Chevron Corporation 10-K 2010
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, 2009
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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 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 $132,865,210,015 (As of June 30, 2009)
Number of Shares of Common Stock outstanding as of February 19, 2010 2,008,352,638
DOCUMENTS INCORPORATED BY REFERENCE
(To The Extent Indicated Herein)
Notice of the 2010 Annual Meeting and 2010 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, in connection with the companys 2010 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: changing crude-oil and natural-gas prices; changing 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 the 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 other pending or future litigation; the companys future acquisition or disposition of assets and 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 through 32 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,* 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 and converting natural gas 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. Chemicals 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-23 and E-24. As of December 31, 2009, Chevron had approximately 64,000 employees (including about 4,000 service station employees). Approximately 31,500 employees (including about 3,500 service station employees), or 49 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, 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 of 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 and national petroleum companies in the sale or acquisition of various goods or services in many national and international markets.
Refer to pages FS-2 through FS-9 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.
* 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. In the upstream, the companys strategies are to grow profitably in core areas, build new legacy positions and commercialize the companys equity natural-gas resource base while growing a high-impact global gas business. In the downstream, the strategies are to improve returns and selectively grow, with a focus on integrated value creation. The company also continues to invest in renewable-energy technologies, with an objective of capturing profitable positions.
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, 2009, and assets as of the end of 2009 and 2008 for the United States and the companys international geographic areas are in Note 11 to the Consolidated Financial Statements beginning on page FS-40. 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-43 through FS-45.
Total expenditures for 2009 were $22.2 billion, including $1.6 billion for the companys share of equity-affiliate expenditures. In 2008 and 2007, expenditures were $22.8 billion and $20 billion, respectively, including the companys share of affiliates expenditures of $2.3 billion in both periods.
Of the $22.2 billion in expenditures for 2009, about three-fourths, or $17.1 billion, was related to upstream activities. Approximately the same percentage was also expended for upstream operations in 2008 and 2007. International upstream accounted for about 80 percent of the worldwide upstream investment in 2009 and about 70 percent in 2008 and 2007, reflecting the companys continuing focus on opportunities available outside the United States.
In 2010, the company estimates capital and exploratory expenditures will be $21.6 billion, including $1.6 billion of spending by affiliates. About 80 percent of the total, or $17.3 billion, is budgeted for exploration and production activities, with $13.2 billion of that amount for projects outside the United States.
Refer also to a discussion of the companys capital and exploratory expenditures on page FS-12.
The table on the following page summarizes the net production of liquids and natural gas for 2009 and 2008 by the company and its affiliates.
Net Production of Crude Oil and Natural Gas Liquids and Natural Gas1,2
Worldwide oil-equivalent production, including volumes from oil sands (refer to footnote 2 above), was 2.7 million barrels per day, up about 7 percent from 2008. The increase was mostly associated with the start-up of the Blind Faith and Tahiti fields in the U.S. Gulf of Mexico in late 2008 and the second quarter 2009, respectively, the commencement of operations in the third quarter 2008 at the Agbami Field in Nigeria, and the expansion at Tengiz in Kazakhstan. Refer to the Results of Operations section beginning on page FS-6 for a detailed discussion of the factors explaining the 2007-2009 changes in production for crude oil and natural gas liquids, and natural gas.
The company estimates that its average worldwide oil-equivalent production in 2010 will be approximately 2.73 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 crude-oil and natural-gas development projects.
Refer to Table IV on page FS-69 for the companys average sales price per barrel of crude oil, condensate and natural gas liquids and per thousand cubic feet of natural gas produced and the average production cost per oil-equivalent barrel for 2009, 2008 and 2007.
The following table summarizes gross and net productive wells at year-end 2009 for the company and its affiliates:
Refer to Table V beginning on page FS-69 for a tabulation of the companys proved net crude-oil and natural-gas reserves by geographic area, at the beginning of 2007 and each year-end from 2007 through 2009, and an accompanying discussion of major changes to proved reserves by geographic area for the three-year period ending December 31, 2009. During 2009, the company provided crude-oil and natural-gas reserves estimates for 2008 to the Department of Energy, Energy Information Administration (EIA) that agree with the 2008 reserve volumes in Table V. This reporting fulfilled the requirement that such estimates be consistent with, and not differ more than 5 percent from, the information furnished to the Securities and Exchange Commission (SEC) in the companys 2008 Annual Report on Form 10-K. During 2010, the company will file estimates of crude-oil and natural-gas reserves with the Department of Energy, EIA, consistent with the 2009 reserve data reported in Table V.
The net proved-reserve balances at the end of each of the three years 2007 through 2009 are shown in the table below:
At December 31, 2009, the company owned or had under lease or similar agreements undeveloped and developed crude-oil and natural-gas properties located throughout the world. The geographical distribution of the companys acreage is shown in the following table.
Acreage1,2 at December 31, 2009
(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 has no fixed and determinable delivery commitments to third-parties or affiliates.
Outside the United States, the company is contractually committed to deliver to third parties a total of 821 billion cubic feet of natural gas from 2010 through 2012 from Australia, 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 Australia, Colombia, Denmark and the Philippines.
Refer to Table I on page FS-64 for details associated with the companys development expenditures and costs of proved property acquisitions for 2009, 2008 and 2007.
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, 2009. 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, 2009. 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-64 for detail of the companys exploration expenditures and costs of unproved property acquisitions for 2009, 2008 and 2007.
Chevrons 2009 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-42.
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 2009 was 717,000 barrels per day.
In California, the company has significant production in the San Joaquin Valley. In 2009, average net oil-equivalent production was 211,000 barrels per day, composed of 191,000 barrels of crude oil, 91 million cubic feet of natural gas and 5,000 barrels of natural gas liquids. Approximately 84 percent of the crude-oil production is considered heavy oil (typically with API gravity lower than 22 degrees).
Average net oil-equivalent production during 2009 for the companys combined interests in the Gulf of Mexico shelf and deepwater areas, and the onshore fields in the region was 243,000 barrels per day. The daily oil-equivalent production comprised 149,000 barrels of crude oil, 484 million cubic feet of natural gas and 14,000 barrels of natural gas liquids.
equipment, subsea equipment and water injection wells. Tahiti has an estimated production life of 30 years. As of the end of 2009, proved reserves had been recognized for the first development phase of the Tahiti Field.
The company is participating in the ultra-deepwater Perdido Regional Development. The project encompasses the installation of a producing host facility to service multiple fields, including Chevrons 33.3 percent-owned Great White, 60 percent-owned Silvertip and 57.5 percent-owned Tobago. Chevron has a 37.5 percent interest in the Perdido Regional Host. All of these fields and the production facility are partner-operated. Activities during 2009 included installation of the topsides on the spar, installation of umbilicals, hook-up and commissioning of the facility systems, and ongoing development drilling. First oil is expected in the first half of 2010, with the facility designed to handle 130,000 barrels of oil-equivalent per day. The project has an expected life of approximately 25 years. Proved reserves have been recognized for the project.
The company has a 60 percent-owned and operated interest in Big Foot. Two successful appraisal wells have been drilled, the most recent in the first quarter 2009. The company also acquired the rights to an adjacent block during 2009. The project entered front-end engineering and design (FEED) in October 2009 and a final investment decision is expected in late 2010. Total maximum production from the project is expected to be 63,000 barrels of oil-equivalent per day. At the end of 2009, proved reserves had not been recognized.
The Caesar and Tonga partnerships for properties located in a number of blocks in the Green Canyon area have formed a unit agreement for the area, with Chevron having a 20.3 percent nonoperated working interest. A final investment decision on the joint Caesar-Tonga project was made in the first quarter 2009. Development plans include four wells and a subsea tie-back to a nearby third-party production facility. Two development sidetracks were completed during the year. Proved reserves have been recognized for the project and first oil is expected in 2011.
The Jack and St. Malo fields are located within 25 miles of each other and are being considered for joint development. Chevron has a 50 percent-owned interest in Jack and a 51 percent-owned interest in St. Malo, following the anticipated acquisition of an additional 9.8 percent equity interest in St. Malo in March 2010. Both fields are company operated. The project entered FEED in May 2009 and a final investment decision is expected in late 2010. The facility is planned to have an initial design capacity of 150,000 barrels of oil-equivalent per day and start-up is expected in 2014. At the end of 2009, proved reserves had not been recognized.
Deepwater exploration activities in 2009 and early 2010 included participation in 10 exploratory wells five wildcat, three appraisal and two delineation. Exploratory work included the following:
At the end of 2009, the company had not 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 contracted capacity of 1 billion cubic feet per day at the third-party Sabine Pass liquefied natural gas (LNG) regasification terminal in Louisiana. The 20-year capacity reservation agreement became effective in July 2009 and enables import of natural gas for the North America market. In September 2009, Chevron began to utilize a portion of the reserved capacity under this agreement.
Chevron has also contracted 1.6 billion cubic feet per day of capacity in a third-party pipeline system connecting the Sabine Pass LNG terminal to the natural-gas pipeline grid. The new pipeline, which was placed in service in July 2009, provides access to two major salt dome storage fields and 10 major interstate pipeline systems, including an interconnect with Chevrons Sabine Pipeline, which connects to the Henry Hub. An interconnect to Chevrons Bridgeline Pipeline is scheduled to be completed in the third quarter 2010. The Henry Hub interconnects to nine interstate and four intrastate pipelines and is the pricing point for natural gas futures contracts traded on the New York Mercantile Exchange.
Outside California and the Gulf of Mexico, the company manages operations across the mid-continental United States and Alaska. During 2009, the companys U.S. production outside California and the Gulf of Mexico averaged 263,000 net oil-equivalent barrels per day, composed of 94,000 barrels of crude oil, 824 million cubic feet of natural gas and 31,000 barrels of natural gas liquids.
In the Piceance Basin in northwestern Colorado, additional production came on line in September 2009 from the companys 100 percent-owned and operated natural-gas development. Development drilling, which began in 2007, surpassed 190 wells in 2009, with 81 completed wells available to supply natural gas to the central processing facility. Construction of compression and dehydration facilities to produce 65 million cubic feet per day of natural gas was completed in the third quarter 2009. Future work is expected to be completed in multiple stages. The full development plan includes drilling more than 2,000 wells from multi-well pads over the next 30 to 40 years. Proved reserves for subsequent stages of the project had not been recognized at year-end 2009.
In Africa, the company is engaged in exploration and production activities in Angola, Chad, Democratic Republic of the Congo, Nigeria and Republic of the Congo. Net oil-equivalent production in Africa averaged 433,000 barrels per day during 2009.
In the Greater Vanza/Longui Area of Block 0, development concept selection was under way and continued into 2010. FEED is planned for 2011. FEED activities continued on the south extension of the NDola Field development. At year-end 2009, no proved reserves had been recognized for these projects.
Four gas management projects in Block 0 are expected to eliminate routine flaring of natural gas by injecting excess natural gas into various reservoirs. The Takula Flare and Relief Modification Project and the Cabinda Gas Plant Project entered service in June 2009 and December 2009, respectively. These projects are expected to reduce flaring by up to 60 million cubic feet per day. Work continued on the Nemba Enhanced Secondary Recovery and Flare Reduction Project and the Malongo Flare and Relief Modification Project, which are scheduled for start-up in the fourth quarter 2010 and in 2011, respectively.
Also in Block 0, a successful two-well exploration and appraisal program was completed. The exploration well was completed in March 2009, and the appraisal well was completed in May 2009. Drilling began on another exploration well in November 2009 and was completed in the first quarter 2010. The results are under evaluation.
In the 31 percent-owned Block 14, net production in 2009 averaged 33,000 barrels of liquids per day from the Benguela Belize Lobito Tomboco development and the Kuito, Tombua and Landana fields. Development and production rights for the various fields in Block 14 expire between 2027 and 2029.
