Chevron Corporation 10-K 2009
Documents found in this filing:
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
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)
Registrants telephone number, including area code (925) 842-1000
Securities registered pursuant to Section 12(b) of the Act:
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 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 in Rule 12b-2 of the Exchange Act. (Check one):
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No þ
Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrants 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 to Rule 14a-6(b) under the Securities Exchange Act of 1934, in connection with the companys 2009 Annual Meeting of Stockholders (in Part III)
CAUTIONARY STATEMENT RELEVANT TO FORWARD-LOOKING INFORMATION
FOR THE PURPOSE OF SAFE HARBOR PROVISIONS OF THE
PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This Annual Report on Form 10-K of Chevron Corporation contains forward-looking statements relating to Chevrons operations that are based on managements 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 companys 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 companys 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 or start-up of planned projects; the potential disruption or interruption of the companys 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 companys 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,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.
A list of the companys major subsidiaries is presented on pages E-125 and 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 worlds 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 companys 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 this Form 10-K in Managements Discussion and Analysis of Financial Condition and Results of Operations for a discussion of the companys current business environment and outlook.
1 Incorporated in Delaware in 1926 as Standard Oil Company of California, the company adopted the name Chevron Corporation in 1984 and ChevronTexaco Corporation in 2001. In 2005, ChevronTexaco Corporation changed its name to Chevron Corporation. As used in this report, the term Chevron and such terms as the company, the corporation, our, we and us may refer to Chevron Corporation, one or more of its consolidated subsidiaries, or all of them taken as a whole, but unless stated otherwise, it does not include affiliates of Chevron i.e., those companies accounted for by the equity method (generally owned 50 percent or less) or investments accounted for by the cost method. All of these terms are used for convenience only and are not intended as a precise description of any of the separate companies, each of which manages its own affairs.
Chevrons 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 company also continues to invest in renewable-energy technologies, with an objective of capturing profitable positions.
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 companys international geographic areas are in Note 9 to the Consolidated Financial Statements beginning on page FS-38. Similar comparative data for the companys 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 Chevrons 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 companys 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 companys 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 companys capital and exploratory expenditures on page FS-11 and 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.
Net Production of Crude Oil and Natural Gas Liquids and Natural Gas1
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 on page FS-6 for 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 project start-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 companys major oil and gas development projects.
Refer to Table IV on page FS-67 for the companys 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:
Productive Oil and Gas Wells1 at December 31, 2008
Refer to Table V beginning on page FS-67 for a tabulation of the companys 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 companys 2007 Annual Report on Form 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 companys acreage is shown in the following table.
Acreage1 at December 31, 2008
(Thousands of Acres)
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 companys 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 companys 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 on page FS-62 for details associated with the companys development expenditures and costs of proved property acquisitions for 2008, 2007 and 2006.
The table below summarizes the companys net interest in productive and dry development wells completed in each of the past three years and the status of the companys 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.
Development Well Activity
The following table summarizes the companys 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.
Exploratory Well Activity
Refer to Table I on page FS-62 for detail of the companys exploration expenditures and costs of unproved property acquisitions for 2008, 2007 and 2006.
Chevrons 2008 key upstream activities, some of which are also discussed in Managements 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-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 companys 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 on page FS-67 for a discussion of the net proved reserves and different hydrocarbon characteristics for the companys major U.S. producing areas.
During 2008, Chevron was engaged in various development and exploration activities in the deepwater Gulf of Mexico. Production start-up occurred 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 project start-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 Chevrons 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 production start-up.
At the 58 percent-owned and operated Tahiti Field, development work continued following a delay in 2007 due to metallurgical problems with the facilitys 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. Production start-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 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. 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 companys 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 Chevrons 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 companys 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 for start-up in the second half of 2009. The Takula and Malongo Flare and Relief project is scheduled for start-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 NDola 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 expected start-up in the second half of 2009. Production from the Landana North reservoir is expected to continue to utilize the BBLT infrastructure after start-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 the Tombua-Landana facilities 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. Chevrons 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. Production start-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 of start-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 production start-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 planned gas-to-liquids facility 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 and start-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. Chevrons 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 a 40-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 the 1.2 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 Thailands PTT Public Company Limited (PTT). The companys 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 projects 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. A 3-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 of start-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 companys 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 worlds 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-D seismic 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 CPIs 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), Venezuelas 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, Venezuelas 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. A 2-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 companys 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, additional 3-D seismic information was obtained in 2008, with evaluation of the data continuing into 2009.
United Kingdom: The companys 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. Plant start-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 a 40-year concession that expires in 2033. Chevrons 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 TCOs 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 TCOs 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 Chevrons 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 Venezuelas 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 companys 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 companys 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, on page FS-10 in Managements Discussion and Analysis of Financial Condition and Results of Operations, for further information on the companys sales volumes of natural gas and natural gas liquids. Refer also to Delivery Commitments on page 8 for information related to the companys delivery commitments for the sale of crude oil and natural gas.
Downstream Refining, Marketing and Transportation
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:
Petroleum Refineries: Locations, Capacities and Inputs
(Crude-unit capacities 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 companys refineries in the United States, the United Kingdom, Canada, South Africa and Australia produce low-sulfur fuels. GS Caltex, the companys 50 percent-owned affiliate, completed construction in 2008 on projects to produce low-sulfur fuels at the 700,000 barrel-per-day Yeosu 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 companys 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 companys 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 Chevrons U.S. refinery inputs in 2008 and 2007, respectively.
In Nigeria, Chevron and the Nigerian National Petroleum Corporation are developing a 34,000 barrel-per-day gas-to-liquids facility 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 companys and affiliates refined products sales volumes, excluding intercompany sales, for the three years ending December 31, 2008.
Refined Products Sales Volumes1
(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 companys 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 dIvoire 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 companys ownership interests in pipelines are summarized in the following table.
During 2008, the company completed the construction of a natural gas gathering pipeline serving the Piceance Basin in northwest Colorado; participated in the successful installation of the Amberjack-Tahiti lateral pipeline on the seafloor of the U.S. Gulf of Mexico; and led the expansion of the West Texas LPG pipeline system. Chevron also continued with a project during 2008 to expand capacity by about 2 billion cubic feet at the Keystone natural-gas storage facility. The project is expected to be completed in late 2009.
Chevron has a 15 percent interest in the Caspian Pipeline Consortium (CPC) affiliate. CPC operates a crude oil export pipeline from the Tengiz Field in Kazakhstan to the Russian Black Sea port of Novorossiysk. During 2008, CPC transported an average of approximately 675,000 barrels of crude oil per day, including 557,000 barrels per day from Kazakhstan and 118,000 barrels per day from Russia. In late 2008, the CPC partners signed a Memorandum of Understanding to expand the design capacity to 1.4 million barrels per day. A final investment decision is expected after commercial terms have been agreed upon and required government approvals have been received.
The company has a 9 percent interest in the Baku-Tbilisi-Ceyhan (BTC) affiliate that owns and operates a pipeline that transports primarily the crude oil produced by Azerbaijan International Operating Company (AIOC) (owned 10 percent by Chevron) from Baku, Azerbaijan, through Georgia to deepwater port facilities in Ceyhan, Turkey. The BTC pipeline has a crude-oil capacity of 1.2 million barrels per day and transports the majority of the AIOC production. Another production export route for crude oil is the Western Route Export Pipeline, wholly owned by AIOC, with capacity to transport 145,000 barrels per day from Baku, Azerbaijan, to the marine terminal at Supsa, Georgia.
Chevron is the largest shareholder, with a 37 percent interest, in the West African Gas Pipeline Company Limited affiliate, which constructed, owns and operates the 421-mile (678-km) West African Gas Pipeline. The pipeline is designed to supply Nigerian natural gas to customers in Benin, Ghana and Togo for industrial applications and power generation and is expected to have capacity of 170 million cubic feet of natural gas per day by 2010. First gas was shipped in December 2008.
Tankers: All tankers in Chevrons controlled seagoing fleet were utilized during 2008. In addition, at any given time during 2008 the company had approximately 40 deep-sea vessels chartered on a voyage basis, or for a period of less than one year. Additionally, the following table summarizes the capacity of the companys controlled fleet.
Federal law requires that cargo transported between U.S. ports be carried in ships built and registered in the United States, owned and operated by U.S. entities, and manned by U.S. crews. In 2008, the companys U.S. flag fleet was engaged primarily in transporting refined products between the Gulf Coast and the East Coast and from California refineries to terminals on the West Coast and in Alaska and Hawaii. One U.S.-flagged product tanker, capable of carrying 300,000 barrels of cargo, was delivered in 2008 and two additional U.S.-flagged product tankers are scheduled for delivery in 2010.
The foreign-flagged vessels were engaged primarily in transporting crude oil from the Middle East, Asia, the Black Sea, Mexico and West Africa to ports in the United States, Europe, Australia and Asia. Refined products were also transported by tanker worldwide.
In addition to the vessels described above, the company owns a one-sixth interest in each of seven LNG tankers transporting cargoes for the North West Shelf (NWS) Venture in Australia. The NWS project also has two LNG tankers under long-term time charter. In 2008, the company sold its two LNG shipbuilding contracts with Samsung Heavy Industries, but retained the option to purchase two new LNG vessels.
The Federal Oil Pollution Act of 1990 requires the phase-out by year-end 2010 of all single-hull tankers trading to U.S. ports or transferring cargo in waters within the U.S. Exclusive Economic Zone. As of the end of 2008, the companys owned and bareboat-chartered fleet was completely double-hulled. The company is a member of many oil-spill-response cooperatives in areas in which it operates around the world.
