Chevron - 10-K annual report

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2008

OR

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

SECURITIES EXCHANGE ACT OF 1934

For the transition period from          to          

 

Commission File Number 1-368-2

(Exact name of registrant as specified in its charter)

 

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

 

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

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

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” inRule 12b-2of the Exchange Act. (Check one):

 

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

 

Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter — $203,659,751,369 (As of June 30, 2008)

Number of Shares of Common Stock outstanding as of February 20, 2009 — 2,004,559,279

 

DOCUMENTS INCORPORATED BY REFERENCE

(To The Extent Indicated Herein)

 

Notice of the 2009 Annual Meeting and 2009 Proxy Statement, to be filed pursuant toRule 14a-6(b)under the Securities Exchange Act of 1934, in connection with the company’s 2009 Annual Meeting of Stockholders (in Part III)

 

 

 

 

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 the company’s 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, marketing and chemical margins; actions of competitors or regulators; timing of exploration expenses; timing of crude-oil liftings; 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 or assessments 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, industry-specific taxes, 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 30 and 31 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.

 

A list of the company’s major subsidiaries is presented on pages E-125and E-126.As of December 31, 2008, Chevron had approximately 67,000 employees (including about 5,000 service station employees). Approximately 32,000 employees (including about 4,000 service station employees), or 48 percent, 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 stockholder 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 Australia. Tabulations of segment sales and other operating revenues, earnings and income taxes for the three years ending December 31, 2008, and assets as of the end of 2008 and 2007 — for the United States and the company’s international geographic areas — are in Note 9 to the Consolidated Financial Statements beginning onpage FS-38.Similar comparative data for the company’s investments in and income from equity affiliates and property, plant and equipment are in Notes 12 and 13 on pages FS-41 to FS-43.

 

Total expenditures for 2008 were $22.8 billion, including $2.3 billion for Chevron’s share of expenditures by affiliated companies, which did not require cash outlays by the company. In 2007 and 2006, expenditures were $20 billion and $16.6 billion, respectively, including the company’s share of affiliates’ expenditures of $2.3 billion and $1.9 billion in the corresponding periods.

 

Of the $22.8 billion in expenditures for 2008, about three-fourths, or $17.5 billion, was related to upstream activities. Approximately the same percentage was also expended for upstream operations in 2007 and 2006. 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 2009, the company estimates capital and exploratory expenditures will be $22.8 billion, including $1.8 billion of spending by affiliates. About three-fourths of the total, or $17.5 billion, is budgeted for exploration and production activities, with $13.9 billion of that amount outside the United States.

 

Refer also to a discussion of the company’s capital and exploratory expenditures onpage FS-11and FS-12.

 

The table on the following page summarizes the net production of liquids and natural gas for 2008 and 2007 by the company and its affiliates.

 

 

 

Worldwide oil-equivalent production, including volumes from oil sands (refer to footnote 1 above), was 2.53 million barrels per day, down about 3 percent from 2007. The decline was mostly attributable to damages to facilities caused by September 2008 hurricanes in the U.S. Gulf of Mexico and the impact of higher prices on certain production-sharing and variable-royalty agreements outside the United States. Refer to the “Results of Operations” section beginning onpage FS-6for a detailed discussion of the factors explaining the 2006 — 2008 changes in production for crude oil and natural gas liquids and natural gas.

The company estimates that its average worldwide oil-equivalent production in 2009 will be approximately 2.63 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,fluctuations in demand for natural gas in various markets, 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-67for 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 2008, 2007 and 2006.

 

The following table summarizes gross and net productive wells at year-end 2008 for the company and its affiliates:

 

 

Refer to Table V beginning onpage FS-67for a tabulation of the company’s proved net oil and gas reserves by geographic area, at the beginning of 2006 and each year-end from 2006 through 2008, and an accompanying discussion of major changes to proved reserves by geographic area for the three-year period ending December 31, 2008. During 2008, the company provided oil and gas reserves estimates for 2007 to the Department of Energy, Energy Information Administration (EIA), that agree with the 2007 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 2007 Annual Report onForm 10-K.During 2009, the company will file estimates of oil and gas reserves with the Department of Energy, EIA, consistent with the 2008 reserve data reported in Table V.

The net proved-reserve balances at the end of each of the three years 2006 through 2008 are shown in the table below:

 

 

At December 31, 2008, 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, as discussed below.

 

In the United States, the company is contractually committed to deliver to third parties and affiliates 414 billion cubic feet of natural gas through 2011. 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 a variety of pricing terms, including both index and fixed-price contracts.

