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Article by DailyStocks_admin    (08-01-08 05:02 AM)

The Daily Magic Formula Stock for 08/01/2008 is Chevron Corp. According to the Magic Formula Investing Web Site, the ebit yield is 16% and the EBIT ROIC is 25-50 %.

Dailystocks.com only deals with facts, not biased journalism. What is a better way than to go to the SEC Filings? It's not exciting reading, but it makes you money. We cut and paste the important information from SEC filings for you to get started on your research on a specific company.

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(a) General Development of Business

Summary Description of Chevron

Chevron Corporation, 1 a 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 on page FS-34.

A list of the company’s major subsidiaries is presented on pages E-4 and 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.

Overview of Petroleum Industry

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.

Operating Environment

Refer to pages FS-2 through FS-8 of this Form 10-K in 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 Strategic Direction

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:

Strategies for Major Businesses

• Upstream — grow profitably in core areas, build new legacy positions and commercialize the company’s natural gas equity resource base while growing a high-impact global gas business

• Downstream — improve base-business returns and selectively grow, with a focus on integrated value creation

The company also continues to invest in renewable-energy technologies, with an objective of capturing profitable positions in important renewable sources of energy.

Enabling Strategies Companywide

• Invest in people to achieve the company’s strategies

• Leverage technology to deliver superior performance and growth

• Build organizational capability to deliver world-class performance in operational excellence, cost reduction, capital stewardship and profitable growth

(b) Description of Business and Properties

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 on page 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.

Capital and Exploratory Expenditures

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 on page FS-12.

Upstream — Exploration and Production

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 on page FS-6 for 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 project start-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.

Average Sales Prices and Production Costs per Unit of Production

Refer to Table IV on page FS-66 for 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.

Gross and Net Productive Wells


Table V, beginning on page 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 for 2006 to the Department of Energy, Energy Information Administration (EIA), that agree with the 2006 reserve volumes in Table V. This reporting fulfilled the requirement that such estimates are to be consistent with, and do not differ more than 5 percent from, the information furnished to the Securities and Exchange Commission in the company’s 2006 Annual Report on Form 10-K. During 2008, the company will file estimates of oil and gas reserves with the Department of Energy, EIA, consistent with the 2007 reserve data reported in Table V.

Contract Obligations

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.

Development Activities

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

Exploration Activities

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.

Review of Ongoing Exploration and Production Activities in Key Areas

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 on page FS-2, are presented below. The comments include references to “total production” and “net production,” which are defined under “Production” in Exhibit 99.1 on page 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.

Gulf of Mexico: Average net oil-equivalent production during 2007 for the company’s combined interests in the Gulf of Mexico shelf and deepwater areas, and the onshore fields in the region was 214,000 barrels per day. The daily oil-equivalent production comprised 105,000 barrels of crude oil, 576 million cubic feet of natural gas and 13,000 barrels of natural gas liquids.

During 2007, Chevron was engaged in various development and exploration activities in the deepwater Gulf of Mexico. Development work continued at the 58 percent-owned and operated Tahiti Field, where production start-up is expected in the third quarter 2009. Construction of
the spar hull and topsides was completed in 2007; however, installation of the spar hull was delayed for about one year when testing revealed a metallurgical problem with the mooring shackles. Six development wells were drilled in 2007, and flow-back tests for five of the six were completed during the year. Initial booking of proved undeveloped reserves occurred in 2003, and the transfer of these reserves into the proved developed category is anticipated near the time of production start-up. With an estimated production life of 30 years, Tahiti is designed to have a maximum total daily production of 125,000 barrels of crude oil and 70 million cubic feet of natural gas. The total cost for this project is estimated at $4.7 billion and includes a planned second phase of field development after start-up that involves additional wells and facility upgrades.

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 production start-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 production start-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:

• Big Foot — 60 percent-owned and operated. A successful appraisal well was completed in January 2008.

• Jack — 50 percent-owned and operated. A second appraisal well is scheduled for completion in the second quarter 2008.

• Saint Malo — 41 percent-owned and operated. Located near the Jack discovery, a second appraisal well drilled in 2007 is scheduled for completion by the end of the first quarter 2008.

• Tubular Bells — 30 percent-owned and nonoperated working interest. The second appraisal well began drilling in 2007 and is scheduled for completion in the first quarter 2008.

• Knotty Head — 25 percent-owned and nonoperated working interest. Discovered in 2005, subsurface studies were in progress in early 2008.

• Puma — 22 percent-owned and nonoperated working interest. Two appraisal wells were drilled in 2007.

• West Tonga — 21 percent-owned and nonoperated working interest. A successful discovery well was drilled in 2007.

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-da y 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- to 20-year project 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.

Angola: Chevron holds company-operated working interests in Blocks 0 and 14 and nonoperated working interests in Block 2 and the Fina Sonangol Texaco (FST) area. In 2007, daily net production was 179,000 barrels of oil-equivalent.

The 39 percent-owned Block 0 and 31 percent-owned Block 14 are off the west coast, north of the Congo River. In Block 0, the company operates in two areas — A and B — composed of 21 fields that produced 120,000 barrels per day of net liquids in 2007. The Block 0 concession extends through 2030.