Chevron Phillips Chemical Company LLC (CPChem) is equally owned with ConocoPhillips Corporation. At the end of 2008, CPChem owned or had joint venture interests in 35 manufacturing facilities and five research and technical centers in Belgium, Brazil, China, Colombia, Qatar, Saudi Arabia, Singapore, South Korea and the United States.
Americas Styrenics LLC, a 50-50 joint venture between CPChem and Dow Chemical Company, began commercial operations in 2008. This joint venture combined CPChems U.S. styrene and polystyrene operations with Dows U.S. and Latin America polystyrene operations. Also, construction continued on the new 22 million-pound-per-year Ryton® polyphenylene-sulfide (PPS) manufacturing facility at Borger, Texas. Completion of this plant is expected in second quarter 2009.
Outside the United States, CPChems 50 percent-owned Jubail Chevron Phillips Company began commercial production at its world-scale styrene facility at Al Jubail, Saudi Arabia. The styrene facility is located adjacent to an existing aromatics complex in Al Jubail that is jointly owned by CPChem and the Saudi Industrial Investment Group. Also during 2008, construction commenced by Saudi Polymers Company, a joint venture company formed to build a third petrochemical project in Al Jubail. Project completion is expected in 2011.
CPChem continued construction during 2008 on the 49 percent-owned Q-Chem II project in Mesaieed, Qatar. The project includes a 350,000-metric-ton-per-year polyethylene plant and a 345,000-metric-ton-per-year normal alpha olefins plant each utilizing CPChem proprietary technology and is located adjacent to the existing Q-Chem I complex. Q-Chem II also includes a separate joint venture to develop a 1.3 million-metric-ton-per-year ethylene cracker at Qatars Ras Laffan Industrial City, in which Q-Chem II owns 54 percent of the capacity rights. Start-up is anticipated in late 2009.
Chevrons Oronite brand lubricant and fuel additives business is a leading developer, manufacturer and marketer of performance additives for lubricating oils and fuels. The company owns and operates facilities in Brazil, France, Japan, the Netherlands, Singapore and the United States and has equity interests in facilities in India and Mexico. Oronite provides additives for lubricating oil in most engine applications, such as passenger car, heavy-duty diesel, marine, locomotive and motorcycle engines, and additives for fuels to improve engine performance and extend engine life. Oronite completed construction and started up the hydrofluoric acid replacement alkylation units in Gonfreville, France, during 2008. Commercial production commenced in January 2009. Also during 2008, the Gonfreville facility began full commercial production of new sulfur-free detergent components for marine engine applications and low-sulfur components for automotive engine oil applications.
Chevrons U.S.-based mining company produces and markets coal and molybdenum. Sales occur in both U.S. and international markets.
The company owns and operates two surface coal mines, McKinley, in New Mexico, and Kemmerer, in Wyoming, and one underground coal mine, North River, in Alabama. The company also owns a 50 percent interest in Youngs Creek Mining Company LLC, a joint venture to develop a coal mine in northern Wyoming. Coal sales from wholly owned mines were 11 million tons, down about 1 million tons from 2007.
At year-end 2008, Chevron controlled approximately 200 million tons of proven and probable coal reserves in the United States, including reserves of environmentally desirable low-sulfur coal. The company is contractually committed to deliver between 8 million and 11 million tons of coal per year through the end of 2010 and believes it will satisfy these contracts from existing coal reserves.
In addition to the coal operations, Chevron owns and operates the Questa molybdenum mine in New Mexico. At year-end 2008, Chevron controlled approximately 53 million pounds of proven molybdenum reserves at Questa.
In 2008, the company sold the petroleum coke calciner assets of Chicago Carbon Company, a wholly owned subsidiary in Illinois. The company also sold its lanthanides processing facilities and rare-earth mineral mine in Mountain Pass, California, and its 33 percent interest in Sumikin Molycorp, a manufacturer and marketer of neodymium compounds in Japan. In early 2009, the company was actively marketing its coal reserves at the North River Mine and elsewhere in Alabama for sale.
Chevrons power generation business develops and operates commercial power projects and has interests in 13 power assets through joint ventures in the United States and Asia. The company manages the production of more than 2,300 megawatts of electricity at 11 facilities it owns through joint ventures. The company operates gas-fired cogeneration facilities that use waste heat recovery to produce additional electricity or to support industrial thermal hosts. A number of the facilities produce steam for use in upstream operations to facilitate production of heavy oil.
The company has major geothermal operations in Indonesia and the Philippines and is investigating several advanced solar technologies for use in oil field operations as part of its renewable energy strategy. For additional information on the companys geothermal operations and renewable energy projects, refer to page 19 and Research and Technology, on page 29.
Chevron Energy Solutions (CES) is a wholly owned subsidiary that provides public institutions and businesses with sustainable energy projects designed to increase energy efficiency and reliability, reduce energy costs, and utilize renewable and alternative-power technologies. Since 2000, CES has developed hundreds of projects that will help government, education and other customers reduce their energy costs and carbon footprint. Major projects completed by CES in 2008 included several large solar panel installations in California.
The companys energy technology organization supports Chevrons upstream and downstream businesses by providing technology, services and competency development in earth sciences; reservoir and production engineering; drilling and completions; facilities engineering; manufacturing; process technology; catalysis; technical computing; and health, environment and safety. The information technology organization integrates computing, telecommunications, data management, security and network technology to provide a standardized digital infrastructure and enable Chevrons global operations and business processes.
Chevron Technology Ventures (CTV) manages investments and projects in emerging energy technologies and their integration into Chevrons core businesses. As of the end of 2008, CTV was investigating technologies such as next-generation biofuels, advanced solar power and enhanced geothermal.
Chevrons research and development expenses were $835 million, $562 million and $468 million for the years 2008, 2007 and 2006, respectively.
Some of the investments the company makes in the areas described above are in new or unproven technologies and business processes, and ultimate successes are not certain. Although not all initiatives may prove to be economically viable, the companys overall investment in this area is not significant to the companys consolidated financial position.
Virtually all aspects of the companys businesses are subject to various U.S. federal, state and local environmental, health and safety laws and regulations and to similar laws and regulations in other countries. These regulatory requirements continue to change and increase in both number and complexity and to govern not only the manner in which the company conducts its operations, but also the products it sells. Chevron expects more environment-related regulations in the countries where it has operations. Most of the costs of complying with the many laws and regulations pertaining to its operations are embedded in the normal costs of conducting business.
In 2008, the companys U.S. capitalized environmental expenditures were approximately $780 million, representing approximately 9 percent of the companys total consolidated U.S. capital and exploratory expenditures. These environmental expenditures include capital outlays to retrofit existing facilities as well as those associated with new facilities. The expenditures relate mostly to air- and water-quality projects and activities at the companys refineries, oil and gas producing facilities, and marketing facilities. For 2009, the company estimates U.S. capital expenditures for environmental control facilities will be approximately $1 billion. The future annual capital costs are uncertain and will be governed by several factors, including future changes to regulatory requirements.
Refer to Managements Discussion and Analysis of Financial Condition and Results of Operations on pages FS-16 through FS-18 for additional information on environmental matters and their impact on Chevron and on the companys 2008 environmental expenditures, remediation provisions and year-end environmental reserves.
The companys Internet Web site is at www.chevron.com. Information contained on the companys Internet Web site is not part of this Annual Report on Form 10-K. The companys Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available on the companys Web site soon after such reports are filed with or furnished to the Securities and Exchange Commission (SEC). The reports are also available at the SECs Web site at www.sec.gov.
Chevron is a major fully integrated petroleum company with a diversified business portfolio, a strong balance sheet, and a history of generating sufficient cash to fund capital and exploratory expenditures and to pay dividends. Nevertheless, some inherent risks could materially impact the companys financial results of operations or financial condition.
Chevron is primarily in a commodities business with a history of price volatility. The single largest variable that affects the companys results of operations is the price of crude oil, which can be influenced by general economic conditions and geopolitical risk.
During extended periods of historically low prices for crude oil, the companys upstream earnings and capital and exploratory expenditure programs will be negatively affected. Upstream assets may also become impaired. The impact on downstream earnings is dependent upon the supply and demand for refined products and the associated margins on refined-product sales.
The scope of Chevrons business will decline if the company does not successfully develop resources.
The company is in an extractive business; therefore, if Chevron is not successful in replacing the crude oil and natural gas it produces with good prospects for future production, the companys business will decline. Creating and maintaining an inventory of projects depends on many factors, including obtaining and renewing rights to explore, develop and produce hydrocarbons; drilling success; ability to bring long-lead-time, capital-intensive projects to completion on budget and schedule; and efficient and profitable operation of mature properties.
Chevron operates in both urban areas and remote and sometimes inhospitable regions. The companys operations and facilities are therefore subject to disruption from either natural or human causes, including hurricanes, floods and other forms of severe weather, war, civil unrest and other political events, fires, earthquakes, and explosions, any of which could result in suspension of operations or harm to people or the natural environment.
The company produces, transports, refines and markets materials with potential toxicity, and it purchases, handles and disposes of other potentially toxic materials in the course of the companys business. Chevron operations also produce byproducts, which may be considered pollutants. Any of these activities could result in liability, either as a result of an accidental, unlawful discharge or as a result of new conclusions on the effects of the companys operations on human health or the environment.
The companys operations, particularly exploration and production, can be affected by changing economic, regulatory and political environments in the various countries in which it operates. As has occurred in the past, actions could be taken by governments to increase public ownership of the companys partially or wholly owned businesses and/or to impose additional taxes or royalties.