 

Outside the United States, the company is contractually committed to deliver to third parties a total of 865 billion cubic feet of natural gas from 2009 through 2011 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. 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 28 billion cubic feet through third-party purchases.

 

Refer to Table I onpage FS-62for details associated with the company’s development expenditures and costs of proved property acquisitions for 2008, 2007 and 2006.

 

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, 2008. 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, 2008. “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.

 

 

Refer to Table I onpage FS-62for detail of the company’s exploration expenditures and costs of unproved property acquisitions for 2008, 2007 and 2006.

 

Chevron’s 2008 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-146.

 

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.

 

 

 

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 in the United States during 2008 was 671,000 barrels per day, composed of 421,000 barrels of crude oil and natural gas liquids and 1.5 billion cubic feet of natural gas. Refer to Table V beginning onpage FS-67for a discussion of the net proved reserves and different hydrocarbon characteristics for the company’s major U.S. producing areas.

 

 

During 2008, Chevron was engaged in various development and exploration activities in the deepwater Gulf of Mexico. Productionstart-upoccurred in fourth quarter 2008 at the 75 percent-owned and operated Blind Faith project. The project was designed for daily production capacity of 65,000 barrels of crude oil and 55 million cubic feet of natural gas from subsea wells tied back to a semisubmersible hull. Proved undeveloped reserves were initially recorded in 2005, and a portion was transferred to the proved-developed category in 2008 coincident with projectstart-up.The production life of the field is estimated to be approximately 20 years.

 

At Caesar/Tonga, the company participated in a successful appraisal well in 2008. The Tonga and Caesar partnerships have formed a unit agreement for the area, with Chevron having a 20 percent nonoperated working interest. First oil is expected by 2011. Development plans include a subsea tie-back to a nearby third-party production facility.

 

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 2008 included facility construction, development drilling and spar installation. First oil is expected in early 2010, with the facility capable of handling 130,000 barrels of oil-equivalent per day. The project has an expected life of approximately 25 years. 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.

 

At the 58 percent-owned and operated Tahiti Field, development work continued following a delay in 2007 due to metallurgical problems with the facility’s mooring shackles, which problems have been resolved. The project is designed as a subsea development, with the wells tied back to a truss-spar floating production facility. Productionstart-up is expected in mid-2009. Initial booking of proved undeveloped reserves occurred in 2003 for the project, with the transfer of a portion of these reserves into the proved-developed category anticipated near the time of productionstart-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. In early 2009, a possible second phase of field development was under evaluation.

 

Deepwater exploration activities in 2008 and early 2009 included participation in 12 exploratory wells — four wildcat and eight appraisal. Exploratory work included the following:

 

 

At the end of 2008, 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, the company also has access to liquefied natural gas (LNG) for the North America natural gas market through the Sabine Pass LNG terminal in Louisiana. The terminal was completed in mid-2008, and Chevron has contracted for 1 billion cubic feet per day of regasification capacity at the facility beginning in July 2009. The company also has completed the permitting process to develop the Casotte Landing regasification facility adjacent to the company’s Pascagoula refinery in Mississippi. Casotte Landing remains a development option for Chevron to bring LNG into the United States.

 

Also in the Sabine Pass area of Louisiana, the company has a binding agreement to be one of the anchor shippers in a 3.2 billion-cubic-feet-per-day third-party-owned natural gas pipeline. Chevron has contracted to 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, expected to be completed in second quarter 2009, will provide access to Chevron’s Sabine and Bridgeline pipelines, which connect to the Henry Hub. The Henry Hub interconnects to nine interstate and four intrastate pipelines and is the pricing point for natural gas futures contracts traded on the NYMEX (New York Mercantile Exchange).

 

Other U.S. Areas: Outside California and the Gulf of Mexico, the company manages operations across the mid-continental United States and Alaska. During 2008, the company’s U.S. production outside California and the Gulf of Mexico averaged 296,000 net oil-equivalent barrels per day, composed of 101,000 barrels of crude oil, 974 million cubic feet of natural gas and 33,000 barrels of natural gas liquids.

 

In the Piceance Basin in northwestern Colorado, the company is continuing a natural-gas development in which it holds a 100 percent operated working interest. A pipeline to transport the gas to a gathering system was completed in 2008 and facilities to produce 60 million cubic feet of natural gas per day are expected to be completed in mid-2009. Development drilling began in 2007, and reserves will be recognized over the life of the project based upon drilling results.

 

 

In Africa, the company is engaged in exploration and production activities in Angola, Chad, Democratic Republic of the Congo, Libya, Nigeria and Republic of the Congo.