Development of the Tombua and Landana fields continued in 2009. First production occurred in August 2009 from new production facilities that were installed in late 2008. Proved developed reserves were recognized at start of production. Development drilling is expected to continue, with maximum total daily production of 100,000 barrels of crude oil anticipated in 2011.
During 2009, studies to evaluate development alternatives for the Lucapa Field continued. The project is expected to enter FEED in the fourth quarter 2010. A successful appraisal well was completed in the fourth quarter 2009 in the Malange area. As of the end of 2009, development of the Negage Field was suspended until cooperative arrangements between Angola and Democratic Republic of the Congo could be finalized. At the end of 2009, proved reserves had not been recognized for these projects.
The 39.2 percent-owned and operated Malongo Terminal Oil Export project was completed in November 2009. The new export system more than doubled export capacity from the area, which includes Blocks 0 and 14. In the 20 percent-owned Block 2 and the 16.3 percent-owned FST areas, combined production during 2009 averaged 3,000 barrels of net liquids per day.
Equity Affiliate Operations: In addition to the exploration and producing activities in Angola, Chevron has a 36.4 percent ownership interest in the Angola LNG affiliate that began construction in early 2008 of an onshore natural gas liquefaction plant located in Soyo, Angola. The plant is designed to process more than 1 billion cubic feet of natural gas per day. Construction continued on schedule during 2009 with plant start-up scheduled for 2012. The life of the LNG plant is estimated to be in excess of 20 years. Proved reserves have been recognized for the producing operations associated with this project.
Angola Republic of the Congo Joint Development Area: Chevron operates and holds a 31.3 percent interest in the Lianzi Development Area located between Angola and Republic of the Congo. In late 2008, the development project entered FEED, which continued through 2009. No proved reserves have been recognized for Lianzi.
Republic of the Congo: Chevron has a 31.5 percent nonoperated working interest in the Nkossa, Nsoko and Moho-Bilondo exploitation permits and a 29.3 percent nonoperated working interest in the Kitina exploitation permit, all of which are offshore. The development and production rights for Nkossa, Nsoko and Kitina expire in 2027, 2018 and 2019, respectively. Net production from the Republic of the Congo fields averaged 21,000 barrels of oil-equivalent per day in 2009.
In May 2009, a successful exploration well was drilled in the Moho-Bilondo exploitation permit area. Development alternatives were being evaluated during 2009. The Moho-Bilondo subsea development project, which started production in 2008, is expected to achieve maximum total production of 90,000 barrels of crude oil per day in the third quarter 2010. Chevrons development and production rights for Moho-Bilondo expire in 2030.
Democratic Republic of the Congo: Chevron has a 17.7 percent nonoperated working interest in an offshore concession. Daily net production in 2009 averaged 3,000 barrels of oil-equivalent.
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 an approximate 21 percent interest in two affiliates that own the pipeline. Average daily net production from the Chad fields in 2009 was 27,000 barrels of oil-equivalent. In September 2009, first production was achieved at the Timbre Field in the Doba area. The Chad producing operations are conducted under a concession that expires in 2030.
Libya: After an unsuccessful exploration well was completed, the company elected to relinquish its 100 percent interest in the onshore Block 177 exploration license in the fourth quarter 2009.
partners in OML 118. At the end of 2009, no proved reserves were recognized for this project.
Chevron operates and holds a 95 percent interest in the deepwater Nsiko discovery on OML 140. Development activities continued in 2009, with FEED expected to start after commercial terms are resolved. At the end of 2009, 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 a floating production, storage and offloading vessel. Development drilling started in June 2009. Production start-up is scheduled for 2012, and maximum total production of 180,000 barrels of crude oil per day is expected to be achieved within one year of start-up. Total costs for the project are estimated at $8.4 billion. Usan has an estimated production life of 20 years. Proved reserves have been recognized for this project.
Chevron participated in one successful deepwater exploration well during 2009 in Oil Prospecting License (OPL) 223. The company has a 30 percent nonoperated working interest in the license. At the end of 2009, proved reserves had not been recognized for the exploration project.
In the Niger Delta, construction on the Phase 3A expansion of the Escravos Gas Plant (EGP) was completed in late 2009 and start of production is expected in March 2010. EGP Phase 3A scope includes offshore natural-gas gathering and compression infrastructure and the addition of a second natural-gas processing facility. The modifications are designed to 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. 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 2012. The engineering, procurement, construction, and installation contract for the pipelines was awarded and work commenced in late 2009. Proved reserves have been recognized for these projects.
The 40 percent-owned and operated Onshore Asset Gas Management project is designed to restore approximately 125 million cubic feet per day of natural-gas production from certain onshore fields that have been shut in since 2003 due to civil unrest. Natural gas from these fields is sold in the Nigerian domestic gas market. The main on-site construction contracts are expected to be awarded in the second quarter 2010.
Refer to page 25 for a discussion of the planned gas-to-liquids facility at Escravos.
Equity Affiliate Operations: Chevron holds a 19.5 percent interest in the OKLNG Free Zone Enterprise (OKLNG) affiliate, which will operate the Olokola LNG project. OKLNG plans to build a multi-train natural-gas liquefaction facility and marine terminal located northwest of Escravos. At the end of 2009, timing of the final investment decision remains uncertain. The company has not recognized proved reserves associated with this project.
Refer to Pipelines under Transportation Operations beginning on page 26 for a discussion of the West African Gas Pipeline operations.
Major producing countries in Asia include Azerbaijan, Bangladesh, Indonesia, Kazakhstan, the Partitioned Zone located between Saudi Arabia and Kuwait, and Thailand. During 2009, net oil-equivalent production averaged 1,044,000 barrels per day in Asia.
prices. The remaining liquids were sold into Russian markets. During 2009, work continued on a fourth train that is designed to increase total export of processed liquids by 56,000 barrels per day. The fourth train is expected to start-up in 2011.
During 2009, Chevron and its 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 project design and achieving project milestones. Karachaganak operations are conducted under a 40-year PSC that expires in 2038.
Equity Affiliate Operations: The company holds a 50 percent interest in Tengizchevroil (TCO), which is operating and 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 2009 from these fields averaged 274,000 barrels per day, composed of 226,000 barrels of crude oil and natural gas liquids and 289 million cubic feet of natural gas.
In 2009, TCO continued ramp-up of the Sour Gas Injection (SGI) and Second Generation Plant (SGP) facilities. 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. TCO is evaluating options for another expansion project based on SGI/SGP technologies.
During 2009, the majority of TCOs crude-oil 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 balance was shipped via other export routes, which 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.)
Turkey: Chevron holds a 25 percent nonoperated working interest in the Silopi licenses in southeast Turkey, which is on trend with production in Iraqs northern Zagros Fold Belt. An exploration well in the Lale prospect completed drilling in the first quarter 2010, and is under evaluation.
Bangladesh: Chevron holds interests in three operated PSCs covering onshore Blocks 12, 13 and 14 and offshore Block 7. The company has a 98 percent interest in Blocks 12, 13 and 14. Government approval of a 2009 farm-out in Block 7 was received in February 2010, reducing the companys interest from 88 percent to 43 percent. The farm-out was to GS Caltex, a 50 percent-owned affiliate of the company. Net oil-equivalent production from these operations in 2009 averaged 66,000 barrels per day, composed of 387 million cubic feet of natural gas and 2,000 barrels of liquids. In 2009, a final investment decision was achieved after the government approved the development of a compression project that is expected to support additional production starting in 2012 from the Bibiyana, Jalalabad and Moulavi Bazar natural-gas fields. Proved reserves have been recognized for this project. The government also approved an amendment to the PSC for Blocks 13 and 14 that allows the company to acquire additional 3-D seismic over the Jalalabad Field. Also in 2009, the company acquired seismic data on Block 7. Evaluation and data processing is under way, and an exploration well is planned to be completed by 2011.
Cambodia: Chevron operates the 1.2 million-acre (4,709 sq-km) Block A, located offshore in the Gulf of Thailand, and expects to reduce its ownership to 30 percent pending government approval of the farm-out that is anticipated in the second quarter 2010. In 2009, commercial evaluation of the prospects continued. The company was granted an extension for the Block A exploration period to the third quarter 2010 in exchange for the obligation to drill three exploration wells. Information gained from the drilling program is expected to provide improved definition of the resource in the block. Proved reserves had not been recognized as of the end of 2009.
Myanmar: Chevron has a 28.3 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 28.3 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 2009 was 76 million cubic feet per day. During 2009, the platform for a compression project was completed. Project start-up is expected in 2011.
Chevron has a 16 percent nonoperated working interest in Blocks 14A, 15A, 16A, G9/48 and G8/50, known collectively as the Arthit Field.
During 2009, construction at the 69.8 percent-owned and operated Platong Gas II project continued. The project is designed to add 420 million cubic feet per day of processing capacity in 2012. Proved reserves have been recognized for this project. Concessions for Blocks 10 through 13 expire in 2022.
During 2009, 14 exploration wells were drilled in the Gulf of Thailand, 13 were successful and one nonoperated well in the Arthit Field was unsuccessful. Two 3-D seismic surveys and geological studies for Block G4/50 were also completed in 2009. At the end of 2009, proved reserves had not been recognized for these activities. Three exploratory wells in Block G4/50 are planned for the second quarter 2010. For Blocks G6/50 and G7/50, one exploration well is scheduled in each block for completion by the third quarter 2010. 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 42.4 percent interest in a PSC that includes Blocks B and 48/95, and a 43.4 percent interest in another PSC for Block 52/97. In August 2009, Chevron reduced its ownership interest in a third operated PSC to 20 percent in Block B122 offshore eastern Vietnam. No production occurred in these areas during 2009.
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, a floating storage and offloading vessel, field pipelines and a central processing platform. The project is expected to enter front-end engineering and design (FEED) in the first quarter 2010, and a final investment decision is expected in 2011. Maximum total production is planned to be about 500 million cubic feet of natural gas per day. At the end of 2009, proved reserves had not been recognized for this project.
In conjunction with the Vietnam Gas Project, a Petrovietnam-operated pipeline will be required to support the offshore development. Chevron will have a 28.7 percent interest in the pipeline, which is planned to transport natural gas from the offshore development to customers in southern Vietnam.
During the year, the company continued to analyze well results and seismic processing from Block B and Block 52/97. In Block 122, 2-D seismic data processing and geologic studies were completed. An exploration well is planned for 2011. Proved reserves had not been recognized as of the end of 2009. Future activity in Block 122 may be affected by an ongoing territorial dispute between Vietnam and China.
November 2009, a storm damaged the floating production, storage and offloading (FPSO) vessel utilized by the companys nonoperated assets in Block 11/19. Temporary and permanent recovery options are under development and production is expected to fully resume in 2012.
The joint development of the HZ25-3 and HZ25-1 crude-oil fields in Block 16/19 continued through the end of 2009. First production was delayed from the third quarter 2009 and is expected to be fully restored in the fourth quarter 2010 following damage to the FPSO vessel caused by a typhoon that struck the area in September 2009.
In 2009, Chevron relinquished its nonoperated working interest in four exploration blocks in the Ordos Basin. Government approval is expected in mid-2010.
The companys net oil-equivalent production in 2009 from all of its interests in Indonesia averaged 243,000 barrels per day. The daily oil-equivalent rate comprised 199,000 barrels of liquids and 268 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 divided into multiple expansion areas. The first expansion in Area 12 started steam injection in June 2009. Maximum total daily production from Area 12 is estimated at 34,000 barrels of crude oil in 2012. A final investment decision regarding North Duri Area 13 is expected by year-end 2010. The Rokan PSC expires in 2021.
Chevron advanced its development plans for the Gendalo and Gehem deepwater natural-gas fields located in the Kutei Basin. FEED started in December 2009, with completion dependent upon achieving project milestones and receipt of government approvals. The Bangka deepwater natural-gas project was progressed during the year under a revised, lower-cost development plan. The project is expected to enter FEED in the second quarter 2010. Under the terms of the PSCs for both projects, the companys 80 percent-owned and operated interest is expected to be reduced to 72 percent in 2010 with the farm-in of an Indonesian company. At the end of 2009, the company had not recognized proved reserves for either of these projects.