In certain locations, governments have imposed restrictions, controls and taxes, and in others, political conditions have existed that may threaten the safety of employees and the companys continued presence in those countries. Internal unrest, acts of violence or strained relations between a government and the company or other governments may affect the companys operations. Those developments have, at times, significantly affected the companys related operations and results and are carefully considered by management when evaluating the level of current and future activity in such countries. At December 31, 2008, 29 percent of the companys net proved reserves were located in Kazakhstan. The company also has significant interests in Organization of Petroleum Exporting Countries (OPEC)-member countries including Angola, Nigeria and Venezuela and in the Partitioned Neutral Zone between Saudi Arabia and Kuwait. Twenty-three percent of the companys net proved reserves, including affiliates, were located in OPEC countries at December 31, 2008 (excluding reserves in Indonesia, which relinquished its OPEC membership at the end of 2008).
Regulation of greenhouse gas emissions could increase Chevrons operational costs and reduce demand for Chevrons products.
Management expects continued political attention to issues concerning climate change, and the role of human activity in it and potential remediation or mitigation through regulation that could materially affect the companys operations.
International agreements and national or regional legislation and regulatory measures to limit greenhouse emissions are currently in various phases of discussion or implementation. The Kyoto Protocol, Californias Global Warming Solutions Act and Australias proposed Carbon Pollution Reduction Scheme, along with other actual or pending federal, state and provincial regulations, envision a reduction of greenhouse gas emissions through market-based trading schemes. The company is currently complying with greenhouse gas emissions limits within the European Union.
As a result of these and other environmental regulations, the company expects to incur substantial capital, compliance, operating, maintenance and remediation costs. The level of expenditure required to comply with these laws and regulations is uncertain and may vary by jurisdiction depending on the laws enacted in each jurisdiction and the companys activities in it. The companys production and processing operations (e.g., the production of crude oil at offshore platforms and the processing of natural gas at liquefied natural gas facilities) typically result in emission of greenhouse gases. Likewise, emissions arise from power and downstream operations, including crude oil transportation and refining. Finally, although beyond the control of the company, the use of passenger vehicle fuels and related products by consumers also results in greenhouse gas emissions that may be regulated.
The companys financial performance will depend on a number of factors, including, among others, the greenhouse gas emissions reductions required by law, the price and availability of emission allowances and credits, the extent to which Chevron would be entitled to receive emission allowances or need to purchase them in the open market or through auctions and the impact of legislation on the companys ability to recover the costs incurred through the pricing of the companys products. Material cost increases or incentives to conserve or use alternative energy sources could reduce demand for products the company currently sells. To the extent these costs are not ultimately reflected in the price of the companys products, the companys operating results will be adversely affected.
The location and character of the companys crude oil, natural gas and mining properties and its refining, marketing, transportation and chemicals facilities are described on page 3 under Item 1. Business. Information required by the Securities Exchange Act Industry Guide No. 2 (Disclosure of Oil and Gas Operations) is also contained in Item 1 and in Tables I through VII on pages FS-62 to FS-74. Note 13, Properties, Plant and Equipment, to the companys financial statements is on page FS-43.
Ecuador Chevron is a defendant in a civil lawsuit before the Superior Court of Nueva Loja in Lago Agrio, Ecuador, brought in May 2003 by plaintiffs who claim to be representatives of certain residents of an area where an oil production consortium formerly had operations. The lawsuit alleges damage to the environment from the oil exploration and production operations, and seeks unspecified damages to fund environmental remediation and restoration of the alleged environmental harm, plus a health monitoring program. Until 1992, Texaco Petroleum Company (Texpet), a subsidiary of Texaco Inc., was a minority member of this consortium with Petroecuador, the Ecuadorian state-owned oil company, as the majority partner; since 1990, the operations have been conducted solely by Petroecuador. At the conclusion of the consortium and following an independent third-party environmental audit of the concession area, Texpet entered into a formal agreement with the Republic of Ecuador and Petroecuador for Texpet to remediate specific sites assigned by the government in proportion to Texpets ownership share of the consortium. Pursuant to that agreement, Texpet conducted a three-year remediation program at a cost of $40 million. After certifying that the sites were properly remediated, the government granted Texpet and all related corporate entities a full release from any and all environmental liability arising from the consortium operations.
Based on the history described above, Chevron believes that this lawsuit lacks legal or factual merit. As to matters of law, the company believes first, that the court lacks jurisdiction over Chevron; second, that the law under which plaintiffs bring the action, enacted in 1999, cannot be applied retroactively to Chevron; third, that the claims are barred by the
statute of limitations in Ecuador; and, fourth, that the lawsuit is also barred by the releases from liability previously given to Texpet by the Republic of Ecuador and Petroecuador. With regard to the facts, the company believes that the evidence confirms that Texpets remediation was properly conducted and that the remaining environmental damage reflects Petroecuadors failure to timely fulfill its legal obligations and Petroecuadors further conduct since assuming full control over the operations.
In April 2008, a mining engineer appointed by the court to identify and determine the cause of environmental damage, and to specify steps needed to remediate it, issued a report recommending that the court assess $8 billion, which would, according to the engineer, provide financial compensation for purported damages, including wrongful death claims, and pay for, among other items, environmental remediation, health care systems, and additional infrastructure for Petroecuador. The engineers report also asserted that an additional $8.3 billion could be assessed against Chevron for unjust enrichment. The engineers report is not binding on the court. Chevron also believes that the engineers work was performed and his report prepared in a manner contrary to law and in violation of the courts orders. Chevron submitted a rebuttal to the report in which it asked the court to strike the report in its entirety. In November 2008, the engineer revised the report and, without additional evidence, recommended an increase in the financial compensation for purported damages to a total of $18.9 billion and an increase in the assessment for purported unjust enrichment to a total of $8.4 billion. Chevron submitted a rebuttal to the revised report, and Chevron will continue a vigorous defense of any attempted imposition of liability.
Management does not believe an estimate of a reasonably possible loss (or a range of loss) can be made in this case. Due to the defects associated with the engineers report, management does not believe the report itself has any utility in calculating a reasonably possible loss (or a range of loss). Moreover, the highly uncertain legal environment surrounding the case provides no basis for management to estimate a reasonably possible loss (or a range of loss).
The information on Chevrons common stock market prices, dividends, principal exchanges on which the stock is traded and number of stockholders of record is contained in the Quarterly Results and Stock Market Data tabulations, on page FS-24.
ISSUER PURCHASES OF EQUITY SECURITIES
The selected financial data for years 2004 through 2008 are presented on page FS-61.
The index to Managements Discussion and Analysis of Financial Condition and Results of Operations, Consolidated Financial Statements and Supplementary Data is presented on page FS-1.
The companys discussion of interest rate, foreign currency and commodity price market risk is contained in Managements Discussion and Analysis of Financial Condition and Results of Operations Financial and Derivative Instruments, beginning on page FS-13 and in Note 7 to the Consolidated Financial Statements, Financial and Derivative Instruments, beginning on page FS-36.
The index to Managements Discussion and Analysis, Consolidated Financial Statements and Supplementary Data is presented on page FS-1.
The companys management has evaluated, with the participation of the Chief Executive Officer and Chief Financial Officer, the effectiveness of the companys disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the Exchange Act) as of the end of the period covered by this report. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the companys disclosure controls and procedures were effective as of December 31, 2008.
The companys management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). The companys management, including the Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of the companys internal control over financial reporting based on the Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the results of this evaluation, the companys management concluded that internal control over financial reporting was effective as of December 31, 2008.
The effectiveness of the companys internal control over financial reporting as of December 31, 2008, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report included on page FS-26.
During the quarter ended December 31, 2008, there were no changes in the companys internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the companys internal control over financial reporting.
The Executive Officers of the Corporation consist of the Chairman of the Board, the Vice Chairman of the Board and such other officers of the Corporation who are members of the Executive Committee.
The information required by Item 401(b) and (e) of Regulation S-K and contained under the heading Election of Directors in the Notice of the 2009 Annual Meeting and 2009 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934 (the Exchange Act), in connection with the companys 2009 Annual Meeting of Stockholders (the 2009 Proxy Statement), is incorporated by reference into this Annual Report on Form 10-K.
The information required by Item 405 of Regulation S-K and contained under the heading Stock Ownership Information Section 16(a) Beneficial Ownership Reporting Compliance in the 2009 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
The information required by Item 406 of Regulation S-K and contained under the heading Board Operations Business Conduct and Ethics Code in the 2009 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
The information required by Item 407(d)(4)-(5) of Regulation S-K and contained under the heading Board Operations Board Committee Membership and Functions in the 2009 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
There were no changes to the process by which stockholders may recommend nominees to the Board of Directors during the last fiscal year.
The information required by Item 402 of Regulation S-K and contained under the headings Executive Compensation and Directors Compensation in the 2009 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
The information required by Item 407(e)(4) of Regulation S-K and contained under the heading Board Operations Board Committee Membership and Functions in the 2009 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
The information required by Item 407(e)(5) of Regulation S-K and contained under the heading Board Operations Management Compensation Committee Report in the 2009 Proxy Statement is incorporated herein by reference into this Annual Report on Form 10-K. Pursuant to the rules and regulations of the SEC under the Exchange Act, the information under such caption incorporated by reference from the 2009 Proxy Statement shall not be deemed filed for purposes of Section 18 of the Exchange Act nor shall it be deemed incorporated by reference into any filing under the Securities Act of 1933.