Area A of Block 0 comprises 15 producing fields and averaged daily net production of approximately 65,000 barrels of crude oil and 1,000 barrels of liquefied petroleum gas (LPG) in 2007. This production includes volumes from the Banzala Field that produced first oil in June 2007. The development of the Mafumeira Field in Area A continued in 2007 and will target the northern portion of the field. Initial booking of proved
undeveloped reserves for this development occurred in 2003, and reclassification of proved undeveloped reserves into the proved developed category is anticipated near the time of first production expected in 2009. Maximum total daily production is expected to be approximately 30,000 barrels of crude oil in 2011.

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 the Tombua-Landana facilities 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 production start-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.

Nigeria: Chevron holds a 40 percent interest in 13 concessions predominantly in the onshore and near-offshore regions of the Niger Delta and varying interests in deepwater offshore blocks. In the Niger Delta, the company operates under a joint-venture arrangement with the Nigerian National Petroleum Corporation (NNPC), which owns a 60 percent interest. In 2007, net oil- equivalent production from 32 fields averaged 129,000 barrels per day. The daily oil-equivalent rate comprised 126,000 barrels of liquids and 15 million cubic feet of natural gas.

In the Niger Delta, Chevron has a 40 percent operated interest in the South Offshore Water Injection Project (SOWIP), an enhanced crude-oil recovery project in Oil Mining License (OML) 90 aimed at increasing production through water injection, natural-gas lift and production debottlenecking in the Okan and Delta fields. The upgraded Delta South Water Injection Platform (DSWIP), which is part of SOWIP, began water injection in March 2007 at a total daily rate of 100,000 barrels. The total maximum daily water injection rate
is expected to increase to 240,000 barrels in 2009 upon the laying of water injection pipelines. Crude-oil production at year-end 2007 was approximately 5,000 barrels per day, and maximum total production is expected to be 35,000 barrels per day in 2010. Initial recognition of proved reserves was made in 2005. Reclassification of additional proved undeveloped reserves to the developed category is expected to occur after the evaluation of the water injection performance. The estimated life of the project is 25 years.

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 after start-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 production start-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. A pre-unit agreement 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 production start-up projected for 2012. Maximum total production of 150,000 barrels of crude oil per day is expected to be reached within one year of production start-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. Production start-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 of start-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.


Lead Director;
Director since 1982

Mr. Armacost, age 69, has been Chairman of SRI International, formerly Stanford Research Institute, an independent research, technology development and commercialization organization, since 1998. Prior Positions Held: Mr. Armacost was a Managing Director of Weiss, Peck & Greer L.L.C. from 1990 until 1998. He was Managing Director of Merrill Lynch Capital Markets from 1987 until 1990. He was President, Director and Chief Executive Officer of BankAmerica Corporation from 1981 until 1986. Public Company Directorships: Callaway Golf Company; Del Monte Foods Company; Exponent, Inc.; Franklin Resources Inc. Other Directorships and Memberships: Bay Area Council; Bay Area Scientific Infrastructure Consortium.

Director since 2006

Ms. Deily, age 62, was a deputy U.S. Trade Representative and U.S. Ambassador to the World Trade Organization from 2001 to June 2005.
Prior Positions Held: Ms. Deily was Vice-Chairman of Charles Schwab Corporation from 2000 until 2001. She was previously President of the Schwab Retail Group from 1998 until 2000 and President of Schwab Institutional Services for Investment Managers from 1996 until 1998. Prior to joining Schwab, she was Chairman, President and Chief Executive Officer from 1990 until 1996 and President and Chief Operating Officer from 1988 until 1990 of the First Interstate Bank of Texas.
Public Company Directorships: Alcatel-Lucent; Honeywell International Inc.
Other Directorships and Memberships: Greater Houston Partnership; Fulbright Board; Museum of Fine Arts, Houston; Houston Zoo; St. Luke's Hospital, Houston; Houston Endowment.

Director since 2004

Mr. Denham, age 62, has been a Partner of Munger, Tolles & Olson LLP, a law firm, since 1998 and from 1973 to 1991.
Prior Positions Held: Mr. Denham was Chairman and Chief Executive Officer of Salomon Inc. from 1992 until 1997. In 1991, he was General Counsel of Salomon and its subsidiary, Salomon Brothers.
Public Company Directorships: Alcatel-Lucent; Wesco Financial Corporation; Fomento EconĂłmico Mexicano, S.A. de C.V.
Other Directorships and Memberships: Financial Accounting Foundation; MacArthur Foundation.

Director since 2000

Mr. Eaton, age 68, is the retired Chairman of the Board of Management of DaimlerChrysler AG, a manufacturer of automobiles.
Prior Positions Held: Mr. Eaton was the Chairman of the Board of Management of DaimlerChrysler AG from 1998 until 2000. He was Chairman of the Board and Chief Executive Officer of Chrysler Corporation from 1993 until 1998. He was Vice-Chairman and Chief Operating Officer of Chrysler Corporation from 1992 until 1993.
Other Memberships: Fellow, Society of Automotive Engineers; Fellow, Engineering Society of Detroit; National Academy of Engineering.

Director since 1989

Mr. Ginn, age 71, is a private investor and the retired Chairman of Vodafone, a worldwide wireless telecommunications company.