The Takula gas-processing platform started production in December 2008. The Cabinda Gas Plant is scheduled forstart-up in the second half of 2009. The Takula and Malongo Flare and Relief project is scheduled forstart-up in stages beginning in the second half of 2009 and continuing into 2011. In Area B, development drilling occurred during 2008 at the Nemba and Kokongo fields. Front-end engineering and development (FEED) continued on the South N’Dola field development.

 

In 31 percent-owned Block 14, net production in 2008 averaged 33,000 barrels of liquids per day. Activities in 2008 included development drilling at the Benguela Belize-Lobito Tomboco (BBLT) project and the ongoing evaluation of the Negage project. Development and production rights for the various fields in Block 14 expire between 2027 and 2029.

 

Also in Block 14, development of the Tombua and Landana fields continued. Installation of producing facilities was completed in late 2008, with expectedstart-up in the second half of 2009. Production from the Landana North reservoir is expected to continue to utilize the BBLT infrastructure afterstart-up.The maximum total production from Tombua and Landana of 100,000 barrels of crude oil per day is expected to occur in 2011. Proved undeveloped reserves were recognized for Tombua and Landana in 2001 and 2002, respectively. Reclassification from proved undeveloped to proved developed for Landana occurred in 2006 and 2007. Further reclassification is expected between 2009 and 2012 as theTombua-Landanafacilities and the drilling program are completed.

During 2008, in the Lucapa provisional development area of Block 14, exploratory drilling included an appraisal well that was the second successful appraisal of the 2006 Lucapa discovery. Studies to evaluate development alternatives at Lucapa began in second quarter 2008. At the end of 2008, proved reserves had not been recognized. At the 20 percent-owned Block 2 and the 16 percent-owned FST area, combined production during 2008 averaged 3,000 barrels of net liquids per day.

 

Refer also to page 22 for a discussion of affiliate operations in Angola.

 

Angola-Republic of the Congo Joint Development Area: Chevron operates and holds a 31 percent interest in the Lianzi Development Area located between Angola and Republic of the Congo. In 2006, the development of the Lianzi area was approved by a committee of representatives from the two countries, and a conceptual field development plan was also submitted to this committee. In late 2008, the project entered FEED, and further development planning is scheduled in 2009.

 

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 exploitation permit, all of which are offshore. Net production from the Republic of the Congo fields averaged 13,000 barrels of oil-equivalent per day in 2008.

 

Production at the Moho-Bilondo subsea development project started in April 2008. Maximum total production of 90,000 barrels of crude oil per day is expected in 2010. Proved undeveloped reserves were initially recognized in 2001. Transfer to the proved-developed category occurred in 2008. Chevron’s development and production rights for Moho-Bilondo expire in 2030. One appraisal well was drilled in the Moho-Bilondo permit area during 2008. Drilling began on an exploration well in early 2009.

 

Chad/Cameroon: Chevron participates 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 in 2008 was 29,000 barrels of oil-equivalent. In late 2008, the development application for the Timbre Field in the Doba area was approved. The Chad producing operations are conducted under a concession that expires in 2030. Partners relinquished rights to exploration acreage not covered by field-development rights in February 2009.

 

Libya: Chevron is the operator and holds a 100 percent interest in the onshore Block 177 exploration license. A two-well exploration program is scheduled for 2009.

 

this project was $7 billion. Additional development drilling is being evaluated. The leases that contain the Agbami Field expire in 2023 and 2024.

 

Also in the deepwater area, the Aparo Field in OML 132 and OML 140 and the Bonga SW Field in offshore OML 118 share a common geologic structure and are planned to be jointly developed under a proposed unitization agreement. Work continued in early 2009 on agreements between Chevron and partners in OML 118. At the end of 2008, the company had not recognized proved reserves for this project.

 

Chevron operates and holds a 95 percent interest in the deepwater Nsiko discovery on OML 140. Development activities continued in 2008, with FEED expected to commence after commercial terms are resolved. At the end of 2008, the company had not recognized proved reserves for this project.

 

The company also holds a 30 percent nonoperated working interest in the deepwater Usan project in OML 138. The development plans involve subsea wells producing to an FPSO vessel. Major construction contracts were awarded in 2008, and development drilling is scheduled to begin in the second half of 2009. Productionstart-up is scheduled for 2012. Maximum total production of 180,000 barrels of crude oil per day is expected to be achieved within one year ofstart-up.The company recognized proved undeveloped reserves for the project in 2004, and a portion is expected to be reclassified to the proved-developed category near productionstart-up.