The information required by Item 403 of Regulation S-K and contained under the heading Stock Ownership Information Security Ownership of Certain Beneficial Owners and Management in the 2009 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
The information required by Item 201(d) of Regulation S-K and contained under the heading Equity Compensation Plan Information in the 2009 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
The information required by Item 404 of Regulation S-K and contained under the heading Board Operations Transactions with Related Persons in the 2009 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
The information required by Item 407(a) of Regulation S-K and contained under the heading Board Operations Independence of Directors in the 2009 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
The information required by Item 9(e) of Schedule 14A and contained under the heading Ratification of Independent Registered Public Accounting Firm in the 2009 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
(a) The following documents are filed as part of this report:
(1) Financial Statements:
(2) Financial Statement Schedules:
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 26th day of February, 2009.
David J. OReilly, Chairman of the Board
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on the 26th day of February, 2009.
Table of Contents
Key Financial Results
Income by Major Operating Area
Refer to the Results of Operations section beginning on page FS-6 for a discussion of financial results by major operating area for the three years ending December 31, 2008.
Business Environment and Outlook
Chevron is a global energy company with 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 Saudi Arabia and Kuwait, 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.
Earnings of the company 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 companys chemicals business and other activities and invest-
ments. Earnings for the company in any period may also be influenced by events or transactions that are infrequent and/ or unusual in nature.
In recent years and through most of 2008, Chevron and the oil and gas industry at large experienced an increase in certain costs that exceeded the general trend of inflation in many areas of the world. This increase in costs affected the companys operating expenses and capital programs for all business segments, but particularly for upstream. These cost pressures began to soften somewhat in late 2008. As the price of crude oil dropped precipitously from a record high in mid-year, the demand for some goods and services in the industry began to slacken. This cost trend is expected to continue during 2009 if crude-oil prices do not significantly rebound. (Refer to the Upstream section on next page for a discussion of the trend in crude-oil prices.)
The companys operations, especially 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 companys operations or investments. Those developments have at times significantly affected the companys 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. From time to time, certain governments have sought to renegotiate contracts or impose additional costs on the company. 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 companys current operations or future prospects.
The company also continually evaluates opportunities to dispose of assets that are not expected to provide sufficient long-term value or to acquire assets or operations complementary to its asset base to help augment the companys growth. Refer to the Results of Operations section beginning on page FS-6 for discussions of net gains on asset sales during 2008. Asset dispositions and restructurings may occur in future periods and could result in significant gains or losses.
The company has been closely monitoring the ongoing uncertainty in financial and credit markets, the rapid decline in crude-oil prices that began in the second half of 2008, and the general contraction of worldwide economic activity. Management is taking these developments into account in the conduct of daily operations and for business planning. The company remains confident of its underlying financial strength to deal with potential problems presented in this environment.
Comments related to earnings trends for the companys 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 companys 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 companys control. External factors include not only the general level of inflation but also prices charged by the industrys material- and service-providers, which can be affected by the volatility of the industrys own supply and demand conditions for such materials and services. Capital and exploratory expenditures and operating expenses also can be affected by damages to production facilities caused by severe weather or civil unrest.
Industry price levels for crude oil were volatile during 2008. The spot price for West Texas Intermediate (WTI) crude oil, a benchmark crude, started 2008 at $96 per barrel and peaked at $147 in early July. At the end of the year, the WTI price had fallen to $45 per barrel. As of mid-February 2009, the WTI price was $38 per barrel. The collapse in price during the second half of 2008 was largely driven by a decline in the demand for crude oil that was associated with a significant weakening in world economies. The WTI price averaged $100 per barrel for the full-year 2008, compared with $72 in 2007.
As in 2007, a wide differential in prices existed in 2008 between high-quality (i.e., high-gravity, low-sulfur) crude oils and those of lower quality (i.e., low-gravity, high-sulfur crude). The relatively lower price for the high-sulfur crudes has been associated with an ample supply and relatively lower demand due to the limited number of refineries that are able to process this lower-quality feedstock into light products (i.e., motor gasoline, jet fuel, aviation gasoline and diesel fuel). 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 certain fields in Angola, China and the United Kingdom North Sea. (Refer to page FS-10 for the companys 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 during 2008, benchmark prices at Henry Hub averaged about $9 per thousand cubic feet (MCF), compared with about $7 in 2007. At December 31, 2008, and as of mid-February 2009,
the Henry Hub price was about $5.60 and $4.70 per MCF, respectively. 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 lower average sales prices for the companys production of natural gas. (Refer to page FS-10 for the companys 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 higher-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 continues to invest 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 processing facility) are expected to remain 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 or Thailand).
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 companys 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.
Chevrons worldwide net oil-equivalent production in 2008, including volumes produced from oil sands, averaged 2.53 million barrels per day, a decline of about 90,000 barrels per day from 2007 due mainly to the impact of higher prices on volumes recovered under certain production-sharing and variable-royalty agreements outside the United States and damage to production facilities in September 2008 caused by hurricanes Gustav and Ike in the U.S. Gulf of Mexico. (Refer to the discussion of U.S. upstream production trends in the Results of Operations section on page
FS-6. Refer also to the Selected Operating Data table on page
FS-10 for a listing of production volumes for each of the three years ending December 31, 2008.)
The company estimates that oil-equivalent production in 2009 will average approximately 2.63 million barrels per day. This estimate is subject to many uncertainties, including quotas that may be imposed by OPEC, price effects 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 startups, fluctuations in demand for natural gas in various markets, weather conditions that may shut in production, 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. Most of Chevrons 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 production of crude oil and natural gas.
Approximately 20 percent of the companys net oil-equivalent production in 2008 occurred in the OPEC-member countries of Angola, Nigeria and Venezuela and in the Partitioned Neutral Zone between Saudi Arabia and Kuwait. (This production statistic excludes volumes produced in Indonesia, which relinquished its OPEC membership at the end of 2008.) At a meeting on December 17, 2008, OPEC announced a reduction of 4.2 million barrels per day, or 14 percent, from actual September 2008 production of 29 million barrels per day. The reduction became effective January 1, 2009. OPEC quotas did not significantly affect Chevrons production level in 2007 or in 2008. The companys current and future production levels could be affected by the cutbacks announced by OPEC in December 2008.
Refer to the Results of Operations section on pages FS-6 through FS-7 for additional discussion of the companys upstream operations.
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 or other operational events.
Other factors affecting profitability for downstream operations include the reliability and efficiency of the companys 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 companys shipping operations, which are driven by the industrys demand for crude oil and product tankers. Other factors beyond the companys control include the general level of inflation and energy costs to operate the companys refinery and distribution network.
The companys most significant marketing areas are the West Coast of North America, the U.S. Gulf Coast, Latin America, Asia, southern 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, were weak from mid-2007 through mid-2008 due mainly to increasing prices of crude oil used in the refining process that were not always fully recovered through sales prices of refined products. Margins significantly improved in the second half of 2008 as the price of crude oil declined. As part of its downstream strategy to focus on areas of market strength, the company announced plans to sell marketing businesses in several countries. Refer to the discussion in Operating Developments below.
Industry margins in the future may be volatile and are influenced by changes in the price of crude oil used for refinery feedstock and by changes in the supply and demand for crude oil and refined products. The industry supply-and-demand balance can be affected by disruptions at refineries resulting from maintenance programs and unplanned outages, including weather-related disruptions; refined-product inventory levels; and geopolitical events.
Refer to pages FS-7 through FS-8 for additional discussion of the companys 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 section on page FS-8 for additional discussion of chemicals earnings.
Key operating developments and other events during 2008 and early 2009 included the following:
Australia Started production from Train 5 of the 17 percent-owned North West Shelf Venture onshore liquefied-natural-gas (LNG) facility in West Australia, increasing export capacity from about 12 million metric tons annually to more than 16 million. The company also announced plans for an LNG project that initially will have a capacity of 5 million tons per year and process natural gas from Chevrons 100 percent-owned Wheatstone discovery located on the northwest coast of mainland Australia.
Canada Finalized agreements with the government of Newfoundland and Labrador to develop the 27 percent-owned Hebron heavy-oil project off the eastern coast.
Indonesia Achieved first oil at North Duri Field Area 12, which Chevron operates with a 100 percent interest. Maximum total crude-oil production of 34,000 barrels per day is expected in 2012.
Kazakhstan Completed the second phase of a major expansion of production operations and processing facilities at the 50 percent-owned Tengizchevroil affiliate, increasing
total crude-oil production capacity from 400,000 to 540,000 barrels per day.
Middle East Signed an agreement with the Kingdom of Saudi Arabia to extend to 2039 the companys operation of the Kingdoms 50 percent interest in oil and gas resources of the onshore area of the Partitioned Neutral Zone between the Kingdom and the state of Kuwait.
Nigeria Started production offshore at the 68 percent-owned and operated Agbami Field, with total oil production expected to reach a maximum of 250,000 barrels per day by the end of 2009. The company and partners also announced plans 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 2012.
Republic of the Congo Confirmed startup of the 32 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.
United States Began production at the 75 percent-owned and operated Blind Faith project in the deepwater Gulf of Mexico. Total volumes are expected to ramp up during 2009 to approximately 65,000 barrels of crude oil and 55 million cubic feet of natural gas per day.
The company announced plans to sell marketing-related businesses in Brazil, Nigeria, Benin, Cameroon, Republic of the Congo, Côte dIvoire, Togo, Kenya, and Uganda.
Common Stock Dividends Increased the quarterly common stock dividend by 12.1 percent in April 2008 to $0.65 per share. 2008 was the 21st consecutive year that the company increased its annual dividend payment.