Prior Positions Held: Mr. Ginn was Chairman of Vodafone AirTouch, Plc., from 1999 until 2000 and Chairman of the Board and Chief Executive Officer of AirTouch Communications, Inc., from 1993 until 1999. He was Chairman of the Board, President and Chief Executive Officer of Pacific Telesis Group from 1988 until 1994.
Public Company Directorships: ICO Global Communications (Holdings) Limited.
Other Directorships and Memberships: Auburn University Board of Trustees; Franklin Funds; Hoover Institute Board of Overseers; TVG Capital Partners; Yosemite Fund.

Director since 1993

Dr. Jenifer, age 69, is President Emeritus of the University of Texas at Dallas, a doctoral-level institution.

Prior Positions Held: Dr. Jenifer was President of the University of Texas at Dallas from 1994 until 2005. He was President of Howard University from 1990 to 1994. Prior to that, he was Chancellor of the Massachusetts Board of Regents of Higher Education from 1986 until 1990.

Other Directorships and Memberships: Chairman, Mountainside Hospital, Merit Health Systems, Inc.

Director Nominee

General Jones (retired, United States Marine Corps), age 64, has been President and Chief Executive Officer of the Institute for 21st Century Energy, a policy, economic and educational center in affiliation with the U.S. Chamber of Commerce, since March 2007 and Special Envoy for Middle East Security since November 2007.

Prior Positions Held: General Jones served as the Supreme Allied Commander, Europe, and Commander of the United States European Command, NATO, from January 2003 to February 2007. Previously, General Jones served as the 32nd Commandant of the United States Marine Corps from July 1999 to January 2003.

Public Company Directorships: The Boeing Company; Invacare Corporation.

Other Directorships and Memberships: Director, Cross Match Technologies; Chairman, Atlantic Council of the United States; Center for Strategic and International Studies Board of Trustees; Chairman, Armed Forces Benefits Association; Chairman, Marine Corps Heritage Foundation.

Director since 1997

Senator Nunn, age 69, has been Co-Chairman and Chief Executive Officer of the Nuclear Threat Initiative, a charitable organization, since January 2001.

Prior Positions Held: Senator Nunn was a Partner of King & Spalding, a law firm, from 1997 until 2003. He served as U.S. Senator from Georgia from 1972 until 1996. During his tenure in the U.S. Senate, he served as Chairman of the Senate Armed Services Committee and the Permanent Subcommittee on Investigations. He also served on the Intelligence and Small Business Committees.

Public Company Directorships: The Coca-Cola Company; Dell Inc.; General Electric Company.

Other Directorships and Memberships: Distinguished Professor, Sam Nunn School of International Affairs at Georgia Institute of Technology; Chairman, Center for Strategic and International Studies.

Director since 1998

Mr. O'Reilly, age 61, has been Chairman of the Board and Chief Executive Officer of Chevron since January 2000.

Prior Positions Held: Mr. O'Reilly was Vice-Chairman of the Board of Chevron from 1998 until 1999. He was a Vice-President of Chevron from 1991 until 1998. He was President of Chevron Products Company from 1994 until 1998. He was a Senior Vice-President and Chief Operating Officer of Chevron Chemical Company from 1989 until 1991.

Other Directorships and Memberships: American Petroleum Institute; Eisenhower Fellowships Board of Trustees; Peterson Institute for International Economics; the Business Council; the Business Roundtable; JPMorgan International Council; World Economic Forum's International Business Council; the National Petroleum Council; the American Society of Corporate Executives; the King Fahd University of Petroleum and Minerals International Advisory Board.

Director since 2005

Dr. Rice, age 68, served from 2002 through 2007 as Chairman of the Board and, since 1996, as President and Chief Executive Officer of Agensys, Inc., a private biotechnology company (since December 2007, an operating subsidiary of Astellas Pharma, Inc.).

Prior Positions Held: Dr. Rice was President and Chief Operating Officer of Teledyne, Inc., from 1993 until 1996. He was Secretary of the Air Force from 1989 until 1993. He was President and Chief Executive Officer of the RAND Corporation from 1972 until 1989.

Public Company Directorships: Vulcan Materials Co.; Wells Fargo & Company.

Other Directorships and Memberships: RAND Corporation Board of Trustees; Chairman, Pardee RAND Graduate School Board of Governors.

Director since 2002

Mr. Robertson, age 61, has been Vice-Chairman of the Board of Chevron since 2002.

Prior Positions Held: Mr. Robertson was Vice-President of Chevron from 1994 until 2001. He was President of Chevron Overseas Petroleum Inc. from 2000 until 2001. He was the Vice-President responsible for Chevron's North American exploration and production operations from 1997 until 2000. From 1994 until 1997, he was the Vice-President responsible for strategic planning.

Other Directorships and Memberships: Chairman, U.S. Energy Association; Director, U.S.–Saudi Arabian Business Council; U.S.-Russia Business Council; American Petroleum Institute; International House at Berkeley; United Way of the San Francisco Bay Area; Vice-Chairman, Leon H. Sullivan Foundation; Director of Global Business Coalition Against AIDS; Resources for the Future; Bay Area Council; World Affairs Council.

Director since 2007

Mr. Sharer, age 60, has been, since January 2001, Chairman of the Board and, since May 2000, Chief Executive Officer and President of Amgen Inc., a biotechnology company.