 

Chevron participated in three successful deepwater exploration wells during 2008. Hydrocarbons were confirmed in two wells in OPL 214 and one well in OML 113. Additional reservoir studies are scheduled for 2009, and one exploration well is planned later in the year. The company has 20 percent and 18 percent nonoperated working interests in the two leases, respectively. At the end of 2008, proved reserves had not been recognized for these activities.

 

In the Niger Delta, construction is under way on the Phase 3A expansion of the Escravos Gas Plant (EGP), which is expected to be installed in late 2009 and start up production in 2010. 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 15,000 to 58,000 barrels per day. EGP Phase 3A is designed to process natural gas from the Meji, Delta South, Okan and Mefa 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 EGP Phase 3A is 25 years. Phase 3B of the EGP project is designed to gather natural gas from eight offshore fields and to compress and transport natural gas to onshore facilities beginning in 2013.

 

Engineering and procurement activities continued during 2008 for certain onshore fields that had been shut in since 2003 due to civil unrest. The 40 percent-owned and operated Onshore Asset Gas Management project is designed to restore approximately 125 million cubic feet of natural gas per day to the Nigerian domestic gas market. A major construction contract is expected to be awarded in 2010.

 

Refer to page 23 for a discussion of affiliate operations in Nigeria and to page 25 for a discussion of the plannedgas-to-liquidsfacility at Escravos. Refer also to “Pipelines” under “Transportation Operations” beginning on page 26 for a discussion of the West African Gas Pipeline operations.

 

Major producing countries in the Asia-Pacific region include Australia, Azerbaijan, Bangladesh, Kazakhstan, the Partitioned Neutral Zone located between Saudi Arabia and Kuwait, and Thailand.

 

The NWS Venture is also advancing plans to extend the period of crude-oil production. The NWS Oil Redevelopment Project is designed to replace an FPSO and a portion of existing subsea infrastructure that services production from the Cossack, Hermes, Lambert and Wanaea offshore fields. A final investment decision was made in November 2008 andstart-up is expected early 2011. The project is expected to extend production past 2020. The concession for the NWS Venture expires in 2034.

 

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 2008. 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 two joint-venture participants are planning for the combined development of Gorgon and nearby natural-gas fields as one large-scale project. Environmental approvals were in process and a final investment decision is expected to be made in the second half of 2009 for a three-train, 15 million-metric-ton-per-year LNG facility. Natural gas for the project is expected to be supplied from the Gorgon and Io/Jansz fields. The Gorgon project has an expected economic life of at least 40 years.

 

At the end of 2008, 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, including receipt of environmental permits. In 2008, negotiations continued to finalize sales agreements with three utility customers in Japan and GS Caltex, a Chevron affiliated company. Purchases by each of these customers are expected to range from 250,000 metric tons per year to 1.5 million metric tons per year over 25 years.

In 2008, the company also announced plans for a multi-train LNG plant to process natural gas from its wholly owned Wheatstone discovery located on the northwest cost of mainland Australia. The project is expected to begin FEED during the second half of 2009. During 2008, Chevron conducted appraisal drilling in the Wheatstone and Iago fields. During 2009, the company plans to drill multiple exploration and appraisal wells in its operated acreage. At the end of 2008, the company had not recognized proved reserves for this project.

 

In the Browse Basin, the company conducted successful appraisal drilling programs in the Calliance and Torosa fields. A commitment well was also drilled to test the northern extension of the Ichthys Field in the eastern Browse Basin. At the end of 2008, proved reserves had not been recognized.

approximately 163,000 barrels per day (30,000 net barrels) of processed liquids at world-market prices. The remaining liquids were sold into Russian markets. During 2008, work continued on a fourth train that is designed to increase the export of processed liquids by 56,000 barrels per day (11,000 net barrels). The fourth train is expected to start up in 2011.

 

During 2008, partners continued to evaluate alternatives for a Phase III development of Karachaganak. Timing for the recognition of Phase III proved reserves is uncertain and depends on finalizing a Phase III project design and achievement of project milestones. Karachaganak operations are conducted under a40-year PSC that expires in 2038.

 

Refer also to page 23 for a discussion of Tengizchevroil, a 50 percent-owned affiliate with operations in Kazakhstan, and to page 26 in “Pipelines” under “Transportation Operations” for a discussion of CPC operations.

 

Bangladesh: Chevron operates and has 98 percent interests in three PSCs in onshore Blocks 12, 13 and 14 and an 88 percent interest in Block 7. Net oil-equivalent production from these operations in 2008 averaged 71,000 barrels per day, composed of 414 million cubic feet of natural gas and 2,000 barrels of liquids.