Common Stock Repurchase Program Acquired $8.0 billion of common shares in 2008 as part of a $15 billion repurchase program initiated in 2007.
Results of Operations
Major Operating Areas The following section presents the results of operations for the companys business segments upstream, downstream and chemicals as well as for all other, which includes mining, power generation businesses, the various companies and departments that are managed at the corporate level, and the companys investment in Dynegy prior to its sale in May 2007. Income is also presented for the U.S. and international geographic areas of the upstream and downstream business segments. (Refer to Note 9, beginning on page FS-38, for a discussion of the companys reportable segments, as defined in Financial Accounting Standards Board (FASB) Statement No. 131, Disclosures About Segments of an Enterprise and Related Information.) This section should also be read in conjunction with the discussion in Business Environment and Outlook on pages FS-2 through FS-5.
U.S. Upstream Exploration and Production
U.S upstream income of $7.1 billion in 2008 increased $2.6 billion from 2007. Higher average prices for crude oil and natural gas increased earnings by $3.1 billion between periods. Also contributing to the higher earnings were gains of approximately $1 billion on asset sales, including a $600 million gain on an asset-exchange transaction. Partially offsetting these benefits were adverse effects of about $1.6 billion associated with lower oil-equivalent production and higher operating expenses, which included approximately $400 million of expenses resulting from damage to facilities in the Gulf of Mexico caused by hurricanes Gustav and Ike in September.
Income of $4.5 billion in 2007 increased approximately $260 million from 2006. Results in 2007 benefited approximately $700 million from higher prices for crude oil and natural gas liquids. This benefit to income was partially offset by the effects of a decline in oil-equivalent production and an increase in depreciation, operating and exploration expenses.
The companys average realization for crude oil and natural gas liquids in 2008 was $88.43 per barrel, compared with $63.16 in 2007 and $56.66 in 2006. The average natural gas realization was $7.90 per thousand cubic feet in 2008, compared with $6.12 and $6.29 in 2007 and 2006, respectively.
Net oil-equivalent production in 2008 averaged 671,000 barrels per day, down 9.7 percent and 12.1 percent from 2007 and 2006, respectively. The decrease between 2007 and 2008 was mainly due to normal field declines and the adverse impact of the hurricanes. The decline in 2007 from 2006 was due primarily to normal field declines. The net liquids component of oil-equivalent production for 2008 averaged 421,000 barrels per day, down approximately 8 percent from 2007 and down 9 percent compared with 2006. Net natural gas production averaged 1.5 billion cubic feet per day in 2008, down 12 percent from 2007 and down 17 percent from 2006.
Refer to the Selected Operating Data table on page FS-10 for the three-year comparative production volumes in the United States.
International Upstream Exploration and Production
International upstream income of $14.6 billion in 2008 increased $4.3 billion from 2007. Higher prices for crude oil and natural gas increased earnings by $4.9 billion. Partially offsetting the benefit of higher prices was an impact of about $1.8 billion associated with a reduction of crude-oil sales volumes due to timing of certain cargo liftings and higher depreciation and operating expenses. Foreign currency effects benefited earnings by $873 million in 2008, compared with reductions to earnings of $417 million in 2007 and $371 million in 2006.
Income in 2007 of $10.3 billion increased $1.4 billion from 2006. Earnings in 2007 benefited approximately $1.6 billion from higher prices, primarily for crude oil, and $300 million from increased liftings. Non-recurring income-tax items also benefited earnings between periods. These benefits to income were partially offset by the impact of higher operating and depreciation expenses.
The companys average realization for crude oil and natural gas liquids in 2008 was $86.51 per barrel, compared with $65.01 in 2007 and $57.65 in 2006. The average natural gas realization was $5.19 per thousand cubic feet in 2008, compared with $3.90 and $3.73 in 2007 and 2006, respectively.
Net oil-equivalent production of 1.86 million barrels per day in 2008 declined about 1 percent and 2 percent from 2007 and 2006, respectively. The volumes for each year included production from oil sands in Canada. Volumes in 2006 also included production under an operating service agreement in Venezuela until its conversion to a joint-stock company in October of that year. Absent the impact of higher prices on certain production-sharing and variable-royalty agreements, net oil-equivalent production increased between 2007 and 2008. The decline in 2007 from 2006 was associated with the impact of the contract conversion in Venezuela and the impact of higher prices on production-sharing agreements.
The net liquids component of oil-equivalent production was 1.3 million barrels per day in 2008, a decrease of 5 percent from 2007 and 9 percent from 2006. Net natural gas production of 3.6 billion cubic feet per day in 2008 was up 9 percent and 15 percent from 2007 and 2006, respectively.
Refer to the Selected Operating Data table, on page FS-10, for the three-year comparative of international production volumes.
U.S. Downstream Refining, Marketing and Transportation
U.S downstream earnings of $1.4 billion in 2008 increased about $400 million from 2007 due mainly to improved margins on the sale of refined products and gains on derivative commodity instruments. Operating expenses were higher between periods. Income of $966 million in 2007 decreased nearly $1 billion from 2006. The decline was associated mainly with lower refined-product margins and higher planned and unplanned refinery downtime than a year earlier. Operating expenses were also higher in 2007 than in 2006.
Sales volumes of refined products were 1.41 million barrels per day in 2008, a decrease of 3 percent from 2007. The decline was associated with reduced sales of gasoline and fuel oil. Sales volumes of refined products were 1.46 million barrels per day in 2007, a decrease of 3 percent from 2006. The reported sales volume for 2007 was on a different basis than 2006 due to a change in accounting rules that became effective April 1, 2006, for certain purchase-and-sale (buy/ sell) contracts with the same counterparty. Excluding the
impact of this accounting standard, refined-product sales in 2007 decreased 1 percent from 2006. Branded gasoline sales volumes of 601,000 barrels per day in 2008 was down about 4 percent and 2 percent from 2007 and 2006, respectively.
Refer to the Selected Operating Data table on page FS-10 for a three-year comparative of sales volumes of gasoline and other refined products and refinery-input volumes. Refer also to Note 14, Accounting for Buy/Sell Contracts, on page FS-43 for a discussion of the accounting for purchase-and-sale contracts with the same counterparty.
International Downstream Refining, Marketing and Transportation
International downstream income of $2.1 billion in 2008 decreased nearly $500 million from 2007. Earnings in 2007 included gains of approximately $1 billion on the sale of assets, which included an interest in a refinery and marketing assets in the Benelux region of Europe. The $500 million improvement otherwise between years was associated primarily with a benefit from gains on derivative commodity instruments that was only partially offset by the impact of lower margins on the sale of refined products. Foreign currency effects increased earnings by $193 million in 2008, compared with $62 million in 2007. Income in 2007 of $2.5 billion increased $500 million from 2006, largely due to the gains on asset sales. Margins on the sale of refined products in 2007 were up slightly from 2006. Operating expenses were higher, and earnings from the companys shipping operations were lower.
Refined-product sales volumes were 2.02 million barrels per day in 2008, about 1 percent lower than 2007 due mainly to reduced sales of gas oil and fuel oil. Refined product sales volumes were 2.03 million barrels per day in 2007, about 5 percent lower than 2006. The decline in 2007 was largely due to the impact of asset sales and the accounting-standard change for buy/sell contracts. Excluding the accounting change, sales decreased about 4 percent.
Refer to the Selected Operating Data table, on page FS-10, for a three-year comparative of sales volumes of gasoline and other refined products and refinery-input volumes. Refer also to Note 14, Accounting for Buy/Sell Contracts, on page FS-43 for a discussion of the accounting for purchase-and-sale contracts with the same counterparty.
The chemicals segment includes the companys Oronite subsidiary and the 50 percent-owned Chevron Phillips Chemical Company LLC (CPChem). In 2008, earnings were $182 million, compared with $396 million and $539 million in 2007 and 2006, respectively. Earnings declined in 2008 due to lower sales volumes of commodity chemicals by CPChem. Higher expenses for planned maintenance activities also contributed to the earnings decline. Earnings also declined for the companys Oronite subsidiary due to lower volumes and higher operating expenses. In 2007, earnings of $396 million decreased $143 million from 2006 due to the impact of lower margins on the sale of commodity chemicals by CPChem that were only partially offset by improved margins on Oronites sales of additives for lubricants and fuel.
All Other includes mining operations, power generation businesses, worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, alternative fuels and technology companies, and the companys interest in Dynegy prior to its sale in May 2007.
Net charges in 2008 increased $1.4 billion from 2007. Results in 2007 included a $680 million gain on the sale of the companys investment in Dynegy common stock and a loss of approximately $175 million associated with the early redemption of Texaco Capital Inc. bonds. Results in 2008 included net unfavorable
corporate tax items and increased costs of environmental remediation for sites that previously had been closed or sold. Foreign exchange effects also contributed to the increase in net charges between years. Net charges of $26 million in 2007 decreased $490 million from 2006 due mainly to the Dynegy-related gain in 2007.
Consolidated Statement of Income
Comparative amounts for certain income statement categories are shown below:
Sales and other operating revenues increased in the comparative periods due mainly to higher prices for crude oil, natural gas and refined products.
Income from equity affiliates increased in 2008 from 2007 on improved upstream-related earnings at Tengizchevroil (TCO) due to higher prices for crude oil. Lower income from equity affiliates between 2006 and 2007 was mainly due to a decline in earnings from CPChem, Dynegy (sold in May 2007) and downstream affiliates in the Asia-Pacific area. Partially offsetting these declines were improved results for TCO and income for a full year from Petroboscan, which was converted from an operating service agreement to a joint-stock company in October 2006. Refer to Note 12, beginning on page FS-41, for a discussion of Chevrons investments in affiliated companies.