Also in the Kutei Basin, first production at the Seturian Field occurred in September 2009, which is providing natural gas to a state-owned refinery. During 2009, evaluation of the 50 percent-owned and operated Sadewa project in the Kutei Basin was suspended.
A drilling campaign continued through 2009 in South Natuna Sea Block B to provide additional supply for long-term natural-gas sales contracts with additional development drilling planned for 2010. The North Belut development project achieved first production in November 2009. The South Belut development project was under review during the year.
A two-well exploration program was conducted in the Central Sumatra Basin in 2009. One commercial discovery was made in the Rokan Block, and a second well in the Siak Block resulted in a dry hole. Chevrons working interests in two exploration blocks in western Papua, West Papua I and West Papua III, are expected to be reduced to 51 percent interests in 2010. Completion of geological studies for those blocks was ongoing at year-end 2009, and 2-D seismic acquisition is planned for the second half 2010.
In West Java, Chevron operates the wholly owned Salak geothermal field with a total power-generation 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 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 pilot is an application of steam injection into a carbonate reservoir and, if successful, could significantly increase heavy oil recovery. The Central Gas Utilization Project was initiated in 2009 to assess alternatives to increase natural-gas utilization and eliminate routine flaring. A final investment decision is expected in 2011. No reserves have been recognized for these projects.
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 2009 averaged 27,000 barrels per day, composed of 137 million cubic feet of natural gas and 4,000 barrels of condensate. Chevron also develops and produces geothermal resources under an agreement with the Philippine government. Chevron expects to sign a new 25-year contract with the government by the end of 2010 to operate the steam fields, which supply geothermal resources to the 637 megawatt geothermal facilities.
Other is composed of Australia, Argentina, Brazil, Colombia, Trinidad and Tobago, Venezuela, Canada, Greenland, Denmark, Faroe Islands, the Netherlands, Norway, Poland and the United Kingdom. Net oil-equivalent production from countries included in this section averaged 484,000 barrels per day during 2009. In addition, the companys share of production from oil sands (for upgrading into synthetic oil) from the Athabasca Oil Sands Project in Canada was 26,000 barrels per day.
designed to be operated as a single integrated facility. The project is scheduled to start production in 2013. Proved reserves have been recognized for the project.
The NWS Venture is also advancing plans to extend the period of crude-oil production. The NWS Oil Redevelopment Project is designed to replace the present floating production, storage and offloading vessel and a portion of existing subsea infrastructure that services production from the Cossack, Hermes, Lambert and Wanaea offshore fields. In 2009, work commenced on conversion of the replacement vessel. The project is expected to start-up in early 2011 and 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 4,000 barrels per day in 2009. Chevrons interests in these operations are 57.1 percent for Barrow and 51.4 percent for Thevenard.
Also off the northwest coast of Australia, Chevron holds significant equity interests in the large natural-gas resource of the Greater Gorgon Area. The company initially held a 50 percent ownership interest across most of the area and is the operator of the Gorgon Project. Chevron and its joint-venture partners are proceeding with the combined development of Gorgon and nearby natural-gas fields as one large-scale project. Environmental approval from the Australian Commonwealth Government was issued in August 2009. In September 2009, the company announced the final investment decision and total estimated project costs for the first phase of development of $37 billion (AU$ 43 billion). The projects scope includes a three-train, 15 million-metric-ton-per-year LNG facility; a carbon sequestration project; and a domestic natural-gas plant. Natural gas for the project is expected to be supplied from the Gorgon and Io/Jansz fields.
In 2009, long-term, binding agreements were finalized with four Asian customers for the delivery of about 4.4 million metric tons per year of LNG from the Gorgon Project. Equity sales agreements with three of the customers reduced Chevrons interest in the project to 47.3 percent at the end of 2009. Nonbinding Heads of Agreements (HOA) for delivery of an additional 2.1 million metric tons per year of LNG were also signed with three additional Asian customers in 2009 and early 2010. Negotiations continue to finalize binding sales agreements, which would bring LNG delivery commitments to a combined total of about 90 percent of Chevrons share of LNG from the project. During 2009, the company recognized proved reserves for the Greater Gorgon Area fields included in the project. First production of natural gas from these fields is expected in 2014. The projects estimated economic life exceeds 40 years from the time of start-up.
Development of the companys majority-owned and operated Wheatstone and Iago fields, located offshore Western Australia, continued with the project entering front-end engineering and design (FEED) in July 2009. Chevron operates the project and plans to supply natural gas to its 75 percent-owned and operated LNG facilities from two 100 percent-owned licenses comprising the majority of the Wheatstone Field and part of the nearby Iago Field. In October 2009, agreements were signed with two companies to join the Wheatstone Project as combined 25 percent LNG facility owners and suppliers of natural gas for the projects first two LNG trains. In December 2009 and January 2010, nonbinding HOAs were signed with two Asian customers to take delivery of 4.9 million tons of LNG per year from the project, representing about 60 percent of the total LNG available from the foundation project. In addition, under these same HOAs the parties would acquire a combined 16.8 percent nonoperated working interest in the Wheatstone Field licenses and a 12.6 percent interest in the foundation natural-gas processing facilities at the final investment decision. At the end of 2009, the company had not recognized proved reserves for this project.
In the Browse Basin, the company continued engineering and survey work on two potential development concepts for the Brecknock, Calliance and Torosa fields. At the end of 2009, proved reserves had not been recognized.
In May 2009, the company announced the successful completion of a well at the Clio prospect to further explore and appraise the 66.7 percent-owned Block WA-205-P. In 2009 and early 2010, the company also announced natural-gas discoveries at the Kentish Knock prospect in the 50 percent-owned Block WA-365-P, the Achilles and Satyr prospects in the 50 percent-owned Block WA-374-P and the Yellowglen prospect in the 50 percent-owned WA-268-P Block. All prospects are Chevron-operated. At the end of 2009, proved reserves had not been recognized.
final investment decision was made in January 2010. The project operator estimates total costs of $5.2 billion and expects first production in 2013. The facility is expected to be capable of producing up to 140,000 barrels of crude oil per day. Evaluation of design options for Maromba continued into 2010. At the end of 2009, proved reserves had not been recognized for these projects.
In the Santos Basin, evaluation of investment options continued into 2010 for the 20 percent-owned and partner-operated Atlanta and Oliva fields. At the end of 2009, proved reserves had not been recognized for these fields.
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 245 million cubic feet of natural gas in 2009.
Trinidad and Tobago: Company interests include 50 percent ownership in three 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 6(d). Net production in 2009 averaged 199 million cubic feet of natural gas per day. Incremental production associated with a new domestic sales agreement commenced at Dolphin in the 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. In February 2010, a Chevron-led consortium was selected to participate in a heavy-oil project composed of three blocks in the Orinoco Oil Belt of eastern Venezuela. The consortium is expected to acquire a 40 percent interest in the project, with PDVSA holding the remaining interest.
The Loran Field in Block 2 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 2008, which provides Chevron with
a 10 percent nonoperated interest in the first train and the associated offshore pipeline. An interim operating agreement governing activities prior to a final investment decision was signed by Chevron and its Train 1 partners in March 2009. In May 2009, the company relinquished part of Block 3 and retained the portion containing the 2005 Macuira natural-gas discovery. An unsuccessful exploration well was drilled in the Cardon III block in 2009. The company plans to continue to evaluate exploration potential in the Cardon III block in 2010. At the end of 2009, proved reserves had not been recognized in these exploratory blocks.
Equity Affiliate Operations: Chevron also holds interests in two affiliates located in western Venezuela and in one affiliate in the Orinoco Belt. 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 39.2 percent interest in the Petroboscan affiliate that operates the Boscan Field in the western part of the country, and a 25.2 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 2009 from these operations was 54,000 barrels per day, composed of 51,000 barrels of crude oil and natural gas liquids and 23 million cubic feet of natural gas.
In February 2010, binding agreements were signed with the Government of Newfoundland and Labrador on the development of the HSE unitized area, providing Chevron with a 23.6 percent nonoperated working interest in the unitized area.
For Hebron, agreements were reached during 2008 with the Government of Newfoundland and Labrador that allow development activities to begin. At the end of 2009, proved reserves had not been recognized for this project.
At AOSP, the companys production from oil sands (for upgrading into synthetic oil) averaged 26,000 barrels per day during 2009. The first phase of an expansion project is under way and is expected to increase total production from oil sands by 100,000 barrels per day. 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 $14.3 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 production from oil sands through wells rather than through mining operations. Additional field appraisal activity is not planned in the near-term. At the end of 2009, proved reserves had not been recognized.
The company also holds exploration leases in the Mackenzie Delta and Beaufort Sea region, including a 34 percent nonoperated working interest in the offshore Amauligak discovery. Three exploration wells were drilled on company leases in the Mackenzie Delta region in 2009, and assessment of development concept alternatives for Amauligak continues. The company holds additional exploration acreage in eastern Labrador and the Orphan Basin. In 2009, the company was also successful in acquiring a western Canada lease position to explore for shale gas. At the end of 2009, proved reserves had not been recognized for any of these areas.
Greenland: Processing of the 2-D seismic survey acquired over License 2007/26 in Block 4 offshore West Greenland in 2008 continued in 2009, and evaluation will commence in the first-half 2010. Chevron has a 29.2 percent nonoperated working interest in this exploration license.
Norway: The company holds a 7.6 percent interest in the partner-operated Draugen Field. The companys net production averaged 5,000 barrels of oil-equivalent per day during 2009. In 2009, Chevron was awarded a 40 percent working interest as operator of the exploration license PL 527 in the deepwater portion of the Norwegian Sea. Data acquisition was completed on a 2-D seismic survey, and evaluation is under way.
Poland: In December 2009, Chevron was awarded three five-year exploration licenses in the Zwierzyniec, Kransnik and Frampol concessions, and in February 2010, Chevron acquired the exploration rights to the Grabowiec concession. Chevron has a 100 percent-owned and operated interest in these four concessions to explore for shale gas.
United Kingdom: The companys average net oil-equivalent production in 2009 from 10 offshore fields was 110,000 barrels per day, composed of 73,000 barrels of crude oil and natural gas liquids and 222 million cubic feet of natural gas. Most of the production was from the 85 percent-owned and operated Captain Field, the 23.4 percent-owned and operated Alba Field and the 32.4 percent-owned and jointly operated Britannia Field.
Evaluation of development alternatives continued during 2009 for the 19.4 percent-owned and partner-operated Clair Phase 2 project west of the Shetland Islands. In the 40 percent-owned and operated Rosebank/Lochnagar area northwest of the Shetland Islands, an exploration well in Rosebank North was completed in the second quarter 2009 and an appraisal well in Rosebank/Lochnagar was completed in the third quarter 2009. Also northwest of the Shetland Islands, a three-well exploration and appraisal drilling program was completed in 2009 at the Cambo prospect. Technical studies have commenced to select a preferred development alternative. Additional exploration drilling in the region is expected to occur in the second-half 2010. As of the end of 2009, proved reserves had not been recognized for any of these prospects.
In February 2010, the company sold its 10 percent nonoperated interest in the Laggan/Tormore discovery.
The company sells natural gas and natural gas liquids from its producing operations under a variety of contractual arrangements. In addition, the company also makes third-party purchases and sales of natural gas and natural gas liquids in connection with its trading activities.
During 2009, U.S. and international sales of natural gas were 5.9 billion and 4.1 billion cubic feet per day, respectively, which includes the companys share of equity affiliates sales. Outside the United States, substantially all of the natural-gas sales from the companys producing interests are from operations in Australia, Bangladesh, Kazakhstan, Indonesia, Latin America, the Philippines, Thailand and the United Kingdom.