 

Cambodia: Chevron operates and holds a 55 percent interest in the1.2 million-acre(4,709 sq-km) Block A, located offshore in the Gulf of Thailand. During 2008 and early 2009, evaluation continued of the exploratory and appraisal drilling programs that occurred in 2007. Proved reserves had not been recognized as of the end of 2008.

Myanmar: Chevron has a 28 percent nonoperated working interest in a PSC for the production of natural gas from the Yadana and Sein fields offshore in the Andaman Sea. The company also has a 28 percent interest in a pipeline company that transports the natural gas from Yadana to the Myanmar-Thailand border for delivery to power plants in Thailand. Most of the natural gas is purchased by Thailand’s PTT Public Company Limited (PTT). The company’s average net natural gas production in 2008 was 89 million cubic feet per day.

 

For Blocks 10 through 13, a final investment decision was made in March 2008 for the construction of a second central natural-gas processing facility in the Platong area. The 70 percent-owned and operated Platong Gas II project is designed to add 420 million cubic feet per day of processing capacity in 2011. The company expects to reclassify proved undeveloped reserves to proved developed throughout the project’s life as the wellhead platforms are installed. Concessions for Blocks 10 through 13 expire in 2022.

 

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 occurred in 2008 and averaged 10,000 net oil-equivalent barrels per day through the end of the year.

 

During 2008, 13 exploration wells were drilled in the Gulf of Thailand, and all were successful. In Block G4/50, an exploratory joint operating agreement was signed in late 2008. A3-D seismic survey and geological studies are scheduled for 2009. Three exploratory wells are planned for 2010. At the end of 2008, proved reserves had not been recognized for these activities. In addition, Chevron holds exploration interests in a number of blocks that are currently inactive, pending resolution of border issues between Thailand and Cambodia.

 

Vietnam: The company operates off the southwest coast and has a 42 percent interest in a PSC that includes Blocks B and 48/95, and a 43 percent interest in another PSC for Block 52/97. Chevron also has a third PSC with a 50 percent-owned and operated interest in Block B122 offshore eastern Vietnam. No production occurred in these areas during 2008.

 

In the blocks off the southwest coast, the Vietnam Gas Project is aimed at developing an area in the Malay Basin to supply natural gas to state-owned PetroVietnam. The project includes installation of wellhead and hub platforms, an FSO vessel, field 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. At the end of 2008, proved reserves had not been recognized for this project.

 

During the year, two exploratory wells confirmed hydrocarbons in Block B and Block 52/97. In Block 122,2-D seismic information was purchased in late 2008, with processing scheduled for 2009. Proved reserves had not been recognized as of the end of 2008. Future activity in Block 122 may be affected by an ongoing territorial dispute between Vietnam and China.

 

The joint development of the HZ 25-3 and HZ 25-1 crude-oil fields in Block 16/19 is expected to achieve first production in the third quarter 2009. The maximum total production of approximately 11,000 barrels of crude oil per day is anticipated by early 2011.

 

Philippines: The company holds a 45 percent nonoperated working interest in the Malampaya natural-gas field located 50 miles (80 km) offshore Palawan Island. Net oil-equivalent production in 2008 averaged 26,000 barrels per day, composed of 128 million cubic feet of natural gas and 5,000 barrels of condensate. Chevron also develops and produces geothermal resources under an agreement with the National Power Corporation, a Philippine government-owned company. The combined generating capacity of the facilities is 637 megawatts.

 

The company’s net oil-equivalent production in 2008 from all of its interests in Indonesia averaged 235,000 barrels per day. The daily oil-equivalent rate comprised 182,000 barrels of crude oil and 319 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. The North Duri Development is located in the northern area of the Duri Field and is divided into multiple expansion areas. The Area 12 expansion area started production November 2008. Maximum total daily production from Area 12 is estimated at 34,000 barrels of crude oil in 2012. Proved undeveloped reserves for the North Duri development 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.

 

Chevron has plans to develop the Gendalo and Gehem deepwater natural-gas fields located in the Kutei Basin as a single project with one development concept. In October 2008, the company received approval from the government of Indonesia for the final development plans. The Bangka natural-gas project remained under evaluation in 2008 and, based on the evaluation results, may be developed in parallel with Gendalo and Gehem. The development timing is dependent on government approvals, market conditions and the achievement of key project milestones. At the end of 2008, the company had not recognized proved reserves for either of these projects. The company holds an 80 percent operated interest in both.