Other income of $2.7 billion in 2008 included gains of approximately $1.3 billion on asset sales. Other income of $2.7 billion in 2007 included net gains of $1.7 billion from asset sales and a loss of $245 million on the early redemption of debt. Interest income was approximately $340 million in 2008 and $600 million in both 2007 and 2006. Foreign currency effects benefited other income by $355 million in 2008 while reducing other income by $352 million and $260 million in 2007 and 2006, respectively.
Crude oil and product purchases in 2008 increased $38.1 billion from 2007 due to higher prices for crude oil, natural gas and refined products. Crude oil and product purchases in 2007 increased more than $5 billion from 2006 due to these same factors.
Operating, selling, general and administrative expenses in 2008 increased approximately $3.7 billion from 2007 primarily due to $1.2 billion of higher costs for employee and contract labor; $800 million of increased costs for materials, services and equipment; $700 million of uninsured losses associated with hurricanes in the Gulf of Mexico in 2008; and an increase of about $300 million for environmental remediation activities. Total expenses were about $3.1 billion higher in 2007 than in 2006. Increases were recorded in a number of categories, including $1.5 billion of higher costs for employee and contract labor.
Exploration expenses in 2008 declined from 2007 due mainly to lower amounts for well write-offs for operations in the United States. Expenses in 2007 were essentially unchanged from 2006.
Depreciation, depletion and amortization expenses increased in 2008 from 2007 largely due to higher depreciation rates for certain crude oil and natural gas producing fields, reflecting completion of higher-cost development projects and asset-retirement obligations. The increase between 2006 and 2007 reflects an increase in charges related to asset write-downs and higher depreciation rates for certain crude oil and natural gas producing fields worldwide.
Taxes other than on income decreased between 2007 and 2008 periods mainly due to lower import duties as a result of the effects of the 2007 sales of the companys Benelux refining and marketing businesses and a decline in import volumes in the United Kingdom. Taxes other than on income increased between 2006 and 2007 due to higher import duties in the companys U.K. downstream operations in 2007.
Interest and debt expense decreased significantly in 2008 because all interest-related amounts were being capitalized. Interest and debt expense in 2007 decreased from 2006 primarily due to lower average debt balances and higher amounts of interest capitalized.
Effective income tax rates were 44 percent in 2008, 42 percent in 2007 and 46 percent in 2006. Rates were higher between 2007 and 2008 primarily due to a greater proportion of income earned in tax jurisdictions with higher income tax rates. In addition, the 2007 period included a relatively low effective tax rate on the sale of the companys investment in Dynegy common stock and the sale of downstream assets in Europe. Rates were lower in 2007 compared with 2006 due mainly to the impact of nonrecurring items in 2007 mentioned above and the absence of 2006 charges related to a tax-law change that increased tax rates on upstream operations in the U.K. North Sea and the settlement of a tax claim in Venezuela. Refer also to the discussion of income taxes in Note 16 beginning on page FS-45.
Selected Operating Data1,2
Liquidity and Capital Resources
Cash, cash equivalents and marketable securities Total balances were $9.6 billion and $8.1 billion at December 31, 2008 and 2007, respectively. Cash provided by operating activities in 2008 was $29.6 billion, compared with $25.0 billion in 2007 and $24.3 billion in 2006.
Cash provided by operating activities was net of contributions to employee pension plans of approximately $800 million, $300 million and $400 million in 2008, 2007 and 2006, respectively. Cash provided by investing activities included proceeds from asset sales of $1.5 billion in 2008, $3.3 billion in 2007 and $1.0 billion in 2006.
At December 31, 2008, restricted cash of $367 million associated with capital-investment projects at the companys Pascagoula, Mississippi, refinery and Angola liquefied natural gas project was invested in short-term marketable securities and reclassified from cash equivalents to a long-term asset on the Consolidated Balance Sheet.
Dividends The company paid dividends of approximately $5.2 billion in 2008, $4.8 billion in 2007 and $4.4 billion in 2006. In April 2008, the company increased its quarterly common stock dividend by 12.1 percent to $0.65 per share.
Debt, capital lease and minority interest obligations Total debt and capital lease balances were $8.9 billion at December 31, 2008, up from $7.2 billion at year-end 2007. The company also had minority interest obligations of $469 million and $204 million at December 31, 2008 and 2007, respectively.
The $1.7 billion increase in total debt and capital lease obligations during 2008 included the net effect of an approximate $2.7 billion increase in commercial paper and $749 million of Chevron Canada Funding Company bonds that matured. The companys debt and capital lease obligations due within one year, consisting primarily of commercial paper and the current portion of long-term debt, totaled $7.8 billion at December 31, 2008, up from $5.5 billion at year-end 2007. Of these amounts, $5.0 billion and $4.4 billion were reclassified to long-term at the end of each period, respectively. At year-end 2008, settlement of these obligations was not expected to require the use of working capital within one year, as the company had the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis.
At year-end 2008, the company had $5 billion in committed credit facilities with various major banks, which permit the refinancing of short-term obligations on a long-term basis. These facilities support commercial-paper borrowing and also can be used for general corporate purposes. The companys practice has been to continually
replace expiring commitments with new commitments on substantially the same terms, maintaining levels management believes appropriate. Terms of new commitments in the future will be subject to market conditions at the time of renewal. Any borrowings under the facilities would be
unsecured indebtedness at interest rates based on London Interbank Offered Rate or an average of base lending rates published by specified banks and on terms reflecting the companys strong credit rating. No borrowings were outstanding under these facilities at December 31, 2008. In addition, the company has an automatic shelf registration statement that expires in March 2010 for an unspecified amount of nonconvertible debt securities issued or guaranteed by the company. In January 2009, the companys Board of Directors authorized the issuance of one or more series of notes or debentures in an aggregate amount up to $5 billion for a term not to exceed ten years.
At December 31, 2008, the company had outstanding public bonds issued by Chevron Corporation Profit Sharing/Savings Plan Trust Fund, Texaco Capital Inc. and Union Oil Company of California. All of these securities are guaranteed by Chevron Corporation and are rated AA by Standard and Poors Corporation and Aa1 by Moodys Investors Service. The companys U.S. commercial paper is rated A-1+ by Standard and Poors and P-1 by Moodys. All of these ratings denote high-quality, investment-grade securities.
The companys future debt level is dependent primarily on results of operations, the capital-spending program and cash that may be generated from asset dispositions. During periods of low prices for crude oil and natural gas and narrow margins for refined products and commodity chemicals, the company has the flexibility to increase borrowings and/or modify capital-spending plans to continue paying the common stock dividend and maintain the companys high-quality debt ratings.
Common stock repurchase program In September 2007, the company authorized the acquisition of up to $15 billion of additional common shares from time to time at prevailing prices, as permitted by securities laws and other legal requirements and subject to market conditions and other factors. The program is for a period of up to three years and may be discontinued at any time. Through December 31, 2008, 119 million shares had been acquired under the program for $10.1 billion, including $8.0 billion in 2008. These amounts include shares acquired in October 2008 as part of an asset-exchange transaction described in Note 2 beginning on page FS-34. The company did not acquire any shares in early 2009 and does not plan to acquire any shares in the 2009 first quarter.
Capital and exploratory expenditures Total reported expenditures for 2008 were $22.8 billion, including $2.3 billion for the companys share of affiliates expenditures, which did not require cash outlays by the company. In 2007 and 2006, expenditures were $20.0 billion and $16.6 billion, respectively, including the companys 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, 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 companys continuing focus on opportunities that are available outside the United States.
The company estimates that in 2009, 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 this amount outside the United States. Spending in 2009 is primarily targeted for exploratory prospects in the deepwater U.S. Gulf of Mexico, western Africa, and the Gulf of Thailand and major development projects in Angola, Australia, Brazil, Indonesia, Nigeria, Thailand and the deepwater U.S. Gulf of Mexico. Also included are one-time payments associated with upstream operating agreements in China and the Partitioned Neutral Zone between Saudi Arabia and Kuwait.
Capital and Exploratory Expenditures
Worldwide downstream spending in 2009 is estimated at $4.3 billion, with about $2.0 billion for projects in the United States. Capital projects include upgrades to refineries in the United States and South Korea and construction of a gas-to-liquids facility in support of associated upstream projects.
Investments in chemicals, technology and other corporate businesses in 2009 are budgeted at $1.0 billion. Technology investments include projects related to unconventional hydrocarbon technologies, oil and gas reservoir management, and gas-fired and renewable power generation.
Pension Obligations In 2008, the companys pension plan contributions were $839 million (including $577 million to the U.S. plans). The company estimates contributions in 2009 will be approximately $800 million. Actual contribution amounts are dependent upon plan-investment results, changes in pension obligations, regulatory requirements and other economic factors. Additional funding may be required if investment returns are insufficient to offset increases in plan obligations. Refer also to the discussion of pension accounting in Critical Accounting Estimates and Assumptions, beginning on page FS-18.
Current Ratio current assets divided by current liabilities. The current ratio in all periods was adversely affected by the fact that Chevrons inventories are valued on a Last-In, First-Out basis. At year-end 2008, the book value of inventory was lower than replacement costs, based on average acquisition costs during the year, by approximately $9 billion.
