Chevron - 10-K annual report

This Annual Report onForm 10-Kof 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,” “budgets” 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 crude oil and natural gas prices; refining margins and marketing margins; chemicals margins; actions of competitors; timing of exploration expenses; the competitiveness of alternate energy sources or product substitutes; technological developments; the results of operations and financial condition of equity affiliates; 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 or delivery/transportation networks due to war, accidents, political events, civil unrest, severe weather or crude-oil production quotas that might be imposed by OPEC (Organization of Petroleum Exporting Countries); the potential liability for remedial actions under existing or future environmental regulations and litigation; significant investment or product changes under existing or future environmental statutes, regulations and litigation; the potential liability resulting from pending or future litigation; the company’s acquisition or disposition of assets; gains and losses from asset dispositions or impairments; government-mandated sales, divestitures, recapitalizations, changes in fiscal terms or restrictions on scope of company operations; foreign currency movements compared with the U.S. dollar; 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” on pages 32 and 33 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, management and technology support to U.S. and international subsidiaries that engage in fully integrated petroleum operations, chemicals operations, mining operations, power generation and energy services. Exploration and production (upstream) operations consist of exploring for, developing and producing crude oil and natural gas and also marketing natural gas. Refining, marketing and transportation (downstream) operations relate to refining crude oil into finished petroleum products; marketing crude oil 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. Chemical operations include the manufacture and marketing of commodity petrochemicals, plastics for industrial uses, and fuel and lubricant oil additives.

On August 10, 2005, the company acquired Unocal Corporation (Unocal), an independent oil and gas exploration and production company. Discussion of the Unocal acquisition is in Note 2 onpage FS-34.

A list of the company’s major subsidiaries is presented on pages E-4and E-5. As of December 31, 2007, Chevron had approximately 65,000 employees (including about 6,000 service station employees). Approximately 31,000, or 48 percent, of the company’s employees were employed in U.S. operations.

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 how companies are structured and 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 generally determined by supply and demand for these commodities. However, some governments impose price controls on refined products such as gasoline or diesel fuel. 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 global economies, although weather patterns and taxation relative to other energy sources also play a significant part. Seasonality is not a primary driver to changes in the company’s quarterly earnings during the year.

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 global petroleum companies, as well as independent and national petroleum companies, for the acquisition of crude oil and natural gas 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 through FS-8 of thisForm 10-Kin Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of 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 has established the following strategies:

The upstream, downstream and chemicals activities of the company and its equity affiliates are widely dispersed geographically, with operations in North America, South America, Europe, Africa, the Middle East, Asia and Australasia. Tabulations of segment sales and other operating revenues, earnings and income taxes for the three years ending December 31, 2007, and assets as of the end of 2007 and 2006 — for the United States and the company’s international geographic areas — are in Note 8 to the Consolidated Financial Statements beginning onpage FS-37.In addition, similar comparative data for the company’s investments in and income from equity affiliates and property, plant and equipment are in Notes 11 and 12 on pages FS-40 to FS-42.

Total reported expenditures for 2007 were $20 billion, including $2.3 billion for Chevron’s share of expenditures by affiliated companies, which did not require cash outlays by the company. In 2006 and 2005, expenditures were $16.6 billion and $11.1 billion, respectively, including the company’s share of affiliates’ expenditures of $1.9 billion and $1.7 billion in the corresponding periods. The 2005 amount excludes $17.3 billion for the acquisition of Unocal.

Of the $20 billion in expenditures for 2007, 78 percent, or $15.5 billion, related to upstream activities. Approximately the same percentage was also expended for upstream operations in 2006 and 2005. International upstream accounted for about 70 percent of the worldwide upstream investment in each of the three years, reflecting the company’s continuing focus on opportunities that are available outside the United States.

In 2008, the company estimates capital and exploratory expenditures will be 15 percent higher at $22.9 billion, including $2.6 billion of spending by affiliates. About three-fourths of the total, or $17.5 billion, is budgeted for exploration and production activities, with $12.7 billion of that amount outside the United States.

Refer also to a discussion of the company’s capital and exploratory expenditures onpage FS-12.

The table on the following page summarizes the net production of liquids and natural gas for 2007 and 2006 by the company and its affiliates.

As shown in the table on page 5, worldwide oil-equivalent production of 2.59 million barrels per day in 2007 was up 34,000 barrels per day from the prior year. Worldwide oil-equivalent production including “other produced volumes” (refer to footnote 5 to the table on page 5) was 2.62 million barrels per day, down about 2 percent from 2006. The decline was mostly attributable to the change in the Boscan operating service agreement in Venezuela to a joint-stock company in October 2006. Refer to the “Results of Operations” section beginning onpage FS-6for a detailed discussion of the factors explaining the 2005–2007 changes in production for crude oil and natural gas liquids and natural gas.

The company estimates that its average worldwide oil-equivalent production in 2008 will be approximately 2.65 million barrels per day. This estimate 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, changes in fiscal terms or restrictions on the scope of company operations, delays in projectstart-ups,and production that may have to be shut in due to weather conditions, civil unrest, changing geopolitics or other disruptions to operations. Future production levels also are affected by the size and number of economic investment opportunities and, for new large-scale projects, the time lag between initial exploration and the beginning of production. Refer to the “Review of Ongoing Exploration and Production Activities in Key Areas,” beginning on page 9, for a discussion of the company’s major oil and gas development projects.

Refer to Table IV onpage FS-66for data about the company’s average sales price per barrel of crude oil and natural gas liquids and per thousand cubic feet of natural gas produced and the average production cost per oil-equivalent barrel for 2007, 2006 and 2005.

The following table summarizes gross and net productive wells at year-end 2007 for the company and its affiliates:

Table V, beginning onpage FS-66,provides a tabulation of the company’s proved net oil and gas reserves, by geographic area, as of each year-end 2004 through 2007, and an accompanying discussion of major changes to proved reserves by geographic area for the three-year period. During 2007, the company provided oil and gas reserves estimates

The net proved-reserve balances at the end of each of the three years 2005 through 2007 are shown in the table below:

At December 31, 2007, 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 obligations. Most contracts generally commit the company to sell quantities based on production from specified properties, but some 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 456 billion cubic feet of natural gas through 2010. 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 631 billion cubic feet of natural gas from 2008 through 2010 from Argentina, Australia, Canada, Colombia, Denmark 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 Argentina, Australia, Colombia, Denmark and the Philippines. The company plans to meet its Canadian contractual delivery commitments of 30 billion cubic feet through third-party purchases.

Details of the company’s development expenditures and costs of proved property acquisitions for 2007, 2006 and 2005 are presented in Table I onpage FS-61.

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, 2007. 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.

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, 2007. “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.

Details of the company’s exploration expenditures and costs of unproved property acquisitions for 2007, 2006 and 2005 are presented in Table I onpage FS-61.