U.S. and international sales of natural gas liquids were 161 thousand and 111 thousand barrels per day, respectively, in 2009. Substantially all of the international 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 2009, the company had a refining network capable of processing more than 2 million barrels of crude oil per day. Operable capacity at December 31, 2009, and daily refinery inputs for 2007 through 2009 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 2009 was 91 percent, compared with 87 percent in 2008, largely a result of improved utilization at the refineries in Mississippi, Canada and Thailand. At the U.S. fuel refineries, crude oil distillation capacity utilization averaged 96 percent in 2009, compared with 95 percent in 2008, and cracking and coking capacity utilization averaged 85 percent and 86 percent in 2009 and 2008, 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. During 2009, GS Caltex, the companys 50 percent-owned affiliate, continued construction on a new heavy-oil hydrocracker designed to increase high-value product yield and lower feedstock costs at the Yeosu, South Korea
complex. Project completion is expected in 2010. Modifications were completed in 2009 that enable the companys 50 percent-owned Singapore Refining Companys refinery to meet regional specifications for clean diesel fuels.
At the Pascagoula Refinery, construction progressed on a continuous catalytic reformer that is expected to improve refinery reliability. Planning continued for a premium base-oil facility at the companys Pascagoula Refinery. The facility is being designed to produce approximately 25,000 barrels per day of premium base oil for use in manufacturing high-performance lubricants, such as motor oils for consumer and commercial applications. At the refinery in El Segundo, California, design, engineering and construction work advanced during 2009 on projects that will reduce feedstock costs and improve yields.
At the beginning of 2009, Chevron held a 5 percent interest in Reliance Petroleum Limited, a company formed by Reliance Industries Limited to construct a new refinery in Jamnagar, India. During the year, the company sold its 5 percent interest to Reliance Industries Limited.
Chevron processes imported and domestic crude oil in its U.S. refining operations. Imported crude oil accounted for about 85 percent and 88 percent of Chevrons U.S. refinery inputs in 2009 and 2008, respectively.
In Nigeria, Chevron and the Nigerian National Petroleum Corporation are developing a 33,000 barrel-per-day gas-to-liquids facility at Escravos designed to process 325 million cubic feet per day of natural gas supplied from the Phase 3A expansion of the Escravos Gas Plant (EGP). At the end of 2009, construction was under way with two gas-to-liquids reactors and the process modules delivered to the site. 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 ended December 31, 2009.
Refined Products Sales Volumes
(Thousands of Barrels per Day)
In the United States, the company markets under the Chevron and Texaco brands. At year-end 2009, the company supplied directly or through retailers and marketers approximately 9,600 Chevron- and Texaco-branded motor vehicle service stations, primarily in the mid-Atlantic, southern and western states. Approximately 500 of these outlets are company-owned or -leased stations. The company plans to discontinue, by mid-2010, sales of Chevron- and Texaco-branded motor fuels in the mid-Atlantic and other eastern states, where the company sold to retail customers through approximately 1,100 stations and to commercial and industrial customers through supply arrangements. Sales in these markets represent approximately 8 percent of the companys total U.S. retail fuels sales volumes. Additionally, in January 2010, the company sold the rights to the Gulf trademark in the United States and its territories that it had previously licensed for use in the U.S. Northeast and Puerto Rico.
Outside the United States, Chevron supplied directly or through retailers and marketers approximately 12,400 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, and in Australia through its 50 percent-owned affiliate, Caltex Australia Limited.
In 2009, the company completed the sale of businesses in Brazil, Haiti, Nigeria, Benin, Cameroon, Republic of the Congo, Côte dIvoire, Togo, Kenya, Uganda, India, Italy, Peru and Chile. The company retained its lubricants business in Brazil. In addition, the company sold its interest in about 465 individual service-station sites in various other countries, including the United States. The majority of these sites continue to market company-branded gasoline through new supply agreements.
The company also manages other marketing businesses globally. Chevron markets aviation fuel at more than 875 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 network of crude-oil, refined-product, chemicals, natural-gas-liquids (NGL) and natural-gas pipelines and other infrastructure assets 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 2009, work progressed on a project that is designed to expand capacity by about 2 billion cubic feet at the Keystone natural-gas storage facility near Midland, Texas, which would bring the total capacity of the facility to nearly 7 billion cubic feet. The project completion is anticipated in the second quarter 2010.
Work commenced in late 2009 to bring the Cal-Ky Pipeline, which was decommissioned in 2002, back into crude-oil service as a supply line for the Pascagoula Refinery. This crude-oil pipeline is also expected to provide additional outlets for the companys equity production. The pipeline is expected to return to service in 2011. The company is also leading the evaluation and negotiations associated with a 136 mile, 24-inch pipeline from the proposed Jack and St. Malo production facility to Green Canyon 19 in the U.S. Gulf of Mexico. In December 2009, the company sold its interest in the western portion of the Texaco Expanded NGL Distribution System and its 64 percent ownership interest in Southcap Pipeline Company, which included Chevrons 13.4 percent ownership interest in the Capline Pipeline.
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 2009, CPC transported an average of approximately 743,000 barrels of crude oil per day, including 597,000 barrels per day from Kazakhstan and 146,000 barrels per day from Russia. In December 2009, partners approved the Expansion Project Implementation Plan, which is expected to increase the pipeline capacity to 1.4 million barrels per day. A final investment decision is expected in late 2010.
The company has an 8.9 percent interest in the Baku-Tbilisi-Ceyhan (BTC) affiliate that owns and operates a pipeline that primarily transports crude oil produced by Azerbaijan International Operating Company (AIOC) (owned 10.3 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. Compression facilities are expected to be installed in the second quarter 2010 that are designed to increase capacity to 170 million cubic feet per day.
Tankers: All tankers in Chevrons controlled seagoing fleet were utilized during 2009. At any given time during 2009, the company had 42 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. The companys U.S.-flagged fleet is 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. As part of its fleet modernization program, the company has two U.S.-flagged tankers scheduled for delivery in 2010 and plans to retire three U.S.-flagged product tankers between 2010 and 2011. The new tankers are expected to bring improved efficiencies to Chevrons U.S.-flagged fleet.
The foreign-flagged vessels are 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. The companys foreign-flagged vessels also transport refined products to and from various locations worldwide.
In addition to the vessels described above, the company owns a one-sixth interest in each of seven liquefied-natural-gas (LNG) tankers transporting cargoes for the North West Shelf (NWS) Venture in Australia. The NWS project also has two LNG tankers under long-term time charter.
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 2009, the companys owned and 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 2009, CPChem owned or had joint-venture interests in 34 manufacturing facilities and five research and technical centers in Belgium, Brazil, China, Colombia, Qatar, Saudi Arabia, Singapore, South Korea and the United States.
During 2009, CPChem completed construction of the 22 million-pounds-per-year Ryton® polyphenylene-sulfide (PPS) manufacturing facility at Borger, Texas. Ryton® PPS is an engineering thermoplastic used in a variety of applications, including automotives and electronics.
Outside the United States, CPChems 35 percent-owned Saudi Polymers Company continued construction during 2009 on a petrochemical project in Al Jubail, Saudi Arabia. The joint-venture project includes an olefins unit and downstream polyethylene, polypropylene, 1-hexene and polystyrene units. Project completion is expected in 2011.
CPChem continued construction during 2009 on the 49 percent-owned Q-Chem II project, located in both Mesaieed and Ras Laffan, Qatar. The project includes a 350,000-metric-ton-per-year high-density polyethylene plant and a 345,000-metric-ton-per-year normal alpha olefins plant, each utilizing CPChem proprietary technology. These plants are located adjacent to the existing Q-Chem I complex. The Q-Chem II project also includes a separate joint venture to develop a 1.3 million-metric-ton-per-year ethylene cracker in Ras Laffan, in which Q-Chem II owns 54 percent of the capacity rights. Start-up for the ethylene cracker is expected in March 2010, and start-up for the polyethylene and alpha olefins plants is anticipated in the third quarter 2010.
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 lubricant additives are blended into refined base oil to produce finished lubricant packages used 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. During 2009, production began at the detergent expansion facility in Palau Sakra, Singapore. This additional capacity enhances the companys ability to produce detergent components for applications in marine and automotive engines.
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 is the operator of a surface coal mine in Kemmerer, Wyoming, an underground coal mine, North River, in Alabama, and a surface coal mine in McKinley, New Mexico. The company continues to actively market for sale its coal reserves at the North River Mine and elsewhere in Alabama. The decision was made in late 2009 to suspend production at the McKinley Mine, and conduct reclamation activities in 2010. The company also owns a 50 percent interest in Youngs Creek Mining Company LLC, which was formed to develop a coal mine in northern Wyoming. Coal sales from wholly owned mines in 2009 were 10 million tons, down about 1 million tons from 2008.
At year-end 2009, Chevron controlled approximately 193 million tons of proven and probable coal reserves in the United States, including reserves of low-sulfur coal. The company is contractually committed to deliver between 7 million and 9 million tons of coal per year through the end of 2012 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 2009, Chevron controlled approximately 53 million pounds of proven molybdenum reserves at Questa. Underground development and production plans at Questa were scaled back in 2009 in response to weakening prices for molybdenum.
Chevrons power generation business has interests in 13 power assets with a total operating capacity of more than 3,100 megawatts, primarily through joint ventures in the United States and Asia. Twelve of these are efficient combined-cycle and gas-fired cogeneration facilities that utilize waste heat recovery to produce electricity and support industrial thermal hosts. The thirteenth facility is a wind farm, located in Casper, Wyoming, that began operating in late 2009. The 100 percent-owned and operated Casper Wind Farm is a small-scale wind power facility designed to optimize the efficient use of a decommissioned refinery site for delivery of clean, renewable energy to the local utility provider.
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 18 and Research and Technology below.
Chevron Energy Solutions (CES) is a wholly owned subsidiary that designs and implements sustainable solutions for public institutions and businesses 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 help governments, educational institutions and other customers reduce their energy costs and environmental impact. Major projects completed by CES in 2009 included solar and energy-efficiency installations for the Los Angeles County Metropolitan Transportation Authority and the San Jose Unified School District, which were the largest projects of their kind for a U.S. transit authority and school district.
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 2009, CTV continued to explore technologies such as next-generation biofuels and advanced solar.
Chevrons research and development expenses were $603 million, $702 million and $510 million for the years 2009, 2008 and 2007, respectively.
Some of the investments the company makes in the areas described above are in new or unproven technologies and business processes, and ultimate technical or commercial successes are not certain. 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. Most of the costs of complying with the many laws and regulations pertaining to its operations are, or are expected to become, embedded in the normal costs of conducting business.
In 2009, the companys U.S. capitalized environmental expenditures were approximately $887 million, representing approximately 15 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 2010, the company estimates U.S. capital expenditures for environmental control facilities will be approximately $831 million. The future annual capital costs are uncertain and will be governed by several factors, including future changes to regulatory requirements.
Chevron expects an increase in environment-related regulations, including those that are intended to address concerns about greenhouse gas emissions and global climate change, in the countries where it has operations. For instance, under Californias Global Warming Solutions Act enacted in 2006, the California Air Resources Board (CARB), charged with implementing the law, has adopted a new low-carbon fuel standard intended to reduce the carbon intensity of transportation fuels, which is expected to apply beginning in 2011. Additionally, CARB is expected to propose regulations to implement the cap and trade emissions regulation provisions of the law, for adoption in the second half 2010. The effect of any such regulation on the companys business is uncertain.
Refer to Managements Discussion and Analysis of Financial Condition and Results of Operations on pages FS-16 through FS-17 for additional information on environmental matters and their impact on Chevron and on the companys 2009 environmental expenditures, remediation provisions and year-end environmental reserves. Refer also to Item 1A. Risk Factors on pages 30 through 32 for a discussion of greenhouse gas regulation and climate change.