 

Also in the Kutei Basin, first production is expected in March 2009 at the Seturian Field, which is providing natural gas to a state-owned refinery. During 2008, the development concept for the 50 percent-owned and operated Sadewa project in the Kutei Basin remained under evaluation. A development decision for Sadewa is expected by year-end 2009.

 

A drilling campaign continued through 2008 in South Natuna Sea Block B to provide additional supply for long-term gas sales contracts. Additional development drilling in the North Belut Field began in November 2008, with first production expected in fourth quarter 2009. In November 2008, Chevron was awarded 100 percent interests in two exploration blocks in western Papua. Geological studies are planned for 2009 in preparation for 2-Dseismic acquisition.

 

In West Java, Chevron operates the wholly owned Salak geothermal field with a total capacity of 377 megawatts. Also in West Java, Chevron holds a 95 percent interest in a power generation company that operates the Darajat geothermal contract area in Garut with a total capacity of 259 megawatts. Chevron also operates a 95 percent-owned 300-megawatt cogeneration facility in support of CPI’s operation in North Duri, Sumatra.

 

The “Other International” region is composed of Latin America, Canada and Europe.

 

2009. At the end of 2008, proved reserves had not been recognized for these projects.

 

In the Santos basin, evaluation of investment options continued into 2009 for the 20 percent-owned and partner-operated Atlanta and Oliva fields. At the end of 2008, proved reserves had not been recognized.

 

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 209 million cubic feet of natural gas in 2008.

 

Trinidad and Tobago: Company interests include 50 percent ownership in four partner-operated blocks in the East Coast Marine Area offshore Trinidad, which includes the Dolphin and Dolphin Deep producing natural-gas fields and the Starfish discovery. Chevron also holds a 50 percent operated interest in the Manatee area of Block 6d. Net production in 2008 averaged 189 million cubic feet of natural gas per day. Incremental production associated with a new domestic sales agreement is scheduled to commence at Dolphin in third quarter 2009.

 

Venezuela: The company operates in two exploratory blocks offshore Plataforma Deltana, with working interests of 60 percent in Block 2 and 100 percent in Block 3. Chevron also holds a 100 percent operated interest in the Cardon III exploratory block, located north of Lake Maracaibo in the Gulf of Venezuela. Petróleos de Venezuela, S.A. (PDVSA), Venezuela’s national crude-oil and natural-gas company, has the option to increase its ownership in each of the three company-operated blocks up to 35 percent upon declaration of commerciality.

 

A conceptual development plan has been completed for the Loran Field in Block 2. Loran is projected to provide the initial supply of natural gas for Delta Caribe LNG (DCLNG) Train 1, Venezuela’s first LNG train. A DCLNG framework agreement was signed in September 2008, which provides Chevron with a 10 percent nonoperated interest in the first train and the associated offshore pipeline. An exploration well is planned in the Cardon III block in 2009. At the end of 2008, proved reserves had not been recognized in these exploratory blocks.

 

Chevron also holds interest in two affiliates located in western Venezuela and in one affiliate in the Orinoco Belt. Refer to page 23 for a discussion of affiliate operations in Venezuela.

 

 

At AOSP, the first phase of an expansion project is under way that is designed to produce an additional 100,000 barrels per day of mined bitumen. The expansion would increase total AOSP design capacity to more than 255,000 barrels per day in late 2010. The projected cost of this expansion is $13.7 billion.

 

The Ells River project consists of heavy oil leases of more than 85,000 acres (344 sq km). The area contains significant volumes with potential for recovery by using Steam Assisted Gravity Drainage, an industry-proven technology that employs steam and horizontal drilling to extract the bitumen through wells rather than through mining operations. During 2008, the company completed an appraisal drilling program and a seismic survey. An additional seismic program started in late 2008 and is expected to be completed in March 2009. At the end of 2008, proved reserves had not been recognized.

 

The company also holds exploration leases in the Mackenzie Delta and Beaufort Sea region, including a 33 percent nonoperated working interest in the offshore Amauligak discovery. Three exploration wells were drilled on company leases in the Mackenzie Delta region in 2008. Drilling on three additional wells in the Mackenzie Delta is expected to be completed in second quarter 2009 and assessment of development concept alternatives for Amauligak continued. The company holds additional exploration acreage in eastern Labrador and the Orphan Basin. At the end of 2008, proved reserves had not been recognized for any of these areas.

 

Greenland: Chevron has a 29 percent nonoperated working interest in an exploration license in Block 4 offshore West Greenland in the Baffin Basin. A2-D seismic survey was completed in 2008, and interpretation of the data is expected to occur in 2009.