Interest Coverage Ratio income before income tax expense, plus interest and debt expense and amortization of capitalized interest, divided by before-tax interest costs. The companys interest coverage ratio was higher between 2007 and 2008 and between 2006 and 2007, primarily due to higher before-tax income and lower average debt balances in each of the subsequent years.
Debt Ratio total debt as a percentage of total debt plus equity. The increase between 2007 and 2008 was primarily due to higher debt. The decrease between 2006 and 2007 was due to lower debt and higher stockholders equity balance.
Guarantees, Off-Balance-Sheet Arrangements and Contractual Obligations, and Other Contingencies
The companys guarantee of approximately $600 million is associated with certain payments under a terminal-use agreement entered into by a company affiliate. The terminal is expected to be operational by 2012. Over the approximate 16-year term of the guarantee, the maximum guarantee amount will be reduced as certain fees are paid by the affiliate.
There are numerous cross-indemnity agreements with the affiliate and the other partners to permit recovery of any amounts paid under the guarantee. Chevron has recorded no liability for its obligation under this guarantee.
Indemnifications The company provided certain indemnities of contingent liabilities of Equilon and Motiva to Shell and Saudi Refining, Inc., in connection with the February 2002 sale of the companys interests in those investments. The company would be required to perform if the indemnified liabilities become actual losses. Were that to occur, the company could be required to make future payments up to $300 million. Through the end of 2008, the company had paid $48 million under these indemnities and continues to be obligated for possible additional indemnification payments in the future.
The company has also provided indemnities relating to contingent environmental liabilities related to assets originally contributed by Texaco to the Equilon and Motiva joint ventures and environmental conditions that existed prior to the formation of Equilon and Motiva or that occurred during the period of Texacos ownership interest in the joint ventures. In general, the environmental conditions or events that are subject to these indemnities must have arisen prior to December 2001. Claims must be asserted no later than February 2009 for Equilon indemnities and no later than February 2012 for Motiva indemnities. Under the terms of these indemnities, there is no maximum limit on the amount of potential future payments. In February 2009, Shell delivered a letter to the company purporting to preserve unmatured claims for certain Equilon indemnities. The letter itself provides no estimate of the ultimate claim amount, and management does not believe the letter provides a basis to estimate the amount, if any, of a range of loss or potential range of loss with respect to Equilon or the Motiva indemnities. The company posts no assets as collateral and has made no payments under the indemnities.
The amounts payable for the indemnities described above are to be net of amounts recovered from insurance carriers and others and net of liabilities recorded by Equilon or Motiva prior to September 30, 2001, for any applicable incident.
In the acquisition of Unocal, the company assumed certain indemnities relating to contingent environmental liabilities associated with assets that were sold in 1997. Under the indemnification agreement, the companys liability is unlimited until April 2022, when the indemnification expires. The acquirer shares in certain environmental remediation costs up to a maximum obligation of $200 million, which had not been reached as of December 31, 2008.
Securitization During 2008, the company terminated the program used to securitize downstream-related trade accounts receivable. At year-end 2007, the balance of securitized receivables was $675 million. As of December 31, 2008, the company had no other securitization arrangements in place.
Minority Interests The company has commitments of $469 million related to minority interests in subsidiary companies.
Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements The company and its subsidiaries have certain other contingent liabilities relating to long-term unconditional purchase obligations and commitments, including throughput and take-or-pay agreements, some of which relate to suppliers financing arrangements. The agreements typically provide goods and services, such as pipeline and storage capacity, drilling rigs, utilities, and petroleum products, to be used or sold in the ordinary course of the companys business. The aggregate approximate amounts of required payments under these various commitments are: 2009 $6.4 billion; 2010 $4.0 billion; 2011 $3.6 billion; 2012 $1.5 billion; 2013 $1.3 billion; 2014 and after $4.3 billion. A portion of these commitments may ultimately be shared with project partners. Total payments under the agreements were approximately $5.1 billion in 2008, $3.7 billion in 2007 and $3.0 billion in 2006.
The following table summarizes the companys significant contractual obligations:
Financial and Derivative Instruments
The market risk associated with the companys portfolio of financial and derivative instruments is discussed below. The estimates of financial exposure to market risk discussed below do not represent the companys projection of future market changes. The actual impact of future market changes could differ materially due to factors discussed elsewhere in this report, including those set forth under the heading Risk
Factors in Part I, Item 1A, of the companys 2008 Annual Report on Form 10-K.
Derivative Commodity Instruments Chevron is exposed to market risks related to the price volatility of crude oil, refined products, natural gas, natural gas liquids, liquefied natural gas and refinery feedstocks.
The company uses derivative commodity instruments to manage these exposures on a portion of its activity, including firm commitments and anticipated transactions for the purchase, sale and storage of crude oil, refined products, natural gas, natural gas liquids and feedstock for company refineries. The company also uses derivative commodity instruments for limited trading purposes. The results of this activity were not material to the companys financial position, net income or cash flows in 2008.
The companys market exposure positions are monitored and managed on a daily basis by an internal Risk Control group to ensure compliance with the companys risk management policies that have been approved by the Audit Committee of the companys Board of Directors.
The derivative instruments used in the companys risk management and trading activities consist mainly of futures, options and swap contracts traded on the NYMEX (New York Mercantile Exchange) and on electronic platforms of ICE (Inter-Continental Exchange) and GLOBEX (Chicago Mercantile Exchange). In addition, crude oil, natural gas and refined-product swap contracts and option contracts are entered into principally with major financial institutions and other oil and gas companies in the over-the-counter markets.
Virtually all derivatives beyond those designated as normal purchase and normal sale contracts are recorded at fair value on the Consolidated Balance Sheet with resulting gains and losses reflected in income. Fair values are derived principally from published market quotes and other independent third-party quotes. The change in fair value from Chevrons derivative commodity instruments in 2008 was a quarterly average increase of $160 million in total assets and a quarterly average decrease of $1 million in total liabilities.
The company uses a Value-at-Risk (VaR) model to estimate the potential loss in fair value on a single day from the effect of adverse changes in market conditions on derivative instruments held or issued, which are recorded on the balance sheet at December 31, 2008, as derivative instruments in accordance with FAS Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended (FAS 133). VaR is the maximum loss not to be exceeded within a given probability or confidence level over a given period of time. The companys VaR model uses the Monte Carlo simulation method that involves generating hypothetical scenarios from the specified probability distribution and constructing a full distribution of a portfolios potential values.
The VaR model utilizes an exponentially weighted moving average for computing historical volatilities and correlations, a 95 percent confidence level, and a one-day holding period. That is, the companys 95 percent, one-day VaR corresponds to the unrealized loss in portfolio value that would not be exceeded on average more than one in every 20 trading days, if the portfolio were held constant for one day.
The one-day holding period is based on the assumption that market-risk positions can be liquidated or hedged within one day. For hedging and risk management, the company uses conventional exchange-traded instruments such as futures and options as well as non-exchange-traded swaps, most of which can be liquidated or hedged effectively within one day. The table below presents the 95 percent/one-day VaR for each of the companys primary risk exposures in the area of derivative commodity instruments at December 31, 2008 and 2007. The higher amounts in 2008 were associated with an increase in price volatility for these commodities during the year.
Foreign Currency The company enters into forward exchange contracts, generally with terms of 180 days or less, to manage some of its foreign currency exposures. These exposures include revenue and anticipated purchase transactions, including foreign currency capital expenditures and lease commitments, forecasted to occur within 180 days. The forward exchange contracts are recorded at fair value on the balance sheet with resulting gains and losses reflected in income.
The aggregate effect of a hypothetical 10 percent increase in the value of the U.S. dollar at year-end 2008 would be a reduction in the fair value of the foreign exchange contracts of approximately $100 million. The effect would be the opposite for a hypothetical 10 percent decrease in the value of the U.S. dollar at year-end 2008.
Interest Rates The company enters into interest-rate swaps from time to time as part of its overall strategy to manage the interest rate risk on its debt. Under the terms of the swaps, net cash settlements are based on the difference between fixed-rate and floating-rate interest amounts calculated by reference to agreed notional principal amounts. Interest rate swaps related to a portion of the companys fixed-rate debt are accounted for as fair value hedges. Interest rate swaps related to floating-rate debt are recorded at fair value on the balance sheet with resulting gains and losses reflected in income. At year-end 2008, the company had no interest-rate swaps on floating-rate debt. The companys only interest-rate swaps on fixed-rate debt matured in January 2009.
Transactions With Related Parties
Chevron enters into a number of business arrangements with related parties, principally its equity affiliates. These arrangements include long-term supply or offtake agreements and long-term purchase agreements. Refer to Other Information in Note 12 of the Consolidated Financial Statements, page FS-42, for further discussion. Management believes these agreements have been negotiated on terms consistent with those that would have been negotiated with an unrelated party.
Litigation and Other Contingencies
MTBE Chevron and many other companies in the petroleum industry have used methyl tertiary butyl ether (MTBE) as a gasoline additive. In October 2008, 59 cases were settled in which the company was a party and which related to the use of MTBE in certain oxygenated gasolines and the alleged seepage of MTBE into groundwater. The terms of this agreement are confidential and not material to the companys results of operations, liquidity or financial position. Chevron is a party to 37 other pending lawsuits and claims, the majority of which involve numerous other petroleum marketers and refiners. Resolution of these lawsuits and claims may ultimately require the company to correct or ameliorate the alleged effects on the environment of prior release of MTBE by the company or other parties. Additional lawsuits and claims related to the use of MTBE, including personal-injury claims, may be filed in the future. The settlement of the 59 lawsuits did not set any precedents related to standards of liability to be used to judge the merits of the claims, corrective measures required or monetary damages to be assessed for the remaining lawsuits and claims or future lawsuits and claims. As a result, the companys ultimate exposure related to pending lawsuits and claims is not currently determinable, but could be material to net income in any one period. The company no longer uses MTBE in the manufacture of gasoline in the United States.