Prior Positions Held: From October 1992 to May 2000, Mr. Sharer served as President and Chief Operating Officer of Amgen. From April 1989 to October 1992, Mr. Sharer was President of the Business Markets Division of MCI Communications Corporation. From February 1984 to March 1989, Mr. Sharer served in numerous executive capacities at General Electric Company.

Public Company Directorships: Amgen Inc.; Northrop Grumman Corporation.

Other Directorships and Memberships: University of Southern California Board of Trustees; Los Angeles County Museum of Natural History.

Director since 1998

Mr. Shoemate, age 68, is the retired Chairman, President and Chief Executive Officer of Bestfoods, a manufacturer of food products.

Prior Positions Held: Mr. Shoemate was Chairman of the Board and Chief Executive Officer of Bestfoods, formerly CPC International, from 1990 until 2000. He was elected President and a member of the Board of Directors of Bestfoods in 1988.

Director since 2005

Dr. Sugar, age 59, has been Chairman of the Board and Chief Executive Officer of Northrop Grumman Corporation, a global defense company, since 2003.

Prior Positions Held: Dr. Sugar was President and Chief Operating Officer of Northrop Grumman Corporation from 2001 until 2003. He was President and Chief Operating Officer of Litton Industries, Inc., from 2000 until 2001. He was previously President and Chief Operating Officer of TRW Aerospace and Information Systems.

Public Company Directorships: Northrop Grumman Corporation.

Other Directorships and Memberships: Aerospace Industries Association; Boys & Girls Clubs of America; Los Angeles Philharmonic Association; National Academy of Engineering; Pearl Harbor Memorial Fund; Royal Aeronautical Society; University of Southern California Board of Trustees.

Director since 2001

Mr. Ware, age 64, is a retired Executive Vice-President of The Coca-Cola Company, a manufacturer of beverages.

Prior Positions Held: Mr. Ware was a Senior Advisor to the CEO of The Coca-Cola Company from 2003 until 2005 and was an Executive Vice-President, Global Public Affairs and Administration, from 2000 until 2003. He was President of The Coca-Cola Company's Africa Group, with operational responsibility for 50 countries in sub-Saharan Africa from 1991 until 2000.

Public Company Directorships: Coca-Cola Bottling Co. Consolidated; Cummins Inc.

Other Directorships and Memberships: Atlanta Falcons; Clark Atlanta University Board of Trustees; PGA TOUR Golf Course Properties, Inc.


First Quarter 2008 Compared with First Quarter 2007

Key Financial Results

Net income for the 2008 first quarter was $5.2 billion ($2.48 per share — diluted), compared with $4.7 billion ($2.18 per share — diluted) in the corresponding 2007 period. In the following discussions, the term “earnings” is defined as segment income.

Upstream earnings in the first quarter of 2008 were $5.1 billion, compared with $2.9 billion in the year-ago period. The increase between periods was largely the result of higher prices for crude oil.

Downstream earnings were $252 million in the first quarter of 2008, down about $1.4 billion from a year earlier. Half of the decline was associated with a $700 million gain recorded in the 2007 first quarter on the sale of assets in the Netherlands. The decline in income otherwise was due mainly to market conditions in 2008 preventing the higher price of crude-oil feedstocks from being fully recovered in the sales price of gasoline and other refined products.

Chemicals earned $43 million in the first quarter of 2008, down $77 million from a year earlier due mainly to environmental remediation costs at a closed manufacturing site and higher feedstock costs.

Refer to pages 25 through 27 for additional discussion of earnings by business segment and “All Other” activities for the first quarter of 2008 vs. the same period in 2007.

Business Environment and Outlook

Chevron is a global energy company with its most significant business activities in the following countries: Angola, Argentina, Australia, Azerbaijan, Bangladesh, Brazil, Cambodia, Canada, Chad, China, Colombia, Democratic Republic of the Congo, Denmark, France, India, Indonesia, Kazakhstan, Myanmar, the Netherlands, Nigeria, Norway, the Partitioned Neutral Zone between Kuwait and Saudi Arabia, the Philippines, Qatar, Republic of the Congo, Singapore, South Africa, South Korea, Thailand, Trinidad and Tobago, the United Kingdom, the United States, Venezuela and Vietnam.

Chevron’s current and future earnings depend largely on the profitability of its upstream (exploration and production) and downstream (refining, marketing and transportation) business segments. The single biggest factor that affects the results of operations for both segments is movement in the price of crude oil. In the downstream business, crude oil is the largest cost component of refined products. The overall trend in earnings is typically less affected by results from the company’s chemicals business and other activities and investments. Earnings for the company in any period may also be influenced by events or transactions that are infrequent and/or unusual in nature.

Chevron and the oil and gas industry at large continue to experience an increase in certain costs that exceeds the general trend of inflation in many areas of the world. This increase in costs is affecting the company’s operating expenses for all business segments and capital expenditures, but particularly for the upstream business. The company’s operations, particularly upstream, can also be affected by changing economic, regulatory and political environments in the various countries in which it operates, including the United States. Civil unrest, acts of violence or strained relations between a government and the company or other governments may impact the company’s operations or investments. 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.