 

Norway: The company holds an 8 percent interest in the partner-operated Draugen Field. The company’s net production averaged 6,000 barrels of oil-equivalent per day during 2008. In the 40 percent-owned and partner-operated PL397 area in the Barents Sea, additional3-D seismic information was obtained in 2008, with evaluation of the data continuing into 2009.

 

United Kingdom: The company’s average net oil-equivalent production in 2008 from 11 offshore fields was 106,000 barrels per day, composed of 71,000 barrels of crude oil and natural gas liquids and 208 million cubic feet of natural gas. Most of the production was from the 85 percent-owned and operated Captain Field and the 32 percent-owned and jointly operated Britannia Field.

 

Two partner-operated satellite fields of Britannia commenced production in 2008 — the 17 percent-owned Callanish Field in the second quarter and the 25 percent-owned Brodgar Field in the third quarter.

 

At the 40 percent-owned and operated Rosebank/Lochnagar area northwest of the Shetland Islands, an exploration well in an adjacent structure is expected to be completed in second-quarter 2009 and an appraisal well is planned for later in the year. Evaluation of development alternatives continued during 2008 for the 19 percent-owned and partner-operated Clair Phase 2 and 10 percent-owned and partner-operated Laggan/Tormore projects. As of the end of 2008, proved reserves had not been recognized for any of these three exploration areas.

 

Angola: In addition to the exploration and producing activities in Angola, Chevron has a 36 percent ownership interest in the Angola LNG affiliate that began construction in early 2008 of an onshore natural gas liquefaction plant located in the northern part of the country. The plant is designed to process more than 1 billion cubic feet of natural gas per day. Plantstart-up is scheduled for 2012. Chevron made an initial booking of proved undeveloped natural-gas reserves in 2007 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 operates and is developing the Tengiz and Korolev crude-oil fields, located in western Kazakhstan, under a40-yearconcession that expires in 2033. Chevron’s net oil-equivalent production in 2008 from these fields averaged 201,000 barrels per day, composed of 168,000 barrels of crude oil and natural gas liquids and 195 million cubic feet of natural gas.

 

In 2008, TCO completed a significant expansion composed of two integrated projects referred to as Second Generation Plant (SGP) and Sour Gas Injection (SGI). Total cost of the project was $7.4 billion. The projects increased TCO’s daily production capacity to 540,000 barrels of crude oil, 760 million cubic feet of natural gas and 46,000 barrels of natural gas liquids. The SGI facility injects approximately one-third of the sour gas separated from the crude oil back into the reservoir. The injected gas maintains higher reservoir pressure and displaces oil towards producing wells. The company recognized additional proved reserves associated with SGI in 2008. TCO is evaluating options for another expansion project based on SGI/SGP technologies.

 

During 2008, the majority of TCO’s production was 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. The majority of the incremental production from SGI/SGP was moved by rail to Black Sea ports. Other export routes included shipment via tanker to Baku for transport by the BTC pipeline to Ceyhan or by rail to Black Sea ports. (Refer to “Pipelines” under “Transportation Operations” beginning on page 26 for a discussion of CPC operations.)

 

Nigeria: Chevron holds 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 natural gas liquefaction facility and marine terminal located northwest of Escravos. The project is expected to be implemented in phases, starting with two 6.3 million-ton-per-year trains. 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 Nigerian National Petroleum Corporation. At the end of 2008, a final investment decision had not been reached, and the company had not recognized proved reserves associated with this project.

 

Venezuela: Chevron has a 30 percent interest in the Petropiar affiliate that operates 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 in the western part of the country, and a 25 percent interest in the Petroindependiente affiliate that operates the LL-652 Field in Lake Maracaibo. The company’s share of average net oil-equivalent production during 2008 from these operations was 66,000 barrels per day, composed of 62,000 barrels of crude oil and natural gas liquids and 27 million cubic feet of natural gas.

 

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. The company also makes third-party purchases and sales of natural gas in connection with its trading activities. Substantially all of the sales of natural gas liquids 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 sales volumes of natural gas and natural gas liquids. Refer also to “Delivery Commitments” on page 8 for information related to the company’s delivery commitments for the sale of crude oil and natural gas.