Chevron’s 2007 key upstream activities, some of which are also discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations beginning onpage FS-2,are presented below. The comments include references to “total production” and “net production,” which are defined under “Production” in Exhibit 99.1 onpage E-23.

The discussion that follows 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 or for mature areas of production that do not have individual projects requiring significant levels of capital or exploratory investment. Amounts indicated for project costs represent total project costs, not the company’s share of costs for projects that are less than wholly owned. In addition to the activities discussed, Chevron was active in other geographic areas, but those activities are considered less significant.

Upstream activities in the United States are concentrated in California, the Gulf of Mexico, Louisiana, Texas, New Mexico, the Rocky Mountains and Alaska. Average net oil-equivalent production during 2007 was 743,000 barrels per day, composed of 460,000 barrels of crude oil and natural gas liquids and 1.7 billion cubic feet of natural gas. Refer to Table V beginning onpage FS-66for a discussion of the net proved reserves and different hydrocarbon characteristics for the company’s major U.S. producing areas.

Also under development is the 75 percent-owned and operated Blind Faith discovery, in which the company increased its ownership from 63 percent in July 2007. Three development wells were drilled, and construction of the topsides and hull was completed in 2007. The project includes a subsea development plan, with tieback to a semisubmersible floating production facility that had an original daily-production design capacity of 45,000 barrels of crude oil and 45 million cubic feet of natural gas based on the initial three-well development program. A fourth development well and associated facility upgrades are planned to commence in the first half of 2008. The facility upgrades are planned to increase the daily capacity to 60,000 barrels of crude oil and 60 million cubic feet of natural gas. Initial daily total production, including the fourth well, is estimated at 45,000 to 60,000 barrels of crude oil and 45 million to 60 million cubic feet of natural gas. Proved undeveloped reserves for the project were recognized in 2005. Reclassification of the reserves to the proved developed category is anticipated near the time of productionstart-up in the second quarter 2008. The estimated production life of the field is approximately 20 years.

The company is also participating in the ultra-deep Perdido Regional Development. The project encompasses the installation of a producing host facility to service multiple fields, including Chevron’s 33 percent-owned Great White, 60 percent-owned Silvertip and 58 percent-owned Tobago. Chevron has a 38 percent interest in the Perdido Regional Host. All of these fields and the production facility are partner-operated. Activities during 2007 included facility construction and development drilling. First oil is expected in 2010, with the facility capable of handling 130,000 barrels of oil-equivalent per day. Proved undeveloped reserves related to the project were first recorded in 2006, and the phased reclassification of these reserves to the proved developed category is anticipated near the time of productionstart-up.The project has an expected life of approximately 25 years.

Deepwater exploration activities in 2007 included participation in 12 exploratory wells — six wildcat and six appraisal. Exploratory work included the following:

At the end of 2007, the company had not yet recognized proved reserves for any of the exploration projects discussed above.

Besides the activities connected with the development and exploration projects in the Gulf of Mexico area, Chevron also continued the federal, state and local permitting process during 2007 and early 2008 for a proposed natural gas import terminal at Casotte Landing in Jackson County, Mississippi. In February 2007, the company received approval from the Federal Energy Regulatory Commission for the proposed terminal. The terminal would be located adjacent to the company’s Pascagoula Refinery and designed to process imported liquefied natural gas (LNG) for distribution to industrial, commercial and residential customers in Mississippi, Florida and the Northeast. The terminal would have an initial natural gas processing capacity of 1.3 billion cubic feet per day. The decision to construct a facility will be timed to align with the company’s LNG supply projects.

The company also has contractual rights to 1 billion cubic feet per day of regasification capacity beginning in 2009 at the third party-owned Sabine Pass LNG terminal that is expected to be commissioned in the second quarter 2008. Also in the Sabine Pass area in Louisiana, the company has a binding agreement to be one of the anchor shippers in a 3.2 billion-cubic-foot-per-day third party-owned natural gas pipeline. Chevron will have 1.6 billion cubic feet per day of capacity in the pipeline, of which 1 billion cubic feet per day is in a new pipeline and 600 million cubic feet per day is interconnecting capacity to an existing pipeline. 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 across the mid-continental United States and Alaska. During 2007 in the Piceance Basin of northwestern Colorado, the company commenced development drilling in the basin’s tight-gas formation. Facilities to produce 50 million cubic feet of natural gas per day are expected to start up in 2009. The Piceance project, in which the company holds a 100 percent operated working interest, is scalable, and the work is planned to be completed in multiple phases over the 15- to20-yearproject life. The plans include expanding facilities to a production capacity of 450 million cubic feet per day. The total cost for this project is estimated at $7.3 billion. Also during 2007, Chevron initiated redevelopment programs in three offshore fields in Alaska’s Cook Inlet, where the company operates 10 offshore platforms and five producing natural gas fields. The company also owns nonoperated working interest production and exploratory acreage at the White Hills prospect on the North Slope of Alaska. During 2007, the company’s production outside California and the Gulf of Mexico averaged 308,000 net oil-equivalent barrels per day, composed of 104,000 barrels of crude oil, 1 billion cubic feet of natural gas and 33,000 barrels of natural gas liquids.

Also in Area A, construction continued during 2007 on the Takula Gas Processing Platform and on projects for the Cabinda Gas Plant and the Flare and Relief Modification. These three projects, called the Area A Gas Management projects, are scheduled to start up in 2009 and are expected to eliminate the routine flaring of natural gas by reinjecting excess natural gas into various reservoirs.

In Area B of Block 0, average daily net production in 2007 from six producing fields was 47,000 barrels of crude oil and condensate and 7,000 barrels of LPG. Included in this production were volumes from the Sanha condensate natural gas utilization and Bomboco crude oil project that was completed in mid-2007. During 2007, a portion of the proved undeveloped reserves for this project was reclassified to the proved developed category.

In Block 14, net production in 2007 from the Benguela, Belize, Lobito, Tomboco, Kuito and Landana fields averaged 48,000 barrels of liquids per day. During 2007, development of the Benguela Belize-Lobito Tomboco (BBLT) project continued, with production of first oil at the Benguela and Tomboco fields. Further development drilling is expected to continue at all BBLT fields. Maximum total production for BBLT is estimated at 200,000 barrels of crude oil per day and is scheduled to occur in late 2008 or early 2009. Proved undeveloped reserves for Benguela and Belize were initially recognized in 1998 and for Lobito and Tomboco in 2000. Proved developed reserves for Belize and Lobito were recognized in 2006 and for Benguela and Tomboco in 2007. Additional BBLT reserves are expected to be reclassified to proved developed as project milestones are met. Development and production rights for these fields expire in 2027.