To sustain its long-term competitive position in the upstream business, the company must develop and replenish an inventory of projects that offer adequate financial returns for the investment required. Identifying promising areas for exploration, acquiring the necessary rights to explore for and to produce crude oil and natural gas, drilling successfully, and handling the many technical and operational details in a safe and cost-effective manner, are all important factors in this effort. Projects often require long lead times and large capital commitments. In the current environment of higher commodity prices, certain governments have sought to renegotiate contracts or impose additional costs and taxes on the company. Other governments may attempt to do so in the future. The company will continue to monitor these developments, take them into account in evaluating future investment opportunities, and otherwise seek to mitigate any risks to the company’s current operations or future prospects.

The company also continually evaluates opportunities to dispose of assets that are not key to providing sufficient long-term value, or to acquire assets or operations complementary to its asset base to help augment the company’s growth. Asset dispositions and restructurings may occur in future periods and could result in significant gains or losses.

Comments related to earnings trends for the company’s major business areas are as follows:

Upstream Earnings for the upstream segment are closely aligned with industry price levels for crude oil and natural gas. Crude-oil and natural-gas prices are subject to external factors over which the company has no control, including product demand connected with global economic conditions, industry inventory levels, production quotas imposed by the Organization of Petroleum Exporting Countries (OPEC), weather-related damage and disruptions, competing fuel prices, and regional supply interruptions or fears thereof that may be caused by military conflicts, civil unrest or political uncertainty. Moreover, any of these factors could also inhibit the company’s production capacity in an affected region. The company monitors developments closely in the countries in which it operates and holds investments, and attempts to manage risks in operating its facilities and business.

Price levels for capital and exploratory costs and operating expenses associated with the efficient production of crude-oil and natural-gas can also be subject to external factors beyond the company’s control. External factors include not only the general level of inflation but also prices charged by the industry’s material- and service-providers, which can be affected by the volatility of the industry’s own supply and demand conditions for such materials and services. The oil and gas industry worldwide has experienced significant price increases for these items since 2005, and future price increases may continue to exceed the general level of inflation. Capital and exploratory expenditures and operating expenses also can be affected by damages to production facilities caused by severe weather or civil unrest.

During 2007, industry price levels for West Texas Intermediate (WTI), a benchmark crude oil, averaged $72 per barrel. The price for WTI averaged $98 per barrel for the first quarter of 2008 and was about $115 per barrel at the end of April. Worldwide crude oil prices have remained strong due mainly to increasing demand in growing economies, the heightened level of geopolitical uncertainty in some areas of the world and supply concerns in other key producing regions.

As in 2007, a wide differential in prices existed during the first quarter of 2008 between high-quality (high-gravity, low sulfur) crude oils and those of lower quality (low-gravity, heavier types of crude). The price for the heavier crudes has been dampened because of ample supply and lower relative demand due to the limited number of refineries that are able to process this lower-quality feedstock into light products (motor gasoline, jet fuel, aviation gasoline and diesel fuel). The price for higher-quality crude oil has remained high, as the demand for light products, which can be more easily manufactured by refineries from high-quality crude oil, has been strong worldwide. Chevron produces or shares in the production of heavy crude oil in California, Chad, Indonesia, the Partitioned Neutral Zone between Saudi Arabia and Kuwait, Venezuela and in certain fields in Angola, China and the United Kingdom North Sea. (Refer to page 30 for the company’s average U.S. and international crude-oil realizations.)

In contrast to price movements in the global market for crude oil, price changes for natural gas in many regional markets are more closely aligned with supply and demand conditions in those markets. In the United States, benchmark prices at Henry Hub averaged about $8.60 per thousand cubic feet (MCF) in the first quarter of 2008, compared with $7.20 for the first quarter of 2007 and about $7 for the full year. At the end of April 2008, the Henry Hub spot price was approximately $11 per MCF. Fluctuations in the price for natural gas in the United States are closely associated with the volumes produced in North America and the inventory in underground storage relative to customer demand. U.S. natural gas prices are also typically higher during the winter period when demand for heating is greatest.

Certain other regions of the world in which the company operates have different supply, demand and regulatory circumstances, typically resulting in significantly lower average sales prices for the company’s production of natural gas. (Refer to page 30 for the company’s average natural gas realizations for the U.S. and international regions.) Additionally, excess-supply conditions that exist in certain parts of the world cannot easily serve to mitigate the relatively high-price conditions in the United States and other markets because of the lack of infrastructure to transport and receive liquefied natural gas.

To help address this regional imbalance between supply and demand for natural gas, Chevron is planning increased investments in long-term projects in areas of excess supply to install infrastructure to produce and liquefy natural gas for transport by tanker, along with investments and commitments to regasify the product in markets where demand is strong and supplies are not as plentiful. Due to the significance of the overall investment in these long-term projects, the natural-gas sales prices in the areas of excess supply (before the natural gas is transferred to a company-owned or third-party processing facility) are expected to remain well below sales prices for natural gas that is produced much nearer to areas of high demand and can be transported in existing natural gas pipeline networks (as in the United States).

Besides the impact of the fluctuation in price for crude oil and natural gas, the longer-term trend in earnings for the upstream segment is also a function of other factors, including the company’s ability to find or acquire and efficiently produce crude-oil and natural-gas, changes in fiscal terms of contracts, changes in tax rates on income, and the cost of goods and services.