 

At the end of 2008, the company had a refining network capable of processing 2.1 million barrels of crude oil per day. Daily refinery inputs for 2006 through 2008 for the company and affiliate refineries were as follows:

(Crude-unitcapacities and crude-oil inputs in thousands of barrels per day; includes equity share in affiliates)

 

Average crude oil distillation capacity utilization during 2008 was 87 percent, compared with 85 percent in 2007. This increase generally resulted from an improvement in utilization at the refineries in Richmond and El Segundo, California. At the U.S. fuel refineries, crude oil distillation capacity utilization averaged 95 percent in 2008, compared with 85 percent in 2007, and cracking and coking capacity utilization averaged 86 percent and 78 percent in 2008 and 2007, respectively. Cracking and coking units are the primary facilities used in fuel refineries to convert heavier feedstocks into gasoline and other light products.

 

The company’s refineries in the United States, the United Kingdom, Canada, South Africa and Australia produce low-sulfur fuels. GS Caltex, the company’s 50 percent-owned affiliate, completed construction in 2008 on projects to produce low-sulfur fuels at the700,000 barrel-per-dayYeosu refining complex in South Korea. Other projects completed during the year at Yeosu included a new hydrocracker complex and distillation unit that increases high-value product yield and lowers feedstock costs. In 2009, construction continues at the Yeosu complex on projects designed to further improve processing of higher-sulfur crude oils and reduce fuel-oil production. At the company’s 50 percent-owned Singapore Refining Company, construction continued during 2008 and into early 2009 to enable the refinery to meet regional specifications for clean diesel fuels.

 

At the Pascagoula refinery, various projects were completed during 2008 that enhanced the ability to process heavier, higher-sulfur crudes, resulting in lower crude-acquisition costs. In addition, construction progressed on a continuous catalytic reformer that is expected to improve refinery reliability and increase daily gasoline production at the refinery by 10 percent, or 600,000 gallons per day, by mid-2010. At the Richmond and El Segundo refineries, construction continued and design and engineering work advanced during 2008 to further increase the ability to process high-sulfur crude oils and improve high-value product yields.

In August 2008, Chevron submitted an environmental permit application to the Mississippi Department of Environmental Quality for the construction of a premium base oil facility at the company’s Pascagoula Refinery. The facility is expected to have daily production of approximately 25,000 barrels of premium base oil for use in manufacturing high-performance lubricants, such as motor oils for consumer and commercial uses.

 

Chevron holds a 5 percent interest in Reliance Petroleum Limited, a company formed by Reliance Industries Limited to construct a new refinery in Jamnagar, India. Chevron has rights to increase its equity ownership to 29 percent or to sell back its investment to Reliance Industries Limited. These rights expire the later of July 27, 2009, or three months after the plant is fully commissioned.

 

Chevron processes imported and domestic crude oil in its U.S. refining operations. Imported crude oil accounted for about 88 percent and 87 percent of Chevron’s U.S. refinery inputs in 2008 and 2007, respectively.

 

In Nigeria, Chevron and the Nigerian National Petroleum Corporation are developing a34,000 barrel-per-daygas-to-liquidsfacility at Escravos designed to process natural gas supplied from the Phase 3A expansion of the Escravos Gas Plant (EGP). At the end of 2008, engineering was essentially complete and facility construction was under way. Chevron has a 75 percent interest in the plant, which is expected to be operational by 2012. The estimated cost of the plant is $5.9 billion. Refer also to page 14 for a discussion on the EGP Phase 3A expansion.

 

The company markets petroleum products under the principal brands of “Chevron,” “Texaco” and “Caltex” throughout much of the world. The table below identifies the company’s and affiliates’ refined products sales volumes, excluding intercompany sales, for the three years ending December 31, 2008.

(Thousands of Barrels per Day)

 

 

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, primarily in the mid-Atlantic, southern and western states. Approximately 500 of these outlets are company-owned or -leased stations.

Outside the United States, Chevron supplies directly or through retailers and marketers approximately 15,300 branded service stations, including affiliates. In British Columbia, Canada, the company markets under the Chevron brand. The company markets in the United Kingdom, Ireland, Latin America and the Caribbean using the Texaco brand. In the Asia-Pacific region, southern 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, Caltex Australia Limited, operates using the Caltex and Ampol brands.

 

In 2008, the company announced agreements to sell marketing-related businesses in Brazil, Nigeria, Kenya, Uganda, Benin, Cameroon, Republic of the Congo, Côte d’Ivoire and Togo. The company will retain its lubricants business in Brazil. The company also completed the sale of its heating-oil business in the United Kingdom. In addition, the company sold its interest in about 350 individual service-station sites. The majority of these sites will continue to market company-branded gasoline through new supply agreements.

 

The company also manages other marketing businesses globally. Chevron markets aviation fuel at more than 1,000 airports. 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.