Another major project in Block 14 is the development of the Tombua and Landana fields. Construction of facilities continued in 2007. Production from the Landana North reservoir is utilizing the BBLT infrastructure. The maximum total daily production from Tombua and Landana of 100,000 barrels of crude oil is expected to occur in 2011. Proved undeveloped reserves were recognized for Tombua and Landana in 2001 and 2002, respectively. Initial reclassification from proved undeveloped to proved developed for Landana occurred in 2006 and continued in 2007. Further reclassification is expected between 2009 when theTombua-Landanafacilities are completed and 2012 when the drilling program is scheduled for completion. Development and production rights for these fields expire in 2028.

As of early 2008, the Negage project in Block 14 was under evaluation. Front-end engineering and design (FEED) for this project was expected to begin in late 2008, with the date of productionstart-up yet to be determined.

Three exploration wells were drilled in Block 14 in 2007, one of which successfully appraised the 2006 Lucapa discovery. In the Malange Pinda prospect, one well resulted in a crude-oil discovery, and as of early 2008, evaluation was ongoing for the third well completed in the first quarter 2007. Appraisal drilling of the discoveries is expected to continue in 2008.

Chevron also has a 20 percent interest in a production-sharing contract (PSC) that covers Block 2, which is adjacent to the northwestern part of Angola’s coast south of the Congo River, and a 16 percent interest in the onshore FST area. Combined net production from these properties in 2007 was 3,000 barrels of liquids per day.

Refer also to page 23 for a discussion of affiliate operations in Angola.

Democratic Republic of the Congo: Chevron has an 18 percent nonoperated working interest in a concession for offshore properties. Daily net production from seven fields averaged 3,000 barrels of oil-equivalent in 2007.

Republic of the Congo: Chevron has a 32 percent nonoperated working interest in the Nkossa, Nsoko and Moho-Bilondo exploitation permits and a 29 percent nonoperated working interest in the Kitina and Sounda exploitation permits, all of which are offshore. Net production from the Republic of the Congo fields averaged 8,000 barrels of oil-equivalent per day in 2007. The Moho-Bilondo development continued in 2007, with first production expected in the second half 2008. The development plan calls for crude oil produced by subsea well clusters to flow into a floating processing unit. Maximum total daily production of 90,000 barrels of crude oil is expected in 2010. Proved undeveloped reserves were initially recognized in 2001. Transfer to the proved developed category is expected near the time of first production. Chevron’s development and production rights for Moho-Bilondo expire in 2030.

Two exploration wells were drilled in the Moho-Bilondo permit area during 2007 and were determined to have oil accumulations. As of early 2008, results continued under evaluation.

Angola-Republic of the Congo Joint Development Area: Chevron is the operator and holds a 31 percent interest in the Lianzi Development Area (formerly referenced as the 14K/A-IMI Unitization Zone), located in a joint development area shared equally between Angola and Republic of the Congo. In 2006, the development of the Lianzi area was approved by the committee of representatives from the two countries, and a conceptual field development plan was also submitted to this committee. In early 2007, one additional exploration well was drilled in the Lianzi area, but the results were considered subcommercial. As of early 2008, development studies and planning continued for this area.

Chad/Cameroon: Chevron is a nonoperating partner in a project to develop crude-oil fields in southern Chad and transport the produced volumes by pipeline to the coast of Cameroon for export. Chevron has a 25 percent nonoperated working interest in the producing operations and a 21 percent interest in two affiliates that own the pipeline. Average daily net production from six fields in 2007 was 32,000 barrels of oil-equivalent, including volumes from a satellite field development project in the Maikeri Field that produced first oil in July 2007. In late 2007, a development application was submitted for another satellite field, Timbre, in the Doba area. The Chad producing operations are conducted under a concession agreement that expires in 2030.

Libya: Chevron is the operator and holds a 100 percent interest in the onshore Block 177 exploration license. Evaluation of seismic data was completed in late 2007, and an exploratory drilling program is scheduled for 2008.

During 2007, the company continued development activities of deepwater offshore projects. The 68 percent-owned and operated deepwater Agbami project in OML 127 and OML 128 is a subsea development with wells tied back to a floating production, storage and offloading (FPSO) vessel, which was delivered from South Korea in December 2007. Development drilling and completion operations started in 2006, and subsea installation of production equipment began in 2007. Maximum total daily production of 250,000 barrels of crude oil and natural gas liquids is anticipated within one year afterstart-up,which is expected by the third quarter 2008. The company initially recognized proved undeveloped reserves for Agbami in 2002. A portion of the proved undeveloped reserves is scheduled to be reclassified to proved developed in 2008 near productionstart-up.The expected field life is approximately 20 years. The total cost for this project is estimated at $5.4 billion.

The Aparo Field in OML 132 and OML 140 and the Bonga SW Field in OML 118 share a common geologic structure and are planned to be jointly developed. The geologic structure lies 70 miles offshore in 4,300 feet of water. Apre-unitagreement was executed between Chevron and the OML 118 partner group in 2006. Final terms for a unitization agreement are expected to be completed in mid-2008. In 2007, FEED and tendering of major contracts continued. Development will likely involve an FPSO vessel and subsea wells. Partners are expected to make the final investment decision in the second half 2008, with productionstart-upprojected for 2012. Maximum total production of 150,000 barrels of crude oil per day is expected to be reached within one year of productionstart-up.The company recognized initial proved undeveloped reserves in 2006 for its approximate 20 percent nonoperated working interest in the unitized area. The expected production life of this project is 20 years.

The company holds a 30 percent nonoperated working interest in the Usan project, located offshore in OML 138 and designed to utilize an FPSO vessel. The company recognized proved undeveloped reserves in 2004. Productionstart-up is estimated for late 2011, before which time a portion of proved undeveloped reserves is expected to be reclassified to the proved developed category. Maximum total production of 180,000 barrels of crude oil per day is expected to be achieved within one year ofstart-up.The end date of the concession period will be determined after final regulatory approvals are obtained.

Chevron operates and holds a 95 percent interest in the Nsiko discovery on OML 140. As of early 2008, subsurface evaluations and field development planning were ongoing. An investment decision is contingent on negotiations concerning the level of Nigerian content in the project’s contracts.

The company has a 46 percent nonoperated interest in the Nnwa Field in OML 129, which contains a discovery that extends into two adjacent blocks not owned by Chevron. Commerciality is dependent upon resolution of the Nigerian Deepwater Gas fiscal regime and collaboration agreements with the adjacent blocks. A joint study was initiated in 2007 with owners in adjoining block OML 135 to progress technical and commercial evaluations.

Chevron participated in two deepwater exploration wells during 2007. The Uge 2 well, drilled as an appraisal well to the Uge 1 discovery in Oil Prospecting License (OPL) 214, confirmed hydrocarbons. The company has a 20 percent nonoperated working interest in OPL 214. The second well was deemed noncommercial. Two additional deepwater exploration wells are planned in 2008.