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 free of charge 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 or through acquisitions, 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, explosions and system failures, 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. Often these operations are conducted through joint ventures over which the company may have limited influence and control. Any of these activities could result in liability arising from private litigation or government action, 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. In addition, to the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to the companys causation of or contribution to the asserted damage or to other mitigating factors.
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 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, 2009, 26 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 Zone between Saudi Arabia and Kuwait. Twenty-two percent of the companys net proved reserves, including affiliates, were located in OPEC countries at December 31, 2009.
Regulation of greenhouse gas emissions could increase Chevrons operational costs and reduce demand for Chevrons products.
Continued political attention to issues concerning climate change, the role of human activity in it and potential mitigation through regulation could have a material impact on the companys operations and financial results.
International agreements and national or regional legislation and regulatory measures to limit greenhouse emissions are currently in various stages of discussion or implementation. For instance, the Kyoto Protocol, Australias proposed legislation and Californias Global Warming Solutions Act, along with other actual or pending federal, state and provincial regulations, envision a reduction of greenhouse gas emissions through market-based regulatory programs, technology-based or performance-based standards or a combination of them. The company is subject to existing greenhouse gas emissions limits in jurisdictions where such regulation is currently effective, including the European Union and New Zealand.
In December 2009, the U.S. Environmental Protection Agency (EPA) issued a final endangerment finding for greenhouse gases, which specifically found that emissions of six greenhouse gases threaten the public health and welfare and that greenhouse gases from new motor vehicles and engines also contribute to such pollution. These findings do not themselves impose regulatory requirements. However, the agency is currently in the process of promulgating greenhouse gas emission standards for light-duty vehicles and regulations that would require certain stationary source facilities that exceed an as-yet undetermined threshold to obtain permits in advance, which permits could require implementation of so-called best available control technologies. In June 2009, the U.S. House of Representatives approved the American Clean Energy and Security Act. This is known as the Waxman-Markey bill, which includes provisions for a cap-and-trade program, aimed at controlling and reducing emissions of greenhouse gases in the United States. At this time it is not possible to predict whether or when the U.S. Senate may act on climate change legislation, how any bill approved by the Senate will be reconciled with the Waxman-Markey legislation or whether any federal legislation will supersede the EPAs regulatory actions.
These and other greenhouse gas emissions-related laws, policies and regulations, may result in substantial capital, compliance, operating and maintenance costs. The level of expenditure required to comply with these laws and regulations is uncertain and is expected to vary by jurisdiction depending on the laws enacted in each jurisdiction, the companys activities in it and market conditions. The companys exploration and production of crude oil, natural gas and
various minerals such as coal; the upgrading of production from oil sands into synthetic oil; power generation; the conversion of crude oil and natural gas into refined products; the processing, liquefaction and regasification of natural gas; the transportation of crude oil, natural gas and related products and consumers or customers use of the companys products result in greenhouse gas emissions that could well be regulated. Some of these activities, such as consumers and customers use of the companys products, as well as actions taken by the companys competitors in response to such laws and regulations, are beyond the companys control.
The effect of regulation on the companys financial performance will depend on a number of factors, including, among others, the sectors covered, the greenhouse gas emissions reductions required by law, the extent to which Chevron would be entitled to receive emission allowance allocations or need to purchase compliance instruments on the open market or through auctions, the price and availability of emission allowances and credits, and the impact of legislation or other regulation on the companys ability to recover the costs incurred through the pricing of the companys products. Material price increases or incentives to conserve or use alternative energy sources could reduce demand for products the company currently sells and adversely affect the companys sales volumes, revenues and margins.
Changes in managements estimates and assumptions may have a material impact on the companys consolidated financial statements and financial or operations performance in any given period.
In preparing the companys periodic reports under the Securities Exchange Act of 1934, including its financial statements, Chevrons management is required under applicable rules and regulations to make estimates and assumptions as of a specified date. These estimates and assumptions are based on managements best estimates and experience as of that date and are subject to substantial risk and uncertainty. Materially different results may occur as circumstances change and additional information becomes known. Areas requiring significant estimates and assumptions by management include measurement of benefit obligations for pension and other postretirement benefit plans; estimates of crude oil and natural gas recoverable reserves; accruals for estimated liabilities, including litigation reserves; and impairments to property, plant and equipment. Changes in estimates or assumptions or the information underlying the assumptions, such as changes in the companys business plans, general market conditions or changes in commodity prices, could affect reported amounts of assets, liabilities or expenses.
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 Subpart 1200 of Regulation S-K (Disclosure by Registrants Engaged in Oil and Gas Producing Activities) is also contained in Item 1 and in Tables I through VII on pages FS-64 through FS-77. Note 13, Properties, Plant and Equipment, to the companys financial statements is on page FS-45.
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; 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, which the court dismissed. In September 2009, following the disclosure by Chevron of evidence that the judge participated in meetings in which businesspeople and individuals holding themselves out as government officials discussed the case and its likely outcome, the judge presiding over the case petitioned to be recused. In late September 2009, the judge was recused, and in October 2009, the full chamber of the provincial court affirmed the recusal, resulting in the appointment of a new judge. Chevron filed motions to annul all of the rulings made by the prior judge, but the new judge denied these motions. The court has completed most of the procedural aspects of the case and could render a judgment at any time. Chevron will continue a vigorous defense of any attempted imposition of liability.
In the event of an adverse judgment, Chevron would expect to pursue its appeals and vigorously defend against enforcement of any such judgment; therefore, the ultimate outcome and any financial effect on Chevron remains uncertain. 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 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).
In November 2008, the California Air Resources Board (CARB) proposed a civil penalty against the companys Sacramento, California, terminal for alleged violations between August and December 2007 of CARBs regulations governing the minimum concentration of additives in gasoline. Due to a computer programming error, the Sacramento terminals automatic dispensers had failed to inject additive detergent into a gasoline line.
In November 2008, CARB proposed a civil penalty against the companys Richmond, California, refinery for a notice of violation relating to gasoline that was not properly certified as to composition. The company corrected the composition certificates for the gasoline without requiring any change to the composition of the gasoline. In July 2009, CARB issued the refinery a notice of violation relating to an error in gasoline blending that caused the product composition certifications to be in error. The composition certifications were corrected without requiring any change to the gasoline. Discussions with CARB officials relating to all of these matters took place in the fourth quarter 2009 and continue in 2010.
In July 2009, the Hawaii Department of Health (DOH) alleged that Chevron is obligated to pay stipulated civil penalties exceeding $100,000 in conjunction with commitments the company undertook to install and operate certain air pollution abatement equipment at its Hawaii Refinery pursuant to Clean Air Act settlement with the United States Environmental Protection Agency and DOH. The company has disputed many of the allegations.
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 2005 through 2009 are presented on page FS-63.
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-14 and in Note 10 to the Consolidated Financial Statements, Financial and Derivative Instruments, beginning on page FS-39.
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, 2009.
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, 2009.
The effectiveness of the companys internal control over financial reporting as of December 31, 2009, 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, 2009, 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.
Executive Officers of the Registrant at February 25, 2010
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 about directors required by Item 401(a) and (e) of Regulation S-K and contained under the heading Election of Directors in the Notice of the 2010 Annual Meeting and 2010 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 2010 Annual Meeting of Stockholders (the 2010 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 2010 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 2010 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
The information required by Item 407(d)(4) and (5) of Regulation S-K and contained under the heading Board Operations Board Committee Membership and Functions in the 2010 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 Director Compensation in the 2010 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 2010 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 2010 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 2010 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 2010 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 2010 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 2010 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 Election of Directors Independence of Directors in the 2010 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 Proposal to Ratify the Independent Registered Public Accounting Firm in the 2010 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:
Schedule Of Valuation And Qualifying Accounts Disclosure
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 25th day of February, 2010.
John S. Watson, 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 25th day of February, 2010.
Financial Table of Contents
Managements Discussion and Analysis of
Financial Condition and Results of Operations
Key Financial Results
Earnings 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 ended December 31, 2009.
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, Indonesia, Kazakhstan, Myanmar, the Netherlands, Nigeria, Norway, the Partitioned Zone between Saudi Arabia and Kuwait, the Philippines, 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 investments. Earnings for the company in any period may also be influenced by events or transactions that are infrequent or unusual in nature.
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 attractive 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 financial performance and growth. Refer to the Results of Operations section beginning on FS-6 for discussions of net gains on asset sales during 2009. Asset dispositions and restructurings may also occur in future periods and could result in significant gains or losses.
In recent years, 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. Softening of these cost pressures started in late 2008 and continued through most of 2009. Costs began to level out in the fourth quarter 2009. The company continues to actively manage its schedule of work,
contracting, procurement and supply-chain activities to effectively manage costs. (Refer to the Upstream section below for a discussion of the trend in crude-oil prices.)
The company continues to closely monitor developments in the financial and credit markets, the level of worldwide economic activity and the implications to the company of movements in prices for crude oil and natural gas. 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 address potential challenges presented in this environment. (Refer also to the Liquidity and Capital Resources section beginning on FS-11.)
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 businesses. Besides the impact of the fluctuation in prices 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 and changes in tax laws and regulations.
Price levels for capital and exploratory costs and operating expenses associated with the 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 commodity prices and 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 damage to production facilities caused by severe weather or civil unrest.
The chart at left shows the trend in benchmark prices for West Texas Intermediate (WTI) crude oil and U.S. Henry Hub natural gas. Industry price levels for crude oil continued to be volatile during 2009, with prices for WTI ranging from $34 to $81 per barrel. The WTI price averaged $62 per barrel for the full-year 2009, compared to $100 in 2008. The decline in prices from 2008 was largely associated with a weakening in global economic conditions and a reduction in the demand for crude oil and petroleum products. As of mid-February 2010, the WTI price was about $77.
A differential in crude-oil prices exists between high-quality (high-gravity, low-sulfur) crudes and those of lower-quality
(low-gravity, high-sulfur). The amount of the differential in any period is associated with the supply of heavy crude available versus the demand that is a function of the number of refineries that are able to process this lower-quality feedstock into light products
(motor gasoline, jet fuel, aviation gasoline and diesel fuel). The differential remained narrow through 2009 as production declines in the industry have been mainly for lower-quality crudes.
Chevron produces or shares in the production of heavy crude oil in California, Chad, Indonesia, the Partitioned Zone between Saudi Arabia and Kuwait, Venezuela and in certain fields in Angola, China and the United Kingdom
Managements Discussion and Analysis of
Financial Condition and Results of Operations
sector of the North Sea. (See 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, prices at Henry Hub averaged about $3.80 per thousand cubic feet (MCF) during 2009, compared with almost $9 during 2008. At December 31, 2009, and as of
mid-February 2010, the Henry Hub spot price was about $5.70 and $5.50 per MCF, respectively. Fluctuations in the price for natural gas in the United States are closely associated with customer demand relative to the volumes produced in North America and the level of inventory in underground storage. Weaker U.S. demand in 2009 was associated with the economic slowdown.
Certain international natural-gas markets in which the company operates have different supply, demand and regulatory circumstances, which historically have resulted in lower average sales prices for the companys production of natural gas in these locations. Chevron continues to invest in long-term projects in these locations to install infrastructure to produce and liquefy natural gas for transport by tanker to other markets where greater demand results in higher prices. International natural-gas realizations averaged about $4.00 per MCF during 2009, compared with about $5.20 per MCF during 2008. Unlike prior years, these realizations compared favorably with those in the United States during 2009, primarily as a result of the deterioration of U.S. supply-and-demand conditions resulting from the economic slowdown. (See page FS-10 for the companys average natural gas realizations for the U.S. and international regions.)
The companys worldwide net oil-equivalent production in 2009 averaged 2.70 million barrels per day. About one-fifth of the companys net oil-equivalent production in 2009 occurred in the OPEC-member countries of Angola, Nigeria and Venezuela and in the Partitioned Zone between Saudi Arabia and Kuwait. For the year 2009, the companys net oil production was reduced by an average of 20,000 barrels per day due to quotas imposed by OPEC. All of the imposed curtailments took place during the first half of the year. At the December 2009 meeting, members of OPEC supported maintaining production quotas in effect since December 2008.