In the first quarter of 2008, the company’s worldwide oil-equivalent production averaged approximately 2.6 million barrels per day. At the beginning of 2008, the company estimated production for the full year at 2.65 million barrels per day under a set of crude-oil and natural-gas price assumptions for the year. Actual crude-oil prices in the 2008 first quarter were higher than the prices used in the production forecast, and the impact of these higher prices reduced the anticipated volumes recoverable under certain production-sharing and variable-royalty agreements outside the United States. This difference in recovered volumes essentially accounted for the variation between the first quarter’s actual reported rate of production and the full-year forecast. The full-year production outlook is also subject to other factors and many uncertainties, including quotas that may be imposed by OPEC, changes in fiscal terms or restrictions on the scope of company operations, delays in project start-ups, and production disruptions that could be caused by severe weather, local civil unrest and changing geopolitics. 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. A significant majority of Chevron’s upstream investment is currently being made outside the United States. Investments in upstream projects generally are made well in advance of the start of the associated crude-oil and natural-gas production.

Approximately 27 percent of the company’s net oil-equivalent production in the first quarter of 2008 occurred in the OPEC-member countries of Angola, Indonesia, Nigeria and Venezuela and in the Partitioned Neutral Zone between Saudi Arabia and Kuwait. OPEC quotas did not significantly affect Chevron’s production level in 2007 or in the first quarter of 2008. The impact of quotas on the company’s production in future periods is uncertain.

Refer to the Results of Operations on page 25 for additional discussion of the company’s upstream business.

Downstream Earnings for the downstream segment are closely tied to margins on the refining and marketing of products that include gasoline, diesel, jet fuel, lubricants, fuel oil and feedstocks for chemical manufacturing. Industry margins are sometimes volatile and can be affected by the global and regional supply-and-demand balance for refined products and by changes in the price of crude oil used for refinery feedstock. Industry margins can also be influenced by refined-product inventory levels, geopolitical events, refinery maintenance programs and disruptions at refineries resulting from unplanned outages that may be due to severe weather, fires or other operational events.

Other factors affecting profitability for downstream operations include the reliability and efficiency of the company’s refining and marketing network, the effectiveness of the crude-oil and product-supply functions and the economic returns on invested capital. Profitability can also be affected by the volatility of tanker-charter rates for the company’s shipping operations, which are driven by the industry’s demand for crude-oil and product tankers. Other factors beyond the company’s control include the general level of inflation and energy costs to operate the company’s refinery and distribution network.

The company’s most significant marketing areas are the West Coast of North America, the U.S. Gulf Coast, Latin America, Asia, sub-Saharan Africa and the United Kingdom. Chevron operates or has ownership interests in refineries in each of these areas, except Latin America. Downstream earnings, especially in the United States, have been weak since mid-2007 due mainly to increasing prices of crude oil that have not always been fully recovered through sales prices of refined products.

Refer to the Results of Operations on page 26 for additional discussion of the company’s downstream operations.

Chemicals Earnings in the petrochemicals business are closely tied to global chemical demand, industry inventory levels and plant capacity utilization. Feedstock and fuel costs, which tend to follow crude-oil and natural-gas price movements, also influence earnings in this segment.

Refer to the Results of Operations on page 26 for additional discussion of chemical earnings.

Operating Developments

Noteworthy operating developments and events in recent months included the following:

• Republic of the Congo — Confirmed start-up ahead of schedule of the 31 percent owned, partner-operated Moho Bilondo deepwater project, which is expected to reach maximum total crude-oil production of 90,000 barrels per day in 2010.

• Thailand — Approved construction in the Gulf of Thailand of the 70 percent-owned and operated Platong Gas II project, which is designed to have processing capacity of 420 million cubic feet of natural gas per day.

• Australia — Announced plans to develop a new liquefied natural gas project associated with Chevron’s 100 percent-owned Wheatstone natural gas discovery.

• Nigeria — Confirmed that the company and its partners plan to develop the 30 percent-owned and partner-operated offshore Usan Field, which is expected to have maximum total production of 180,000 barrels of crude oil per day within one year of start-up in late 2011.

Results of Operations

Business Segments The following section presents the results of operations for the company’s business segments — upstream, downstream and chemicals — as well as for “all other” — the departments and companies managed at the corporate level. (Refer to Note 3 beginning on page 8 for a discussion of the company’s “reportable segments,” as defined in FAS 131, Disclosures about Segments of an Enterprise and Related Information. )

U.S. Upstream Income
$ 1,599 $ 796

U.S. upstream income of $1.60 billion doubled from the first quarter of 2007, primarily due to higher prices of crude oil. Prices for natural gas also increased between periods. Partially offsetting the benefit of higher prices were increases in depreciation and operating expenses and the impact of lower production.

The average liquids realization in 2008 was $86.63 per barrel, up more than 70 percent from $49.91 a year earlier. The average natural gas realization was $7.55 per thousand cubic feet, compared with $6.40 in the 2007 quarter.

Net oil-equivalent production of 715,000 barrels per day in the 2008 quarter declined 34,000 barrels per day from the 2007 first quarter due mainly to normal field declines. The net liquids component of production was down about 5 percent to 437,000 barrels per day. Net natural gas production of 1.67 billion cubic feet per day in the first quarter of 2008 declined 3 percent between periods.

International upstream income of $3.53 billion in the first quarter of 2008 increased $1.42 billion from a year earlier, due mainly to higher prices for crude oil. Prices and sales volumes of natural gas were also higher between periods. Partially offsetting these benefits were higher operating expenses and lower crude-oil sales volumes associated with the timing of cargo liftings in certain producing regions.