Chevron also is involved in projects in the Niger Delta region that support the company’s strategic initiative to commercialize its significant natural gas resource base outside the United States. Construction is under way on the Phase 3A expansion of the Escravos Gas Plant (EGP), which is expected to start up in 2009. Phase 3A scope includes offshore natural gas gathering and compression infrastructure and a second gas processing facility, which potentially would increase processing capacity from 285 million to 680 million cubic feet of natural gas per day and increase LPG and condensate export capacity from 12,000 to 47,000 barrels per day. EGP Phase 3A is designed to process natural gas from the Meji, Delta South, Okan and Mefa producing fields. Proved undeveloped reserves associated with EGP Phase 3A were recognized in 2002. These reserves are expected to be reclassified to proved developed as various project milestones are reached 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 also to page 26 for a discussion of the planned gas-to-liquids facility at Escravos.

Chevron holds a 37 percent interest in the West African Gas Pipeline, which is designed to supply Nigerian natural gas to customers in Ghana, Benin and Togo for industrial applications and power generation. First gas is anticipated to be shipped by mid-2008, and facility completion, with a capacity of 170 million cubic feet of natural gas per day, is expected in the second-half 2008. Chevron is the managing sponsor in the West African Pipeline Company Limited affiliate, which constructed, owns and operates the412-milepipeline.

In March 2007, Chevron signed a shareholders’ agreement for a 19 percent interest in the OKLNG Free Zone Enterprise (OKLNG) affiliate, which will operate the Olokola LNG project. OKLNG plans to build a multitrain, 22 million-metric-ton-per-year natural gas liquefaction facility and marine terminal located in a free trade zone. The project entered FEED in 2006 and is expected to be implemented in phases, commencing with two trains having at least 11 million-metric-ton-per-year total capacity. Approximately 50 percent of the gas supplied to the plant is expected to be provided from the producing areas associated with Chevron’s joint-venture arrangement with NNPC (discussed earlier in this section).

Nigeria-São Tomé e Príncipe Joint Development Zone (JDZ): Chevron holds a 46 percent operated interest in JDZ Block 1. In 2006, the first exploration well encountered hydrocarbons. In 2008, technical studies are planned to determine the need for additional drilling and evaluate development alternatives.

On Barrow and Thevenard islands off the northwest coast of Australia, Chevron operates crude oil producing facilities that had combined net production of 5,000 barrels per day in 2007. Chevron’s interests in these operations are 57 percent for Barrow and 51 percent for Thevenard.

Also off the northwest coast of Australia, Chevron is the operator of the Gorgon development and has a 50 percent ownership interest across most of the Greater Gorgon Area. Chevron and its two joint-venture participants signed a Framework Agreement in 2005 that will enable the combined development of Gorgon and the nearby natural gas fields as one world-scale project. In 2007, the company received environmental regulatory approvals necessary for the development of the Greater Gorgon LNG project on Barrow Island using a two-train, 10 million-metric-ton-per-year LNG development plan. As of early 2008, the detailed environmental conditions were incorporated into the project’s updated optimization and engineering efforts for a three-train, 15 million-metric-ton-per-year LNG configuration, and activities to secure the necessary government approvals were under way. Natural gas for the project will be supplied from the Gorgon and Jansz fields. The Gorgon project has an expected economic life of at least 40 years.

Elsewhere in the Greater Gorgon Area during 2007, Chevron participated in four successful appraisal wells — two in the Browse Basin and two in the Carnarvon Basin. Chevron also participated in two exploration wells in the Carnarvon Basin, with Lady Nora resulting in a natural gas discovery and Snarf-1 expecting to be completed in 2008. As of early 2008, plans were also being developed to appraise the 67 percent-owned Clio and the 50 percent-owned Chandon natural gas discoveries. Concept studies continued in 2007 on the Wheatstone natural gas discovery, and a successful appraisal well was drilled late in the year. Further appraisal wells are planned to be drilled in the area in 2008.

At the end of 2007, the company had not recognized proved reserves for any of the Greater Gorgon Area fields. Recognition is contingent on securing sufficient LNG sales agreements and achieving other key project milestones. In 2007, the company signed a nonbinding Heads of Agreement (HOA) with GS Caltex, a Chevron affiliated company, to supply 250,000 metric tons of LNG annually from the Gorgon project. Combined with the nonbinding HOAs signed previously with three utility customers in Japan, volumes under the four HOAs totaled 4.5 million metric tons per year. As of early 2008, negotiations were continuing to finalize binding sales agreements on these HOAs. Purchases by each of these customers are expected to range from 300,000 metric tons per year to 1.5 million metric tons per year over 25 years.

Kazakhstan: Chevron holds a 20 percent nonoperated working interest in the Karachaganak project that is being developed in phases. During 2007, Karachaganak net oil-equivalent production averaged 66,000 barrels per day, composed of 41,000 barrels of liquids and 149 million cubic feet of natural gas. In 2007, access to the Caspian Pipeline Consortium (CPC) and Atyrau-Samara (Russia) pipelines allowed Karachaganak sales of approximately 166,000 barrels per day (31,000 net barrels) of processed liquids at prices available in world markets. The remaining liquids were sold into Russian markets. During 2007, work continued on a fourth train that is designed to increase this export of processed liquids by 56,000 barrels per day (11,000 net barrels). The fourth train is expected to start up in 2009.

In 2007, the Karachaganak operator signed a15-yearnatural gas sales agreement to deliver up to 1.6 billion cubic feet per day of sour gas to a Russian-Kazakh joint venture. Deliveries under the agreement commenced in September 2007. As of early 2008, Phase III development of Karachaganak continued under evaluation. The project could increase maximum total production to 335,000 barrels of liquids per day and 1.7 billion cubic feet of natural gas per day. Timing for the recognition of Phase III proved reserves is uncertain and depends on finalizing a viable Phase III project design.

Refer also to pages 23 and 24 for a discussion of Tengizchevroil, a 50 percent-owned affiliate with operations in Kazakhstan.

Russia: Refer to page 24 for a discussion of the company’s interest in a Russian joint venture.

Bangladesh: Chevron is the operator of three onshore blocks, with a 98 percent interest in Blocks 12, 13 and 14 and operator of Block 7, in which the company holds a 43 percent interest. Net oil-equivalent production in 2007 averaged 47,000 barrels per day, composed of 275 million cubic feet of natural gas and 2,000 barrels of liquids. Production from the Bibiyana Field in Block 12 started in March 2007. The project is expected to reach maximum total production of 500 million cubic feet per day by late 2010. The development program included a gas processing plant with capacity of 600 million cubic feet per day and a natural gas pipeline. Initial proved reserves were recognized in 2005. In 2007, additional proved reserves were recognized based on development wells drilled during the year, and a portion of proved undeveloped reserves were reclassified to the proved developed category. Bibiyana operations are conducted under a PSC that expires in 2034.

Thailand: Chevron has operated and nonoperated working interests in several different offshore blocks. The company’s net oil-equivalent production in 2007 averaged 224,000 barrels per day, composed of 71,000 barrels of crude oil and condensate and 916 million cubic feet of natural gas. All of the company’s natural gas production is sold to PTT under long-term sales contracts.