The company estimates that oil-equivalent production in 2010 will average approximately 2.73 million barrels per day. This estimate is subject to many factors and uncertainties, including additional 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. The outlook for future production levels is also 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. Investments in upstream projects generally begin well in advance of the start of the associated crude-oil and natural-gas production. A significant majority of Chevrons upstream investment is made outside the United States.
Refer to the Results of Operations section on pages FS-6 through FS-7 for additional discussion of the companys upstream business.
Refer to Table V beginning on page FS-69 for a tabulation of the companys proved net oil and gas reserves by geographic area, at the beginning of 2007 and each year-end from 2007 through 2009, and an accompanying discussion of major changes to proved reserves by geographic area for the three-year period ending December 31, 2009.
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, cost of materials and services, refinery maintenance programs and disruptions at refineries resulting from unplanned outages due to severe weather, fires or other operational events.
Other factors affecting profitability for downstream operations include the reliability and efficiency of the companys refining and marketing network and the effectiveness of the crude-oil and product-supply functions. 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 significant ownership interests in refineries in each of these areas except Latin America. The company completed sales of marketing businesses during 2009 in certain countries in Latin America and Africa. The company plans to discontinue, by mid-2010, sales of Chevron- and Texaco-branded motor fuels in the mid-Atlantic and other eastern states, where the company sold to retail customers through approximately 1,100 stations and to commercial and industrial customers through supply arrangements. Sales in these markets
represent approximately 8 percent of the companys total U.S. retail fuel sales volumes. Additionally, in January 2010, the company sold the rights to the Gulf trademark in the United States and its territories that it had previously licensed for use in the U.S. Northeast and Puerto Rico.
The companys refining and marketing margins in 2009 were generally weak due to challenging industry conditions, including a sharp drop in global demand reflecting the economic slowdown, excess refined-product supplies and surplus refining capacity. Given these conditions, in January 2010 the company announced to its employees that high-level evaluations of Chevrons refining and marketing organizations had been completed. These evaluations concluded that the companys downstream organization should be restructured to improve operating efficiency and achieve sustained improvement in financial performance. Details of the restructuring will be further developed over the next three to six months and may include exits from additional markets, dispositions of assets, reductions in the number of employees and other actions, which may result in gains or losses in future periods.
Refer to the Results of Operations section on pages FS-7 and 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 chemical earnings.
Key operating developments and other events during 2009 and early 2010 included the following:
Angola Production began at the 39.2 percent-owned and operated Mafumeira Norte offshore project in Block 0 and the 31 percent-owned and operated deepwater Tombua-Landana project in Block 14. Mafumeira Norte is expected to reach maximum total daily production of 42,000 barrels of crude oil in the third quarter 2010, and the Tombua-Landana project is expected to reach its maximum total production of approximately 100,000 barrels of crude oil per day in 2011. The company also discovered crude oil offshore in the 39.2 percent-owned and operated Block 0 concession, extending a trend of earlier discoveries in the Greater Vanza/Longui Area.
Australia The company and its partners reached final investment decision to proceed with the development of the Gorgon Project, located offshore Western Australia, in which Chevron has a 47.3 percent-owned and operated interest as of December 31, 2009. In addition, the company finalized long-term sales agreements for delivery of liquefied natural gas (LNG) from the Gorgon Project with four Asian customers, three of which also acquired an ownership interest in the project. Nonbinding Heads of Agreement (HOAs) with three additional Asian customers were also signed in late 2009 and
early 2010 for delivery of LNG from the project. Negotiations continue to finalize binding sales agreements, which would bring LNG delivery commitments to a combined total of about 90 percent of Chevrons share of LNG from the project.
The company awarded front-end engineering and design contracts for the first phase of the Wheatstone natural gas project, also located offshore northwest Australia. The 75 percent-owned and
completion of a well at the Clio prospect to further explore and appraise the 66.7 percent-owned Block WA-205-P. In 2009 and early 2010, the company also announced natural-gas discoveries at the Kentish Knock prospect in the 50 percent-owned Block WA-365-P, the Achilles and Satyr prospects in the 50 percent-owned Block WA-374-P and the Yellowglen prospect in the 50 percent-owned WA-268-P Block. All prospects are Chevron-operated. Proved reserves have not been recognized for these discoveries.
Brazil Production started at the 51.7 percent-owned and operated deepwater Frade Field, which is projected to attain maximum total production of 72,000 oil-equivalent barrels per day in 2011. Also, in early 2010 a final investment decision was reached to develop the 37.5 percent-owned, partner-operated Papa-Terra Field, where first production is expected in 2013. Project facilities are designed with a capacity to handle up to 140,000 barrels of crude oil per day.
Republic of the Congo Crude oil was discovered in the northern portion of the 31.5 percent-owned, partner-operated Moho-Bilondo deepwater permit area. This discovery follows two others made in 2007 in the same permit area.
Managements Discussion and Analysis of
Financial Condition and Results of Operations
Venezuela In February 2010, a Chevron-led consortium was named the operator of a heavy-oil project composed of three blocks in the Orinoco Oil Belt of eastern Venezuela.
United States First oil was achieved at the 58 percent-owned and operated Tahiti Field in the deepwater Gulf of Mexico, reaching maximum total production of 135,000 barrels of oil-equivalent per day. The company also discovered crude oil at the Chevron-operated and 55 percent-owned Buckskin prospect in the deepwater Gulf of Mexico. The first appraisal well is scheduled to begin drilling in the second quarter 2010.
The company sold businesses during 2009 in Brazil, Haiti, Nigeria, Benin, Cameroon, Republic of the Congo, Côte dIvoire, Togo, Kenya, Uganda, India, Italy, Peru and Chile.
Common Stock Dividends The quarterly common stock dividend increased by 4.6 percent in July 2009, to $0.68 per share. 2009 was the 22nd consecutive year that the company increased its annual dividend payment.
Common Stock Repurchase Program The company did not acquire any shares during 2009 under its $15 billion repurchase program, which began in 2007 and expires in September 2010. As of December 31, 2009, 119 million common shares had been acquired under this program for $10.1 billion.
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. Earnings are also presented for the U.S. and international geographic areas of the upstream and downstream business segments. (Refer to Note 11, beginning on page FS-40, for a discussion of the companys reportable segments, as defined in accounting standards for segment reporting (Accounting Standards Codification (ASC) 280)). 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 earnings of $2.2 billion in 2009 decreased $4.9 billion from 2008. Lower prices for crude oil and natural gas reduced earnings by about $5.2 billion between periods, and gains on asset sales declined by approximately $900 million. Partially offsetting these effects was a benefit of about $1.3 billion resulting from an increase in net oil-equivalent production. An approximate $600 million benefit to income from lower operating expenses was more than offset by higher depreciation expense. The benefit from
lower operating expenses was largely associated with absence of charges for damages related to the 2008 hurricanes in the Gulf of Mexico.
U.S upstream earnings 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.
The companys average realization for crude oil and natural gas liquids in 2009 was $54.36 per barrel, compared with $88.43 in 2008 and $63.16 in 2007. The average natural-gas realization was $3.73 per thousand cubic feet in 2009, compared with $7.90 and $6.12 in 2008 and 2007, respectively.
Net oil-equivalent production in 2009 averaged 717,000 barrels per day, up 6.9 percent from 2008 and down 3.5 percent from 2007. The increase between 2008 and 2009 was mainly due to the start-up of the Blind Faith Field in late 2008 and the Tahiti Field in the second quarter 2009. The decrease between 2007 and 2008 was mainly due to normal field declines and the adverse impact of the hurricanes. The net liquids component of oil-equivalent production for 2009 averaged 484,000 barrels per day, up approximately 15 percent from 2008 and 5 percent compared with 2007. Net natural-gas production averaged 1.4 billion cubic feet per day in 2009, down approximately 7 percent from 2008 and about 18 percent from 2007.
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 earnings of $8.2 billion in 2009 decreased $6.4 billion from 2008. Lower prices for crude oil and natural gas reduced earnings by $7.0 billion, while foreign-currency effects and higher operating and depreciation expenses decreased income by a total of $2.2 billion. Partially offsetting these items were benefits of $2.3 billion resulting from an increase in sales volumes of crude oil and about $500 million associated with asset sales and tax items related to the Gorgon Project in Australia.
Earnings 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 a reduction to earnings of $417 million in 2007.
The companys average realization for crude oil and natural gas liquids in 2009 was $55.97 per barrel, compared with $86.51 in 2008 and $65.01 in 2007. The average natural-gas realization was $4.01 per thousand cubic feet in 2009, compared with $5.19 and $3.90 in 2008 and 2007, respectively.
Net oil-equivalent production of 1.99 million barrels per day in 2009 increased about 7 percent and 6 percent from 2008 and 2007, respectively. The volumes for each year included production from oil sands in Canada. Absent the impact of prices on certain production-sharing and variable-royalty agreements, net
oil-equivalent production increased 4 percent in 2009 and 3 percent in 2008, when compared with prior years production.
The net liquids component of oil-equivalent production was 1.4 million barrels per day in 2009, an increase of approximately 11 percent from 2008 and 5 percent from
2007. Net natural-gas production of 3.6 billion cubic feet per day in 2009 was down 1 percent and up 8 percent from 2008 and 2007, 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 operations lost $273 million in 2009, an earnings decrease of approximately $1.6 billion from 2008. A decline in refined product margins resulted in a negative earnings variance of $1.7 billion. Partially offsetting were lower operating expenses, which benefited earnings by $300 million. 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 2007 and 2008.
Sales volumes of refined products were 1.40 million barrels per day in 2009, a decrease of 1 percent from 2008. The decline was associated with reduced demand for jet fuel and fuel oil, principally associated with the downturn in the U.S. economy. Sales volumes of refined products were 1.41 million barrels per day in 2008, a decrease of 3 percent from 2007. Branded gasoline sales volumes of 617,000 barrels per day in 2009 were up about 3 percent and down 2 percent from 2008 and 2007, respectively.
Refer to the Selected Operating Data table on page FS-10 for a three-year comparison of sales volumes of gasoline and other refined products and refinery-input volumes.
Managements Discussion and Analysis of
Financial Condition and Results of Operations
International Downstream Refining, Marketing and Transportation
International downstream earnings of $838 million in 2009 decreased about $1.2 billion from 2008. An approximate $2.6 billion decline between periods was associated with weaker margins on the sale of gasoline and other refined products and the absence
refined products. Foreign-currency effects increased earnings by $193 million in 2008, compared with $62 million in 2007.
Refined-product sales volumes were 1.85 million barrels per day in 2009, about 8 percent lower than in 2008 due mainly to the effects of asset sales and lower demand. Refined-product sales volumes were 2.02 million barrels per day in 2008, about level with 2007.
Refer to the Selected Operating Data table, on page FS-10, for a three-year comparison of sales volumes of gasoline and other refined products and refinery-input volumes.
The chemicals segment includes the companys Oronite subsidiary and the 50 percent-owned Chevron Phillips Chemical Company LLC (CPChem). In 2009, earnings were $409 million, compared with $182 million and $396 million in 2008
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, Inc. prior to its sale in May 2007.
Net charges in 2009 decreased $468 million from 2008 due to lower provisions for environmental remediation at sites
that previously had been closed or sold, favorable foreign-currency effects and lower expenses for employee compensation and benefits. Net charges in 2008 increased $1.4 billion from 2007. Results in 2008 included net unfavorable corporate tax items and increased costs of environmental remediation. Foreign-currency effects also contributed to the increase in net charges from 2007 to 2008. 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.
Consolidated Statement of Income
Comparative amounts for certain income statement categories are shown below:
Sales and other operating revenues decreased in 2009, due mainly to lower prices for crude oil, natural gas and refined products. Higher 2008 prices resulted in increased revenues compared with 2007.