The average liquids realization for the first quarter of 2008 was $86.13 per barrel, about a 70 percent increase from $51.15 in the 2007 period. The average natural gas realization in 2008 was $4.83 per thousand cubic feet, an increase of 25 percent from $3.85 in the first quarter last year.


Steve J. Crowe

Thanks, Matt. Welcome to Chevron's first quarter earnings conference call and webcast. Jim Aleveras, General Manager of Investor Relations is on the call with me today. Our focus is on Chevron's financial and operating results for the first quarter of 2008. We will refer to the slides that are available on the web.

Before we get started, please be reminded that this presentation contains estimates, projections, and other forward-looking statements. We ask that you review the cautionary statement on slide 2.

I’ll begin with slide 3, which provides an overview of our financial performance. The company’s first quarter earnings were $5.2 billion, or $2.48 per diluted share. Our first quarter 2008 earnings were up nearly 10% from the first quarter 2007, reflecting higher crude oil and natural gas prices, which more than offset weaker downstream results.

The first quarter of last year included a $700 million gain on the sale of our interest in a refinery in The Netherlands.

First quarter 2008 earnings rose 6% compared to the fourth quarter 2007, which Jim will discuss shortly.

Return on capital employed for the trailing 12 months was 23%. The debt ratio was about 8% at the end of the quarter. As we announced Wednesday, we increased our quarterly dividend by $0.07 per share, or 12.1%. This marks the fourth consecutive year we’ve raised the second quarter dividend by a double-digit amount.

Stock buy-backs were $2 billion in the quarter.

Jim will now take us through the quarterly comparisons. Jim.

Jim Aleveras

Thanks, Steve. My remarks compare results of the first quarter 2008 with the fourth quarter 2007. As a reminder, our earnings release compared the first quarter 2008 with the same quarter a year ago.

Turning to slide 4, first quarter net income was almost $300 million higher than the fourth quarter. Starting with the left side of the chart, higher crude oil and natural gas realizations benefited the company’s worldwide upstream results. Partly offsetting this was the impact of lower upstream volumes. The largest component here was international liftings. Liftings were lower than production in the first quarter.

Downstream results were up slightly from the fourth quarter, reflecting improved refinery operations in the United States. The variance in the residual other bar is the net of everything else.

Slide 5 summarizes the results of our U.S. upstream operations, which improved by about $220 million between quarters. Higher crude oil and natural gas realizations benefited earnings by $335 million. Chevron's average U.S. crude oil realization was up about $8 per barrel between consecutive quarters. This is more than the $7.25 per barrel increase in WTI’s spot prices, since much of our Gulf of Mexico crude oil production is priced on a lagged basis.

Production volumes were down 2% between quarters, largely due to operational and weather related downtime, as well as normal fuel declines. This impact reduced earnings by $85 million.

The $85 million DD&A reflects higher rates and higher accretion charges for abandonment. Exploration expense fell $90 million between periods. The primary factor was lower well write-offs in the first quarter.

The other bar reflects miscellaneous gas marketing and income tax items.

Let’s turn to slide 6. International upstream earnings for the first quarter were about $70 million higher than the fourth quarter’s results. Higher oil and gas prices increased earnings by $370 million. Our unit realization for liquids rose by $5.70 per barrel, significantly less than the $9.30 per barrel increase in brent spot prices.

Comparing average prices for the first and fourth quarters, we found that worldwide benchmark crudes did not move consistently. For example, Malaysia’s light sweet tapas crude was up $3.20 per barrel between quarter and Sumatra Light rose $7.70 per barrel. WTI’s spot prices increased $7.25 per barrel, $2 less than the change in brent.

Our realizations therefore reflected geographic market prices which were not in line with brent movements during this particular comparison period.

Lower first quarter liftings, particularly in Azerbaijan, the U.K., Nigeria, and Australia, reduced earnings by $195 million. As I noted earlier, we were under-lifted in the first quarter, an issue we referenced in the interim update.

Partially offsetting this under-lift is a one-time benefit from the retroactive effect of the unitization agreement in Indonesia we also mentioned in the interim update.

Tax items reduced earnings by $230 million between quarters. These were spread among several countries and included the absence of favorable fourth quarter items we discussed on our last conference call.

Operating expense was down $130 million from the fourth quarter due to lower seasonal activity levels in several international areas. The other bar reflects the net of many unrelated items. The largest components were adverse foreign exchange effects, offset by lower exploration expense.

Slide 7 summarizes the change in worldwide oil equivalent production, including volumes produced from oil sands in Canada. Production fell by 14,000 barrels per day, or about half of 1% between consecutive quarters. United States production fell 15,000 barrels per day, about 2% due to operational down time and normal field declines.

Outside the United States, overall production was flat between quarters. Kazakhstan benefited from the ramp-up of staged oil from the TCO expansion project. Offsetting this were reduced entitlements in Azerbaijan.

Comparing the fourth and first quarters, the increase in international liquids realizations reduced our volumes by about 25,000 barrels per day, due to cost recovery and variable royalty provisions of certain production contracts. As we noted at our March analyst meeting in New York City, each contract is different and there are non-linear points when certain thresholds are reached.