Operated interests are in Pattani and other fields with ownership interests ranging from 35 percent to 80 percent in Blocks 10 through 13, B12/27, B8/32, 9A, G4/43 and G4/48. Blocks B8/32 and 9A produce crude oil and natural gas from six operating areas, and Blocks 10 through 13 and B12/27 produce crude oil, condensate and natural gas from 16 operating areas.

The company’s production of natural gas increased beginning in March 2007 with PTT’s commissioning of a third natural gas pipeline. In October 2007, the leases for Blocks 10 through 13 were extended from 2012 to 2022. In December 2007, the company signed a natural gas sales agreement that will increase daily contract quantity of natural gas from these blocks by 500 million cubic feet, to 1.2 billion, by 2012. In addition, this agreement is expected to enable the construction of a second central natural gas processing facility in the Platong area. The 70 percent-owned Platong Gas II project is designed to add 420 million cubic feet per day of processing capacity in the first quarter 2011. The company expects to recognize proved reserves throughout the project’s12-year life as the wellhead platforms are installed.

Chevron has a 16 percent nonoperated working interest in Blocks 14A, 15A, 16A, G9/48 and G8/50, known collectively as the Arthit Field. First production from Arthit is planned for the second quarter 2008 and is expected to reach an estimated maximum total production of 330 million cubic feet of natural gas per day by the end of 2008. Proved undeveloped reserves were recorded for the first time in 2006. Reclassification of proved undeveloped reserves to the proved developed category is anticipated in 2008, near productionstart-up.The concessions that cover Arthit operations expire in 2040.

In G9/48, one exploration well is required to be drilled by the first quarter 2009. Chevron also holds exploration interests in a number of blocks that are currently inactive, pending resolution of border issues between Thailand and Cambodia.

In late 2007, the company was granted the concession rights to four prospective offshore petroleum blocks in Thailand, which includes Block G8/50 (discussed earlier in this section). Chevron’s interest in the other three operated blocks, G4/50, G6/50 and G7/50, ranges from 35 percent to 75 percent.

Vietnam: The company is operator in two PSCs offshore southwest Vietnam in the northern part of the Malay Basin. Chevron has a 42 percent interest in one PSC that includes Blocks B and 48/95 and a 43 percent interest in the other PSC that has Block 52/97. Chevron also has a 50 percent operated interest in Block B122 offshore eastern Vietnam. No production occurred in these PSCs during 2007.

The Vietnam Gas Project is aimed at developing an area in the two Malay Basin PSCs to supply natural gas to state-owned PetroVietnam. In the third quarter 2007, PetroVietnam approved the revised development plan, joint development area and unitization agreement for the project. The project includes installation of wellhead and hub platforms, an FPSO vessel, infield pipelines and a central processing platform. The timing of first natural gas production is dependent upon the outcome of commercial negotiations. Maximum total production of approximately 500 million cubic feet of natural gas per day is projected within five years ofstart-up.Recognition of initial proved undeveloped reserves would follow execution of the gas sales agreements and project approval. The PSC for Blocks B and 48/95 and the PSC for Block 52/97 will expire in 2022 and 2029, respectively.

In Block 122, a planned seismic program was postponed in 2007 due to issues of territorial claim between Vietnam and China.

China: Chevron has nonoperated working interests of 33 percent in Blocks 16/08 and 16/19 located in the Pearl River Delta Mouth Basin, 25 percent in the QHD-32-6 Field in Bohai Bay and 16 percent in the unitized and producing BZ 25-1Field in Bohai Bay Block 11/19. The company’s net oil-equivalent production in China during 2007 averaged 26,000 barrels per day, composed of 22,000 barrels of crude oil and condensate and 22 million cubic feet of natural gas.

Joint development of the HZ25-3 and HZ25-1 crude-oil fields in Block 16/19 commenced in the first quarter 2007. First production is expected in early 2009, reaching a maximum total daily production of approximately 14,000 barrels of crude oil late in the year. Chevron also has interests ranging from 36 percent to 50 percent in four prospective onshore natural gas blocks in the Ordos Basin totaling about 1.5 million acres. In December 2007, the company signed a30-year PSC that became effective in February 2008 for the development of the Chuandongbei natural gas area in the onshore Sichuan Basin. The aggregate design input capacity of the proposed gas plants is expected to be 740 million cubic feet of natural gas per day. The company holds a 49 percent interest in the area.

Partitioned Neutral Zone (PNZ): Chevron holds a60-yearconcession that expires in 2009 to produce crude oil from onshore properties in PNZ, which is located between Saudi Arabia and Kuwait. Negotiations to extend the concession period were ongoing in early 2008. Net production in PNZ for 2007 represented 4 percent of Chevron’s net barrels of oil-equivalent total.

Under the current concession, Chevron has the right to Saudi Arabia’s 50 percent interest in the hydrocarbon resource and pays a royalty and other taxes on volumes produced. During 2007, average net oil-equivalent production was 112,000 barrels per day, composed of 109,000 barrels of crude oil and 17 million cubic feet of natural gas. The second phase of a steamflood pilot project is expected to be completed in early 2009. This pilot is a unique application of steam injection into a carbonate reservoir and, if successful, could significantly increase recoverability of the heavy oil in place.

Philippines: The company holds a 45 percent nonoperated working interest in the Malampaya natural gas field located 50 miles offshore Palawan Island. Net oil-equivalent production in 2007 averaged 26,000 barrels per day, composed of 126 million cubic feet of natural gas and 5,000 barrels of condensate. Chevron also develops and produces steam resources under an agreement with the National Power Corporation, a Philippine government — owned company. The combined generating capacity is 637 megawatts.

The company’s net oil-equivalent production in 2007 from all of its interests in Indonesia averaged 241,000 barrels per day. The daily oil-equivalent rate comprised 195,000 barrels of crude oil and 277 million cubic feet of natural gas. The largest producing field is Duri, located in the Rokan PSC. Duri has been under steamflood operation since 1985 and is one of the world’s largest steamflood developments. An expansion area, Area 12, is targeted for start-upin late 2008. Maximum total daily production is estimated at 34,000 barrels of crude oil in 2012. Two other areas have been identified for possible sequential expansions. Proved undeveloped reserves for North Duri were recognized in previous years, and reclassification from proved undeveloped to proved developed is scheduled to occur during various stages of sequential completion. The Rokan PSC expires in 2021.

A drilling campaign continued through 2007 in South Natuna Sea Block B, with first oil produced from the Kerisi Field in December 2007. First production of LPG from the Belanak Field was achieved in April 2007. Additional development drilling in the North Belut Field is scheduled to begin in mid-2008, with first production expected in 2009.