Income from equity affiliates decreased in 2009 from 2008. Upstream-related affiliate income declined about $1.3 billion mainly due to lower earnings for Tengizchevroil (TCO) in Kazakhstan as a result of lower prices for crude oil. Downstream-related affiliate earnings were lower by approximately $1.0 billion primarily due to weaker margins and an unfavorable swing in foreign-currency effects. Income from equity affiliates increased in 2008 from 2007 largely due to improved upstream-related earnings at TCO as a result of higher prices for crude oil. Refer to Note 12, beginning on page FS-43, for a discussion of Chevrons investments in affiliated companies.
Other income of $918 million in 2009 included gains of approximately $1.3 billion on asset sales. Other income of $2.7 billion in 2008 and 2007 included net gains from asset sales of $1.3 billion and $1.7 billion, respectively. Interest income was approximately $95 million in 2009, $340 million in 2008 and $600 million in 2007. Foreign-currency effects reduced other income by $466 million in 2009 while increasing other income by $355 million in 2008 and reducing other income by $352 million in 2007. In addition, other income in 2008 included approximately $700 million in favorable settlements and other items.
Crude oil and product purchases in 2009 decreased $71.7 billion from 2008 due to lower prices for crude oil, natural gas and refined products. 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.
Operating, selling, general and administrative expenses in 2009 decreased approximately $4.2 billion from 2008 primarily due to $1.4 billion of lower fuel and transportation expenses; $800 million of decreased costs for contract labor and professional services; absence of uninsured 2008 hurricane-related charges of $700 million; a decrease of about $500 million for environmental remediation activities; $200 million of lower costs for materials; and $600 million for other items. Total expenses for 2008 were about $3.7 billion higher than 2007 primarily due to $1.2 billion of higher costs for employee and contract labor and professional services; $600 million of increased transportation expenses; $700 million of uninsured losses associated with hurricanes in the Gulf of Mexico in 2008; an increase of about $300 million for environmental remediation activities; $200 million from higher material expenses; and $700 million from increases for other items.
Exploration expenses in 2009 increased from 2008 due mainly to higher amounts for well write-offs in the United States and international operations. Expenses in 2008 declined from 2007 mainly due to lower amounts for well write-offs for operations in the United States.
Depreciation, depletion and amortization expenses increased in 2009 from 2008 due to incremental production related to start-ups for upstream projects in the United States and Africa and higher depreciation rates for certain other oil and gas producing fields. The increase in 2008 from 2007 was 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.
Taxes other than on income decreased in 2009 from 2008 mainly due to lower import duties for the companys downstream operations in the United Kingdom. Taxes other than on income decreased in 2008 from 2007 mainly due to lower import duties as a result of the effects of the 2007 sales
Managements Discussion and Analysis of
Financial Condition and Results of Operations
of the companys Benelux refining and marketing businesses and a decline in import volumes in the United Kingdom.
Interest and debt expense increased in 2009 due to an increase in long-term debt. Interest and debt expense decreased in 2008 because all interest-related amounts were being capitalized.
Effective income tax rates were 43 percent in 2009, 44 percent in 2008 and 42 percent in 2007. The rate was lower in 2009 than in 2008 mainly due the effect in 2009 of deferred tax benefits and relatively low tax rates on asset sales, both related to an international upstream project. In addition, a greater proportion of before-tax income was earned in 2009 by equity affiliates than in 2008. (Equity-affiliate income is reported as a single amount on an
after-tax basis on the Consolidated Statement of Income.) Partially offsetting these items was the effect of a greater proportion of income earned in 2009 in tax jurisdictions with higher tax rates. The rate was higher in 2008 compared with 2007 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. Refer also to the discussion of income taxes in Note 15 beginning on page FS-46.
Selected Operating Data1,2
Liquidity and Capital Resources
Cash, cash equivalents and marketable securities Total balances were $8.8 billion and $9.6 billion at December 31, 2009 and 2008, respectively. Cash provided by operating activities in 2009 was $19.4 billion, compared with $29.6 billion in 2008 and $25.0 billion in 2007.
Cash provided by operating activities was net of contributions to employee pension plans of approximately $1.7 billion, $800 million and $300 million in 2009, 2008 and 2007, respectively. Cash provided by investing activities included proceeds and deposits related to asset sales of $2.6 billion in 2009, $1.5 billion in 2008 and $3.3 billion in 2007.
Restricted cash of $123 million and $367 million associated with various capital-investment projects at December 31, 2009 and 2008, respectively, was invested in short-term marketable securities and recorded as Deferred charges and other assets on the Consolidated Balance Sheet.
Dividends Dividends paid to common stockholders were approximately $5.3 billion in 2009, $5.2 billion in 2008 and $4.8 billion in 2007. In July 2009, the company increased its quarterly common stock dividend by 4.6 percent to $0.68 per share.
Debt and capital lease obligations Total debt and capital lease obligations were $10.5 billion at December 31, 2009, up from $8.9 billion at year-end 2008.
The $1.6 billion increase in total debt and capital lease obligations during 2009 included the net effect of a $5 billion public bond issuance, a $350 million issuance of tax-exempt Gulf Opportunity Zone bonds, a $3.2 billion decrease in commercial paper, and a $400 million payment of principal for Texaco Capital Inc. bonds that matured in January 2009. 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 $4.6 billion at
December 31, 2009, down from $7.8 billion at year-end 2008. Of these amounts, $4.2 billion and $5.0 billion were reclassified to long-term at the end of each period, respectively. At year-end 2009, settlement of these obligations was not expected to require the use of working capital in 2010, 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 2009, the company had $5.1 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. 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, 2009. 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. The company intends to file a new shelf registration statement when the current one expires.
The company has outstanding public bonds issued by Chevron Corporation, Chevron Corporation Profit Sharing/ Savings Plan Trust Fund, Texaco Capital Inc. and Union Oil Company of California. All of these securities are the obligations of, or 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. The company believes that it has substantial borrowing capacity to meet unanticipated cash requirements and that during periods of low prices for crude oil and natural gas and narrow margins for refined products and commodity chemicals, it 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 its common shares 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 (expiring in 2010) and may be discontinued at any time. The company did not acquire any shares during 2009 and does not plan to acquire any shares in the first quarter 2010. From the inception of the program, the company has acquired 119 million shares at a cost of $10.1 billion.
Managements Discussion and Analysis of
Financial Condition and Results of Operations
Capital and Exploratory Expenditures
The company estimates that in 2010, capital and exploratory expenditures will be $21.6 billion, including $1.6 billion of spending by affiliates. About 80 percent of the total, or $17.3 billion, is budgeted for exploration and production activities, with $13.2 billion of this amount for projects outside the United States. Spending in 2010 is primarily targeted for exploratory prospects in the U.S. Gulf of Mexico and major development projects in Angola, Australia, Brazil, Canada, China, Nigeria, Thailand and the U.S. Gulf of Mexico. Also included is funding for base business improvements and focused appraisals in core hydrocarbon basins.
Worldwide downstream spending in 2010 is estimated at $3.4 billion, with about $1.6 billion for projects in the
United States. Major capital outlays include projects under construction at refineries in the United States and South Korea and construction of gas-to-liquids facilities in support of associated upstream projects.
Investments in chemicals, technology and other corporate businesses in 2010 are budgeted at $900 million. Technology investments include projects related to unconventional hydrocarbon technologies, oil and gas reservoir management, and gas-fired and renewable power generation.
Noncontrolling interests The company had noncontrolling interests of $647 million and $469 million at December 31, 2009 and 2008, respectively. Distributions to noncontrolling interests totaled $71 million and $99 million in 2009 and 2008, respectively.
Pension Obligations In 2009, the companys pension plan contributions were $1.7 billion (including $1.5 billion to the U.S. plans and $200 million to the international plans). The company estimates contributions in 2010 will be approximately $900 million ($600 million for the U.S. plans and $300 million for the international plans). Actual contribution amounts are dependent upon investment returns, changes in pension obligations, regulatory environments and other economic factors. Additional funding may ultimately 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 2009, the book value of inventory
was lower than replacement costs, based on average acquisition costs during the year, by approximately $5.5 billion.
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 over time 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 2009, 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 origi-
nally 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 had to be asserted by February 2009 for Equilon indemnities and must be asserted 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. Management does not believe this letter or any other information provides a basis to estimate the amount, if any, of a range of loss or potential range of loss with respect to either the 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 in the preceding paragraph 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. The acquirer of those assets shared in certain environmental remediation costs up to a maximum obligation of $200 million, which had been reached at December 31, 2009. Under the indemnification agreement, after reaching the $200 million obligation, Chevron is solely responsible until April 2022, when the indemnification expires. The environmental conditions or events that are subject to these indemnities must have arisen prior to the sale of the assets in 1997.
Although the company has provided for known obligations under this indemnity 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.
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: 2010 $7.5 billion; 2011 $4.3 billion; 2012 $1.4 billion; 2013 $1.4 billion; 2014 $1.0 billion; 2015 and after $4.1 billion. A portion of these commitments may ultimately be shared with project
Managements Discussion and Analysis of
Financial Condition and Results of Operations
partners. Total payments under the agreements were approximately $8.1 billion in 2009, $5.1 billion in 2008 and $3.7 billion in 2007.
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 2009 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 these activities were not material to the companys financial position, results of operations or cash flows in 2009.
The companys market exposure positions are monitored and managed on a daily basis by an internal Risk Control group in accordance with the companys risk management policies, which have been approved by the Audit Committee of the companys Board of Directors.
The derivative commodity instruments used in the companys risk management and trading activities consist mainly of futures, options and swap contracts traded on the New York Mercantile Exchange and on electronic platforms of the Inter-Continental Exchange and 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 2009 was a quarterly average decrease of $168 million in total assets and a quarterly average decrease of $104 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 commodity instruments held or issued, which are recorded on the balance sheet at
December 31, 2009, as derivative commodity instruments in accordance with accounting standards for derivatives (ASC 815). 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, 2009 and 2008. The lower amounts in 2009 were primarily associated with a decrease in price volatility for these commodities during the year.
Foreign Currency The company may enter into foreign-currency derivative contracts to manage some of its foreign-currency exposures. These exposures include revenue and anticipated purchase transactions, including foreign-currency capital expenditures and lease commitments. The foreign-currency derivative contracts, if any, are recorded at fair value on the balance sheet with resulting gains and losses reflected in income. There were no open foreign-currency derivative contracts at December 31, 2009.
Interest Rates The company may enter into interest rate swaps from time to time as part of its overall strategy to manage the interest rate risk on its debt. Historically, under the terms of the swaps, net cash settlements were 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, if any, may be accounted for as fair value hedges. Interest rate swaps related to floating-rate debt, if any, are recorded at fair value on the balance sheet with resulting gains and losses reflected in income. At year-end 2009, 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 and the company had no interest rate swaps on
fixed-rate debt at year-end 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 Financial Information in Note 24 of the Consolidated Financial Statements, page FS-61, 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. Chevron is a party to 50 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 companys ultimate exposure related to pending lawsuits and claims is not 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.
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; 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
Managements Discussion and Analysis of
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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, which the court dismissed. In September 2009, following the disclosure by Chevron of evidence that the judge participated in meetings in which businesspeople and individuals holding themselves out as government officials discussed the case and its likely outcome, the judge presiding over the case petitioned to be recused. In late September 2009, the judge was recused, and in October 2009, the full chamber of the provincial court affirmed the recusal, resulting in the appointment of a new judge. Chevron filed motions to annul all of the rulings made by the prior judge, but the new judge denied these motions. The court has completed most of the procedural aspects of the case and could render a judgment at any time. Chevron will continue a vigorous defense of any attempted imposition of liability.
In the event of an adverse judgment, Chevron would expect to pursue its appeals and vigorously defend against enforcement of any such judgment; therefore, the ultimate outcome and any financial effect on Chevron remains uncertain. 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 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).