Looking at our 2008 production guidance, our general rule of thumb is unchanged. A $1 per barrel increase in crude oil prices will reduce our production entitlement by roughly 2,000 barrels per day. We caution that this is only an estimate and results will vary, especially for individual quarterly comparisons.

In the context of our production, I would like to briefly summarize our upstream project status. As we discussed at our March meeting, the Tengiz expansion is on track with the first phase of staged oil meeting all of its targets and full facility start-up on schedule for the third quarter of this year.

First oil at Blind Faith, our Gulf of Mexico project, forecasted for the late second quarter is now projected to occur in the second half of 2008 due to an issue with the mooring lines. The exact timing of startup is dependent on weather in the Gulf.

As we mentioned at the March meeting, a fourth well was added to the initial development plan for Blind Faith. The acceleration of the fourth well reflects higher than anticipated reservoir quality. This well has now been drilled, completed, and is ready for production at the time of facility startup later this year.

As indicated in March, gross peak production for Blind Faith is now expected to be 70,000 barrels of oil equivalent per day.

Also in March, we said we expected first oil from Moho Bilondo offshore of the Republic of Congo in the second half of this year. This project has now started up ahead of schedule.

In Nigeria, we expect our Agbami project to remain on track for a third quarter start-up.

Overall, our upstream projects are moving forward. While we will provide an update later in the year, we are optimistic that when adjusted for price effects, our 2008 production will be on track with the guidance we provided in march that was based on $70 oil prices.

Let’s turn to slide 8 -- our U.S. downstream operations moved from a loss position in the fourth quarter to break-even results in the first quarter. Industry refining and marketing indicator margins on the west coast weakened in the first quarter. Although refining margins improved somewhat on the Gulf Coast, marketing margins declined. On balance, especially given Chevron's west coast weighting, industry margins were an adverse $55 million impact between quarters.

With the completion of our El Segundo refinery upgrade project at the end of 2007, the coker was back in operation and we were able to run heavier crudes. That helped to improve first quarter results by roughly $100 million. The swing in timing effects, such as the impact of provisionally priced foreign crudes, was $50 million better in the first quarter, since crude prices did not rise as much from the beginning to the end of the first quarter as they did in the fourth quarter.

Sales of motor gasoline and jet fuel were down by 2% and 3% respectively. While diesel fuel sales strengthened between quarters, lower first quarter volumes resulted in an adverse impact of $50 million.

Turning to slide 9, international downstream earnings fell about $10 million from the fourth quarter’s results. Refining indicator margins were lower while marketing margins were mixed across our international geographic areas. On balance, margins reduced earnings by about $30 million between quarters.

Volumetric effects were a $70 million adverse variance. This reflected planned shutdowns at refineries in Canada, South Africa, Singapore, and South Korea. Additionally, marketing volumes were affected by seasonal factors in Asia and Africa.

Higher charter rates resulted in a $70 million increase in international shipping earnings. The $19 million benefit in the other bar is the net of many items, including adverse tax effects and favorable OpEx variance.

Slide 10 shows that earnings from chemical operations were $43 million in the first quarter compared with $69 million in the fourth quarter. Results for olefins improved on higher margins and volumes, especially for polyethylene. Aromatics were essentially unchanged as volumes and margins were mixed.

Included in the other bar here is an approximately $40 million environmental provision we mentioned in the interim update, as well as the absence of favorable tax items we discussed on last quarter’s conference call.

Slide 11 covers all other. First quarter results were net charges of $255 million compared to net charges of $237 million in the fourth quarter. Corporate tax adjustments had a $100 million adverse impact between quarters. Corporate charges shown were a favorable variance of $85 million. This largely reflects lower advertising and employee related expense.

As we mentioned in the interim update, our current guidance for all other activities is a charge of $250 million to $300 million. Because of irregularly occurring accruals and other charges that affect corporate and other activities, we continue to expect volatility in this area and the possibility that actual results will lie outside the guidance range.

That completes our brief analysis of the quarter. Back over to you, Steve.

Steve J. Crowe

Thanks, Jim. And now a brief recap of our strategic progress in recent months. Please turn to slide 12. Jim touched on the Moho Bilondo deepwater project in the Republic of the Congo. We confirmed start-up ahead of schedule of this 31% owned partner operated project. It is expected to reach maximum total crude oil production of 90,000 barrels per day in 2010.

With our partners, we made the final investment decision to construct Platong Gas II natural gas project in Thailand. The $3.1 billion project will add 420 million cubic feet a day of processing capacity. Chevron is the operator and holds a 70% interest. Start-up is anticipated in 2011.

We began front-end engineering and design work to develop an LNG project at our 100% owned Wheatstone discovery in Australia. We estimate that Wheatstone holds 4.5 trillion cubic feet of natural gas resource.

In Nigeria, along with our partners, we made the final investment decision to develop the deepwater Usan Field. Chevron Nigeria Limited holds a 30% interest in this partner operated project. Usan is expected to have first production in late 2011 with peak production of 180,000 barrels of oil per day.

Finally, as I mentioned, earlier in the week our board approved a 12% increase in the quarterly dividend. We’ve raised our quarterly dividend by a double-digit amount in each of the last four years and our shareholders have benefited from 21 consecutive years of higher annual dividend payouts.

That concludes our prepared remarks. We will now take your questions, one question and one follow-up per caller, please. Matt, please open the lines for questions. Thanks.

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