In January 2007, Chevron combined the development of the Gendalo and Gehem deepwater natural gas fields located in the Kutei Basin into a single project with one development concept. In August 2007, the company submitted final development plans to the government of Indonesia. Approvals are expected during the first-half 2008. The Bangka natural gas project was under evaluation in 2007 and will likely be developed in parallel with Gendalo and Gehem. The development timing is partially dependent on government approvals, market conditions and the achievement of key project milestones. The company holds an 80 percent operated interest in these projects.

As of early 2008, the development concept for the 50 percent-owned and operated Sadewa project in the Kutei Basin remained under evaluation. Also in the Kutei Basin, the development of the Seturian Field project continued in 2007, with first production anticipated in late 2008. The project is designed to supply natural gas to a state-owned refinery.

The company concentrates its exploration efforts in the Campos and Santos basins. In the partner-operated Campos Basin Block BC-20, two areas — 38 percent-owned Papa-Terra and 30 percent-owned Maromba — have been retained for development following the end of the exploration phase of this block. In 2006, a Papa-Terra field development plan was submitted to the government, and as of early 2008 this plan was still under evaluation. In Maromba as of early 2008, a pilot production system was under consideration, with first oil projected for 2013. Elsewhere in Campos, the company relinquished its 30 percent nonoperated working interest in BM-C-4. In the 20 percent-owned and partner-operated Santos Basin Block BS-4, development options for the Atlanta and Oliva fields were under evaluation.

Colombia: The company operates the offshore Chuchupa and the onshore Ballena and Riohacha natural gas fields as part of the Guajira Association contract. In exchange, Chevron receives 43 percent of the production for the remaining life of each field and a variable production volume from a fixed-fee Build-Operate-Maintain-Transfer agreement based on prior Chuchupa capital contributions. Daily net production averaged 178 million cubic feet of natural gas, or 30,000 barrels of oil-equivalent, in 2007. During the year, new dehydration facilities were constructed that enabled natural gas exports to Venezuela beginning in January 2008.

Trinidad and Tobago: The company has a 50 percent nonoperated working interest in four blocks in the East Coast Marine Area offshore Trinidad, which include the Dolphin and Dolphin Deep producing natural gas fields and the Starfish discovery. Net production from Dolphin and Dolphin Deep in 2007 averaged 174 million cubic feet of natural gas per day, or 29,000 barrels of oil-equivalent.

In May 2007, a domestic natural gas sales agreement was signed for the Trinidad Incremental Gas project. The agreement includes the delivery of 220 million cubic feet per day for 11 years with an option for a four-year extension. Drilling operations started in late 2007 at the Dolphin platform. First gas for the project is expected in 2009, ramping up to maximum total production of 220 million cubic feet of natural gas per day in early 2010. Reserves were initially booked in 2006. In 2007, additional proved reserves were recorded, and some proved undeveloped reserves were reclassified to the proved developed category. Further reclassifications are expected in 2008, following the drilling of additional development wells.

Chevron also holds a 50 percent operated interest in the Manatee area of Block 6d. In early 2007, an agreement was signed by the governments of Venezuela and Trinidad and Tobago to unitize the Loran Field in Venezuela and the Manatee area. Negotiations are expected to continue in 2008 to achieve a field-specific unitization treaty.

Venezuela: Chevron holds interest in two affiliates located in western Venezuela and one affiliate in the Orinoco Belt. The company also operates in two exploratory blocks offshore Plataforma Deltana, with working interests of 60 percent in Block 2 and 100 percent in Block 3. In Block 2, which includes the Loran natural gas field, a conceptual offshore development plan was completed in 2007. In Block 3, Chevron discovered natural gas in 2005 that is in close proximity to Loran. Both Block 3 and Loran will provide a possible supply source for Venezuela’s first LNG train. Seismic work elsewhere in Block 3 was completed in 2007. Chevron also has a 100 percent interest in the Cardon III

Refer also to page 24 for a discussion of affiliate operations in Venezuela.

Canada: The company has nonoperated working interests of 27 percent in the Hibernia Field offshore eastern Canada and 20 percent in the Athabasca Oil Sands Project (AOSP), a 60 percent operated interest in the Ells River “In Situ” Oil Sands Project, a 28 percent operated interest in the Hebron project and exploration acreage in the Mackenzie Delta, Beaufort Sea and the Orphan Basin. Excluding volumes mined at the AOSP, average net oil-equivalent production during 2007 was 36,000 barrels per day, composed of 35,000 barrels of crude oil and natural gas liquids and 5 million cubic feet of natural gas. Substantially all of the production was from the Hibernia Field. At AOSP, bitumen mined and upgraded to synthetic crude oil averaged 27,000 net barrels per day.

At AOSP, the first phase of an expansion project, with an estimated total project cost of $10.2 billion, is being designed to upgrade an additional 100,000 barrels of bitumen into synthetic crude oil per day. The expansion would increase total AOSP design capacity to more than 255,000 barrels of bitumen per day in 2010. Preliminary work is under way to determine the feasibility of additional expansion projects.

The Ells River project consists of heavy oil leases of more than 85,000 acres. The area contains significant volumes with the potential for recovery using Steam Assisted Gravity Drainage, a proven technology that employs steam and horizontal drilling to extract the bitumen through wells rather than through mining operations. During 2007, a successful appraisal drilling program involving 66 wells was completed.Follow-upappraisal activities are planned in 2008, with a similar number of wells and a small2-D and3-D seismic program.

The potential development at Hebron stalled in 2006 after unsuccessful negotiations with the provincial government of Newfoundland and Labrador. In mid-2007, the Hebron partners executed a nonbinding memorandum of understanding with the government that outlined fiscal, equity and local-benefit terms associated with the Hebron project. Execution of formal agreements is expected during 2008.

Exploratory activities are expected to continue during 2008 in the Mackenzie Delta and the Orphan Basin.

Netherlands: Chevron is the operator and holds interests ranging from 34 percent to 80 percent in nine blocks in the Dutch sector of the North Sea. The company’s daily net production from eight producing fields averaged 3,000 barrels of crude oil and 5 million cubic feet of natural gas. Productionstart-up at the first stage of the A/B Gas Project from Block A12 occurred in December 2007 at an initial daily total rate of 60 million cubic feet of natural gas. As of early 2008, the second stage of the project was under evaluation.

Norway: At the 8 percent-owned and partner-operated Draugen Field, the company’s net production during 2007 was 6,000 barrels of oil-equivalent per day. In the 40 percent-owned and partner-operated PL397, seismic survey data was processed in 2007. Acquisition of additional seismic data is planned for 2008. Exploration activities are expected to continue in 2008 in various license areas.