RFG Patent Fourteen purported class actions were brought by consumers who purchased reformulated gasoline (RFG) from January 1995 through August 2005, alleging that Unocal misled the California Air Resources Board into adopting standards for composition of RFG that overlapped with Unocals undisclosed and pending patents. The parties agreed to a settlement that calls for, among other things, Unocal to pay $48 million and for the establishment of a cy pres fund to administer payout of the award. The court approved the final settlement in November 2008.
Ecuador Chevron is a defendant in a civil lawsuit before the Superior Court of Nueva Loja in Lago Agrio, Ecuador, brought in May 2003 by plaintiffs who claim to be representatives of certain residents of an area where an oil production consortium formerly had operations. The lawsuit alleges damage to the environment from the oil exploration and production operations, and seeks unspecified damages to fund environmental remediation and restoration of the alleged environmental harm, plus a health monitoring program. Until 1992, Texaco Petroleum Company (Texpet), a subsidiary of Texaco Inc., was a minority member of this consortium with Petroecuador, the Ecuadorian state-owned
oil company, as the majority partner; since 1990, the operations have been conducted solely by Petroecuador. At the conclusion of the consortium and following an independent third-party environmental audit of the concession area, Texpet entered into a formal agreement with the Republic of Ecuador and Petroecuador for Texpet to remediate specific sites assigned by the government in proportion to Texpets ownership share of the consortium. Pursuant to that agreement, Texpet conducted a three-year remediation program at a cost of $40 million. After certifying that the sites were properly remediated, the government granted Texpet and all related corporate entities a full release from any and all environmental liability arising from the consortium operations.
Based on the history described above, Chevron believes that this lawsuit lacks legal or factual merit. As to matters of law, the company believes first, that the court lacks jurisdiction over Chevron; second, that the law under which plaintiffs bring the action, enacted in 1999, cannot be applied retroactively to Chevron; third, that the claims are barred by the statute of limitations in Ecuador; and, fourth, that the lawsuit is also barred by the releases from liability previously given to Texpet by the Republic of Ecuador and Petroecuador. With regard to the facts, the company believes that the evidence confirms that Texpets remediation was properly conducted and that the remaining environmental damage reflects Petroecuadors failure to timely fulfill its legal obligations and Petroecuadors further conduct since assuming full control over the operations.
In April 2008, a mining engineer appointed by the court to identify and determine the cause of environmental damage, and to specify steps needed to remediate it, issued a report recommending that the court assess $8 billion, which would, according to the engineer, provide financial compensation for purported damages, including wrongful death claims, and pay for, among other items, environmental remediation, health care systems, and additional infrastructure for Petroecuador. The engineers report also asserted that an additional $8.3 billion could be assessed against Chevron for unjust enrichment. The engineers report is not binding on the court. Chevron also believes that the engineers work was performed and his report prepared in a manner contrary to law and in violation of the courts orders. Chevron submitted a rebuttal to the report in which it asked the court to strike the report in its entirety. In November 2008, the engineer revised the report and, without additional evidence, recommended an increase in the financial compensation for purported damages to a total of $18.9 billion and an increase in the assessment for purported unjust enrichment to a total of $8.4 billion. Chevron submitted a rebuttal to the revised report, and Chevron will continue a vigorous defense of any attempted imposition of liability.
Management does not believe an estimate of a reasonably possible loss (or a range of loss) can be made in this case. Due to the defects associated with the engineers report, management does not believe the report itself has any utility in calculating a reasonably possible loss (or a range of loss). Moreover, the highly uncertain legal environment surrounding the case provides no basis for management to
estimate a reasonable possible loss (or a range of loss).
Environmental The company is subject to loss contingencies pursuant to environmental laws and regulations that in the future may require the company to take action to correct or ameliorate the effects on the environment of prior release of chemicals or petroleum substances, including MTBE, by the company or other parties. Such contingencies may exist for various sites, including, but not limited to, federal Superfund sites and analogous sites under state laws, refineries, crude oil fields, service stations, terminals, land development areas, and mining operations, whether operating, closed or divested. These future costs are not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the companys liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties.
Although the company has provided for known environmental obligations that are probable and reasonably estimable, the amount of additional future costs may be material to results of operations in the period in which they are recognized. The company does not expect these costs will have a material effect on its consolidated financial position or liquidity. Also, the company does not believe its obligations to make such expenditures have had, or will have, any significant impact on the companys competitive position relative to other U.S. or international petroleum or chemical companies.
The following table displays the annual changes to the companys before-tax environmental remediation reserves, including those for federal Superfund sites and analogous sites under state laws.
Included in the $1,818 million year-end 2008 reserve balance were remediation activities of 248 sites for which
the company had been identified as a potentially responsible party or otherwise involved in the remediation by the U.S. Environmental Protection Agency (EPA) or other regulatory agencies under the provisions of the federal Superfund law or analogous state laws. The companys remediation reserve for these sites at year-end 2008 was $120 million. The federal Superfund law and analogous state laws provide for joint and several liability for all responsible parties. Any future actions by the EPA or other regulatory agencies to require Chevron to assume other potentially responsible parties costs at designated hazardous waste sites are not expected to have a material effect on the companys consolidated financial position or liquidity.
Of the remaining year-end 2008 environmental reserves balance of $1,698 million, $968 million related to current and former sites for the companys U.S. downstream operations, including refineries and other plants, marketing locations (i.e., service stations and terminals), and pipelines. The remaining $730 million was associated with various sites in international downstream ($117 million), upstream ($390 million), chemicals ($154 million) and other ($69 million). Liabilities at all sites, whether operating, closed or divested, were primarily associated with the companys plans and activities to remediate soil or groundwater contamination or both. These and other activities include one or more of the following: site assessment; soil excavation; offsite disposal of contaminants; onsite containment, remediation and/or extraction of petroleum hydrocarbon liquid and vapor from soil; groundwater extraction and treatment; and monitoring of the natural attenuation of the contaminants.
The company manages environmental liabilities under specific sets of regulatory requirements, which in the United States include the Resource Conservation and Recovery Act and various state or local regulations. No single remediation site at year-end 2008 had a recorded liability that was material to the companys financial position, results of operations or liquidity.
It is likely that the company will continue to incur additional liabilities, beyond those recorded, for environmental remediation relating to past operations. These future costs are not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the companys liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties.
The company accounts for asset retirement obligations in accordance with FASB Statement No. 143, Accounting for Asset Retirement Obligations (FAS 143). Under FAS 143, the fair value of a liability for an asset retirement obligation is recorded when there is a legal obligation associated with the retirement of long-lived assets and the liability can be
reasonably estimated. The liability balance of approximately $9.4 billion for asset retirement obligations at year-end 2008 related primarily to upstream properties.
For the companys other ongoing operating assets, such as refineries and chemicals facilities, no provisions are made for exit or cleanup costs that may be required when such assets reach the end of their useful lives unless a decision to sell or otherwise abandon the facility has been made, as the indeterminate settlement dates for the asset retirements prevent estimation of the fair value of the asset retirement obligation.
Refer also to Note 24, beginning on page FS-58, related to FAS 143 and the companys adoption in 2005 of FASB Interpretation No. (FIN) 47, Accounting for Conditional Asset Retirement Obligations An Interpretation of FASB Statement No. 143 (FIN 47), and the discussion of Environmental Matters below.
Income Taxes The company calculates its income tax expense and liabilities quarterly. These liabilities generally are subject to audit and are not finalized with the individual taxing authorities until several years after the end of the annual period for which income taxes have been calculated. Refer to Note 16 beginning on page FS-45 for a discussion of the periods for which tax returns have been audited for the companys major tax jurisdictions and a discussion for all tax jurisdictions of the differences between the amount of tax benefits recognized in the financial statements and the amount taken or expected to be taken in a tax return. The company does not expect that settlement of income tax liabilities associated with uncertain tax positions will have a material effect on its results of operations, consolidated financial position or liquidity.
The Emergency Economic Stabilization Act of 2008, which contained a number of energy and tax-related provisions, known as the Energy Improvement and Extension Act of 2008 (the Act), was signed into U.S. law in October 2008. The Act includes two provisions that affect Chevrons tax liability, beginning in the fourth quarter of 2008. The Act freezes at 6 percent the domestic manufacturers deduction on income from U.S. oil and gas operations that was scheduled to increase to 9 percent in 2010. Effective in 2009, the Act expands the current foreign tax credit (FTC) limitation for Foreign Oil and Gas Extraction Income to also include foreign downstream income, known as Foreign Oil Related Income. This change is expected to impact Chevrons utilization of FTCs.
Suspended Wells The company suspends the costs of exploratory wells pending a final determination of the commercial potential of the related crude oil and natural gas fields. The ultimate disposition of these well costs is dependent on the results of future drilling activity or development decisions or both. At December 31, 2008, the company had approximately $2.1 billion of suspended exploratory wells included in properties, plant and equipment, an increase of $458 million from 2007. The 2007 balance reflected an increase of $421 million from 2006.
The future trend of the companys exploration expenses can be affected by amounts associated with well write-offs, including wells that had been previously suspended pending determination as to whether the well had found reserves
that could be classified as proved. The effect on exploration expenses in future periods of the $2.1 billion of suspended wells at year-end 2008 is uncer