United Kingdom: The company’s average net oil-equivalent production in 2007 from nine offshore fields was 115,000 barrels per day, composed of 78,000 barrels of crude oil and 220 million cubic feet of natural gas. Most of the

As of early 2008, development activities were continuing at the Britannia satellite fields Callanish and Brodgar, in which Chevron holds 17 percent and 25 percent nonoperated working interests, respectively. Productionstart-upfrom these two fields is expected to occur in late 2008. Together, these fields are expected to achieve maximum total daily production of 25,000 barrels of crude oil and 133 million cubic feet of natural gas several months after both fields start up. Proved undeveloped reserves were initially recognized in 2000. In 2006, proved undeveloped reserves were reclassified to the proved developed category. This project has an expected production life of approximately 15 years.

In exploration activities, the Alder discovery west of the Britannia Field was being evaluated in early 2008 and is likely to be developed as a tieback to existing infrastructure. The company has a 70 percent operated interest in the project, which is expected to start up and reach maximum total daily production rates of 9,000 barrels of crude oil and 80 million cubic feet of natural gas in 2012. The timing of the initial proved-reserves recognition was also under evaluation in early 2008. This project has an expected production life of approximately nine years.

At the Rosebank/Lochnagar discovery west of the Shetland Islands, an appraisal program consisting of three wells and a sidetrack was completed in 2007. All four wellbores encountered hydrocarbons, and an evaluation for commerciality was under way in early 2008. Evaluation continued of a successful natural gas production test at the Tormore well that is also in the West of Shetlands gas trend. During 2007, another successful appraisal well was drilled in the Clair Phase 2 area.

Angola: In addition to the exploration and producing activities in Angola, Chevron participates in the Angola LNG project, for which the company and partners made a final investment decision at the end of 2007. The LNG plant will be designed with a capacity to process 1 billion cubic feet of natural gas per day and will provide a commercial option for Angola’s natural gas resources. Chevron has a 36 percent interest in the Angola LNG affiliate. Construction began in early 2008 on the 5.2 million-metric-ton-per-year onshore LNG plant that is located in the northern part of the country. Plantstart-up is expected in 2012. At the end of 2007, the company made an initial booking of proved natural gas reserves for the producing operations associated with this LNG project. The life of the LNG plant is estimated to be in excess of 20 years.

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 a 40-yearconcession that expires in 2033. Chevron’s net oil-equivalent production in 2007 from these fields averaged 176,000 barrels per day, composed of 144,000 barrels of crude oil and natural gas liquids and 193 million cubic feet of natural gas.

TCO is undergoing a significant expansion composed of two integrated projects referred to as the Second Generation Plant (SGP) and Sour Gas Injection (SGI). At a total combined cost of approximately $7.2 billion, these projects are designed to increase TCO’s crude-oil production capacity to 540,000 barrels per day during the second half of 2008.

SGP involves the construction of a large processing train for treating crude oil and the associated sour gas (i.e., high in sulfur content). The SGP design is based on the same conventional technology employed in the existing processing trains. Proved undeveloped reserves associated with SGP were recognized in 2001. Wells were drilled, deepenedand/orcompleted since 2002 in the Tengiz and Korolev reservoirs to produce volumes required for the new SGP train. Reserves associated with the project were reclassified to the proved developed category. 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 sour gas separated from the crude-oil production at the SGP processing train and reinjecting 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, SGI is expected over time to increase production efficiency and recoverable volumes as the injected gas maintains higher reservoir pressure and displaces oil toward producing wells. The company anticipates recognizing additional proved reserves associated with the SGI expansion in late 2008. The primary SGI risks include uncertainties about compressor performance associated with injecting high-pressure sour gas and subsurface responses to injection.

Initial production from the first phase of the SGI/SGP expansion projects occurred in late 2007. This first phase increased production capacity by 90,000 barrels per day, to approximately 400,000, in January 2008.

As of early 2008, essentially all of TCO’s production was being 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. Also in early 2008, CPC was seeking stockholder approval for an expansion to accommodate increased TCO volumes beginning in 2009. Expanded rail-car loading and rail-export facilities, designed to transport most of the incremental SGI/SGP production prior to the CPC expansion, started operation during 2007. As of early 2008, other alternatives were also being explored to increase export capacity.

Venezuela: Chevron has a 30 percent interest in the Hamaca heavy oil production and upgrading project located in Venezuela’s Orinoco Belt, a 39 percent interest in the Petroboscan affiliate that operates the Boscan Field, and a 25 percent interest in the Petroindependiente affiliate that operates the LL-652 Field. The company’s average net oil-equivalent production during 2007 from these affiliates was 72,000 barrels per day, composed of 68,000 barrels of crude oil and 27 million cubic feet of natural gas.

The Hamaca project has a total design capacity for processing and upgrading 190,000 barrels per day of heavy crude oil (8.5 degrees API gravity) into 180,000 barrels of lighter, higher-value crude oil (26 degrees API gravity). In February 2007, the president of Venezuela issued a decree announcing the government’s intention for PDVSA to increase its ownership in all Orinoco Heavy Oil Associations effective May 1, 2007, including Chevron’s 30 percent-owned Hamaca project, to a minimum of 60 percent. In December 2007, Chevron executed a conversion agreement and signed a charter and by-laws with a PDVSA subsidiary that provided for Chevron to retain its 30 percent interest in the Hamaca project. The new entity, Petropiar, commenced activities in January 2008.

The Boscan Field is located onshore western Venezuela. A 3-D seismic program was acquired in 2007 that is expected to guide future development activities in South Boscan. The water-injection pressure-maintenance project was expanded to include four wells converted to injectors in 2007, and four new injectors are planned to be drilled in 2008 and 2009. The LL-652 Field is located in Lake Maracaibo.

Russia: As of early 2008, Chevron and JSC Gazprom Neft continued to negotiate the final agreements for exploration and development activities in two licensed areas in the Yamal-Nenets region of western Siberia. Once the agreement is finalized, Chevron is expected to hold a 49 percent interest in the Northern Taiga Neftegaz LLC affiliate, which will operate in the licensed areas. Exploration and delineation activities are planned for 2008 on both licenses.

The company sells natural gas and natural gas liquids from its producing operations under a variety of contractual arrangements. Outside the United States, substantially all of the natural gas sales are from the company’s producing interests in Australia, Bangladesh, Kazakhstan, Indonesia, Latin America, the Philippines, Thailand and the United Kingdom. Substantially all of the company’s natural gas liquids sales are from company operations in Africa, Australia and Indonesia. Refer to “Selected Operating Data,” onpage FS-10in 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. Refer also to “Contract Obligations” on page 8 for information related to the company’s contractual commitments for the sale of crude oil and natural gas.

At the end of 2007, 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. The daily refinery inputs for 2005 through 2007 for the company and affiliate refineries are as follows:

In the first quarter 2008, the company sold its 4 percent ownership interest in an affiliate that owned a refinery in Abidjan, Côte d’Ivoire, decreasing the company’s share of operable capacity by about 2,000 barrels per day.

Average crude oil distillation capacity utilization during 2007 was 86 percent, compared with 90 percent in 2006. This decrease generally resulted from unplanned downtime to repair damage resulting from fires in the crude units at the Richmond and Pascagoula refineries during 2007. This impact was partially offset by an improvement in capacity utilization at the Pembroke, U.K., refinery, which had unplanned downtime in 2006. The crude unit at the Pascagoula Refinery was back in service in February 2008. Despite the outage at Pascagoula, the company was able to maintain uninterrupted product supplies to customers through the use of other feedstocks in its gasoline-producing facilities at the refinery. At the U.S. fuel refineries, crude oil distillation capacity utilization averaged 85 percent in 2007, compared with 99 percent in 2006, and cracking and coking capacity utilization averaged 78 percent and 86 percent in 2007 and 2006, respectively. Cracking and coking units, including fluid catalytic cracking units, are the primary facilities used in fuel refineries to convert heavier products into gasoline and other light products.

The company’s fuel refineries in the United States, Europe, Canada, South Africa and Australia produce low-sulfur fuels. In 2007, Singapore Refining Company, the company’s 50 percent-owned affiliate, began an upgrade project at its 290,000-barrel-per-day refinery in Singapore to produce diesel fuels that meet Euro IV specifications.

In 2007, the company completed modifications at its refineries in El Segundo, California, to enable the processing of heavier crude oils into gasoline, diesel and other light products, and in the United Kingdom to increase the capability to process Caspian-blend crude oils. In October 2007, the company approved plans to construct a $500 million Continuous Catalyst Regeneration unit at the Pascagoula, Mississippi, refinery, which is expected to increase gasoline production by 10 percent, or 600,000 gallons per day, by mid-2010. Design and engineering for a project to increase the

In late 2007, GS Caltex, the company’s 50 percent-owned affiliate, completed commissioning of new facilities associated with a $1.5 billion upgrade project at the 680,000-barrel-per-day Yeosu refining complex in South Korea. This project is expected to increase the yield of high-value refined products by 33,000 barrels per day, add 15,000 barrels of new lubricant base oil production and reduce feedstock costs through an increase in the refinery’s ability to process heavy oil.

Chevron owns a 5 percent interest in Reliance Petroleum Limited, a company formed by Reliance Industries Limited to own and operate a new export refinery being constructed in Jamnagar, India. The refinery is expected to begin operation by year-end 2008, with a crude-oil capacity of 580,000 barrels per day. Chevron has future rights to increase its equity ownership to 29 percent.

Chevron processes imported and domestic crude oil in its U.S. refining operations. Imported crude oil accounted for about 87 percent of Chevron’s U.S. refinery inputs in 2007 and 2006, respectively.

Through the Sasol Chevron Global50-50 Joint Venture, the company is pursuing gas-to-liquids (GTL) opportunities in several countries.

In Nigeria, Chevron and the Nigerian National Petroleum Corporation are developing a 34,000-barrel-per-day GTL facility at Escravos designed to process natural gas supplied from the Phase 3A expansion of the Escravos Gas Plant (EGP). As of early 2008, approximately 90 percent of engineering and procurement activities had been completed. Chevron has a 75 percent interest in the plant, which is expected to be operational by the end of the decade. Refer also to page 16 for a discussion on the EGP Phase 3A expansion.

The company markets petroleum products throughout much of the world. The principal brands for identifying these products are “Chevron,” “Texaco” and “Caltex.” The table below identifies the company’s and affiliates’ refined products sales volumes, excluding intercompany sales, for the three years ending December 31, 2007.

In the United States, the company markets under the Chevron and Texaco brands. The company supplies directly or through retailers and marketers approximately 9,700 Chevron- and Texaco-branded motor vehicle retail outlets, concentrated in the mid-Atlantic, southern and western states. Approximately 550 of the outlets are company-owned or -leased stations.

Outside the United States, Chevron supplies directly or through retailers and marketers approximately 15,400 branded service stations, including affiliates. In British Columbia, Canada, the company markets under the Chevron brand. In Europe, the company markets primarily in the United Kingdom and Ireland under the Texaco brand. In West Africa, the company operates or leases to retailers in Benin, Cameroon, Côte d’Ivoire, Nigeria, Republic of the Congo and Togo. In these countries, 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 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.

The company continued the marketing and sale of retail fuels networks and individual service station sites, focusing on selected areas outside the United States. In 2007, the company sold its fuels marketing businesses in Belgium, the Netherlands and Luxembourg and its retail fuels business in Uruguay. The company also sold its interest in about 500 individual service station sites, primarily in the United Kingdom and Latin America. Since the beginning of 2003, the company has sold its interests in about 3,300 service station sites. The vast majority of these sites continue to market company-branded gasoline through new supply agreements.

The company also manages other marketing businesses globally. Chevron markets aviation fuel at more than 1,000 airports, representing a worldwide market share of about 11 percent, and is a leading marketer of jet fuels in the United States. The company also markets an extensive line of lubricant and coolant products under brand names that include Havoline, Delo, Ursa, Meropa and Taro.

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.

During 2007, the company led the development of a natural gas gathering pipeline serving the Piceance Basin in northwest Colorado; participated in the successful installation of the55-mileAmberjack-Tahiti lateral pipeline on the seafloor of the U.S. Gulf of Mexico; and completed a pipeline running from the U.S. Gulf of Mexico subsea to the Fourchon Terminal in southern Louisiana. The company is also leading the expansion of the West Texas liquefied natural gas pipeline system that is expected to be operational in late 2008. In addition, the company continued with its project to expand capacity by about 2 billion cubic feet at its Keystone natural gas storage facility, which is expected to be completed in 2009.

Chevron has a 15 percent interest in the Caspian Pipeline Consortium (CPC) affiliate. CPC operates a crude oil export pipeline from the Tengiz Field in Kazakhstan to the Russian Black Sea port of Novorossiysk. During 2007, CPC transported an average of approximately 700,000 barrels of crude oil per day, including 545,000 barrels per day from Kazakhstan and 155,000 barrels per day from Russia. For information related to the possible expansion of the CPC pipeline, refer to page 24.

The company has a 9 percent interest in the Baku-Tbilisi-Ceyhan (BTC) affiliate, whose pipeline transports Azerbaijan International Operating Company (AIOC) (owned 10 percent by Chevron) production from Baku, Azerbaijan, through Georgia to deepwater port facilities in Ceyhan, Turkey. The BTC pipeline has a crude-oil capacity of 1 million barrels per day and transports the majority of the AIOC production. Another crude oil production export route is the Western Route Export Pipeline, wholly owned by AIOC, withcrude-oilcapacity to transport 145,000 barrels per day from Baku, Azerbaijan, to the terminal at Supsa, Georgia.

For information on projects under way related to the West African Gas Pipeline, refer to page 16.

Tankers: At any given time during 2007, the company had approximately 80 vessels chartered on a voyage basis, or for a period of less than one year. Additionally, all tankers in Chevron’s controlled seagoing fleet were utilized during 2007. The following table summarizes cargo transported on the company’s controlled fleet.