Environmental The company is subject to loss contingencies pursuant to laws, regulations, private claims and legal proceedings related to environmental matters that are subject to legal settlements or 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 $1,700 million year-end 2009 reserve balance were remediation activities at approximately 250 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 2009 was $185 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 results of operations, consolidated financial position or liquidity.
Of the remaining year-end 2009 environmental reserves balance of $1,515 million, $820 million related to the companys U.S. downstream operations, including refineries and other plants, marketing locations (i.e., service stations and terminals), and pipelines. The remaining $695 million was associated with various sites in international downstream ($107 million), upstream ($369 million), chemicals ($149 million) and other businesses ($70 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 and local regulations. No single remediation site at year-end 2009 had a recorded liability that was material to the companys results of operations, consolidated financial position 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.
Under accounting standards for asset retirement obligations
(ASC 410), 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 $10.2 billion for asset retirement obligations at year-end 2009 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 23 on page FS-60, related to the companys asset retirement obligations and the discussion of Environmental Matters on page FS-18.
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 15 beginning on page FS-46 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 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.
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, 2009, the company had approximately $2.4 billion of suspended exploratory wells included in properties, plant and equipment, an increase of $317 million from 2008. The 2008 balance reflected an increase of $458 million from 2007.
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 $2.4 billion of suspended wells at year-end 2009 is uncertain pending future activities, including normal project evaluation and additional drilling.
Refer to Note 19, beginning on page FS-50, for additional discussion of suspended wells.
Equity Redetermination For oil and gas producing operations, ownership agreements may provide for periodic reassessments of equity interests in estimated crude-oil and natural-gas reserves. These activities, individually or together, may result in gains or losses that could be material to earnings in any given period. One such equity redetermination process has been under way since 1996 for Chevrons interests in four producing zones at the Naval Petroleum Reserve at Elk Hills, California, for the time when the remaining interests in these zones were owned by the U.S. Department of Energy. A wide range remains for a possible net settlement amount for the four zones. For this range of settlement, Chevron estimates its maximum possible net before-tax liability at approximately $200 million, and the possible maximum net amount that could be owed to Chevron is estimated at about $150 million. The timing of the settlement and the exact amount within this range of estimates are uncertain.
Other Contingencies Chevron receives claims from and submits claims to customers; trading partners; U.S. federal, state and local regulatory bodies; governments; contractors; insurers; and suppliers. The amounts of these claims, individually and in the aggregate, may be significant and take lengthy periods to resolve.
Managements Discussion and Analysis of
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The company and its affiliates also continue to review and analyze their operations and may close, abandon, sell, exchange, acquire or restructure assets to achieve operational or strategic benefits and to improve competitiveness and profitability. These activities, individually or together, may result in gains or losses in future periods.
Virtually all aspects of the businesses in which the company engages are subject to various federal, state and local environmental, health and safety laws and regulations. These regulatory requirements continue to increase in both number and complexity over time and govern not only the manner in which the company conducts its operations, but also the products it sells. Most of the costs of complying with laws and regulations pertaining to company operations and products are embedded in the normal costs of doing business.
Accidental leaks and spills requiring cleanup may occur in the ordinary course of business. In addition to the costs for environmental protection associated with its ongoing operations and products, the company may incur expenses for corrective actions at various owned and previously owned facilities and at
third-party-owned waste-disposal sites used by the company. An obligation may arise when operations are closed or sold or at non-Chevron sites where company products have been handled or disposed of. Most of the expenditures to fulfill these obligations relate to facilities and sites where past operations followed practices and procedures that were considered acceptable at the time but now require investigative or remedial work or both to meet current standards.
Using definitions and guidelines established by the American Petroleum Institute, Chevron estimated its worldwide environmental spending in 2009 at approximately $3.5 billion for its consolidated companies. Included in these expenditures were approximately $1.7 billion of environmental capital expenditures and $1.8 billion of costs associated with the prevention, control, abatement or elimination of hazardous substances and pollutants from operating, closed or divested sites, and the abandonment and restoration of sites.
For 2010, total worldwide environmental capital expenditures are estimated at $2.1 billion. These capital costs are in addition to the ongoing costs of complying with environmental regulations and the costs to remediate previously contaminated sites.
It is not possible to predict with certainty the amount of additional investments in new or existing facilities or amounts of incremental operating costs to be incurred in the future to: prevent, control, reduce or eliminate releases of hazardous materials into the environment; comply with exist-
ing and new environmental laws or regulations; or remediate and restore areas damaged by prior releases of hazardous materials. Although these costs may be significant to the results of operations in any single period, the company does not expect them to have a material effect on the companys liquidity or financial position.
Critical Accounting Estimates and Assumptions
Management makes many estimates and assumptions in the application of generally accepted accounting principles (GAAP) that may have a material impact on the companys consolidated financial statements and related disclosures and on the comparability of such information over different reporting periods. All such estimates and assumptions affect reported amounts of assets, liabilities, revenues and expenses, as well as disclosures of contingent assets and liabilities. Estimates and assumptions are based on managements experience and other information available prior to the issuance of the financial statements. Materially different results can occur as circumstances change and additional information becomes known.
The discussion in this section of critical accounting estimates and assumptions is according to the disclosure guidelines of the Securities and Exchange Commission (SEC), wherein:
Besides those meeting these critical criteria, the company makes many other accounting estimates and assumptions in preparing its financial statements and related disclosures. Although not associated with highly uncertain matters, these estimates and assumptions are also subject to revision as circumstances warrant, and materially different results may sometimes occur.
For example, the recording of deferred tax assets requires an assessment under the accounting rules that the future realization of the associated tax benefits be more likely than not. Another example is the estimation of crude-oil and natural-gas reserves under SEC rules, which, effective December 31, 2009, require ...by analysis of geosciences and engineering data, (the reserves) can be estimated with reasonable certainty to be economically producible...under existing economic conditions where existing economic conditions include prices based on the average price during the
12-month period. Refer to Table V, Reserve Quantity Information, beginning on page FS-69, for the changes in these estimates for the three years ending December 31, 2009, and to Table VII, Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves on page FS-77 for estimates of
proved-reserve values for each of the three years ended December 31, 2009. Note 1 to the Consolidated Financial Statements, beginning on page FS-32, includes a description of the successful efforts method of accounting for oil and gas exploration and production activities. The estimates of crude-oil and natural-gas reserves are important to the timing of expense recognition for costs incurred.
The discussion of the critical accounting policy for Impairment of Properties, Plant and Equipment and Investments in Affiliates, beginning on page FS-20, includes reference to conditions under which downward revisions of proved-reserve quantities could result in impairments of oil and gas properties. This commentary should be read in conjunction with disclosures elsewhere in this discussion and in the Notes to the Consolidated Financial Statements related to estimates, uncertainties, contingencies and new accounting standards. Significant accounting policies are discussed in Note 1 to the Consolidated Financial Statements, beginning on page FS-32. The development and selection of accounting estimates and assumptions, including those deemed critical, and the associated disclosures in this discussion have been discussed by management with the Audit Committee of the Board of Directors.
The areas of accounting and the associated critical estimates and assumptions made by the company are as follows:
Pension and Other Postretirement Benefit Plans The determination of pension-plan obligations and expense is based on a number of actuarial assumptions. Two critical assumptions are the expected long-term rate of return on plan assets and the discount rate applied to pension plan obligations. For other postretirement benefit (OPEB) plans, which provide for certain health care and life insurance benefits for qualifying retired employees and which are not funded, critical assumptions in determining OPEB obligations and expense are the discount rate and the assumed health care
Note 21, beginning on page FS-52, includes information on the funded status of the companys pension and OPEB plans at the end of 2009 and 2008; the components of pension and OPEB expense for the three years ending December 31, 2009; and the underlying assumptions for those periods.
Pension and OPEB expense is reported on the Consolidated Statement of Income as Operating expenses or Selling, general and administrative expenses and applies to all business segments. The year-end 2009 and 2008 funded status, measured as the difference between plan assets and obligations, of each of the companys pension and OPEB plans is recognized on the Consolidated Balance Sheet. The
differences related to overfunded pension plans are reported as a long-term asset in Deferred charges and other assets. The differences associated with underfunded or unfunded pension and OPEB plans are reported as Accrued liabilities or Reserves for employee benefit plans. Amounts yet to be recognized as components of pension or OPEB expense are reported in Accumulated other comprehensive loss.
To estimate the long-term rate of return on pension assets, the company uses a process that incorporates actual historical asset-class returns and an assessment of expected future performance and takes into consideration external actuarial advice and asset-class factors. Asset allocations are periodically updated using pension plan asset/liability studies, and the determination of the companys estimates of long-term rates of return are consistent with these studies. The expected long-term rate of return on U.S. pension plan assets, which account for 69 percent of the companys pension plan assets, has remained at 7.8 percent since 2002. For the 10 years ending December 31, 2009, actual asset returns averaged 3.7 percent for this plan. The actual return for 2009 was 15.7 percent and was associated with the broad recovery in the financial markets.
The year-end market-related value of assets of the major U.S. pension plan used in the determination of pension expense was based on the market value in the preceding three months, as opposed to the maximum allowable period of five years under U.S. accounting rules. Management considers the three-month period long enough to minimize the effects of distortions from day-to-day market volatility and still be contemporaneous to the end of the year. For other plans, market value of assets as of year-end is used in calculating the pension expense.
The discount rate assumptions used to determine U.S. and international pension and postretirement benefit plan obligations and expense reflect the prevailing rates available on high-quality fixed-income debt instruments. At December 31, 2009, the company selected a 5.3 percent discount rate for the major U.S. pension plan and 5.8 percent for its OPEB plan. These rates were selected based on a cash flow analysis that matched estimated future benefit payments to the Citigroup Pension Discount Yield Curve as of year-end 2009. The discount rates at the end of 2008 and 2007 were 6.3 percent for both years for the U.S. pension and OPEB plans.
An increase in the expected long-term return on plan assets or the discount rate would reduce pension plan expense, and vice versa. Total pension expense for 2009 was $1.1 billion. As an indication of the sensitivity of pension expense to the long-term rate of return assumption, a 1 percent increase in the expected rate of return on assets of the companys primary U.S. pension plan would have reduced total pension plan expense for 2009 by approximately $50 million. A 1 percent increase in the discount rate for this same plan, which accounted for about 61 percent of the
Managements Discussion and Analysis of
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companywide pension obligation, would have reduced total pension plan expense for 2009 by approximately $150 million.
An increase in the discount rate would decrease the pension obligation, thus changing the funded status of a plan reported on the Consolidated Balance Sheet. The total pension liability on the Consolidated Balance Sheet at December 31, 2009, for underfunded plans was approximately $3.8 billion. As an indication of the sensitivity of pension liabilities to the discount rate assumption, a 0.25 percent increase in the discount rate applied to the companys primary U.S. pension plan would have reduced the plan obligation by approximately $300 million, which would have decreased the plans underfunded status from approximately $1.6 billion to $1.3 billion. Other plans would be less underfunded as discount rates increase. The actual rates of return on plan assets and discount rates may vary significantly from estimates because of unanticipated changes in the worlds financial markets.
In 2009, the companys pension plan contributions were $1.7 billion (including $1.5 billion to the U.S. plans). In 2010, the company estimates contributions will be approximately $900 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.
For the companys OPEB plans, expense for 2009 was $164 million and the total liability, which reflected the unfunded status of the plans at the end of 2009, was $3.1 billion.
As an indication of discount rate sensitivity to the determination of OPEB expense in 2009, a 1 percent increase in the discount rate for the companys primary U.S. OPEB plan, which accounted for about 69 percent of the companywide OPEB expense, would have decreased OPEB expense by approximately $11 million. A 0.25 percent increase in the discount rate for the same plan, which accounted for about 84 percent of the companywide OPEB liabilities, would have decreased total OPEB liabilities at the end of 2009 by approximately $65 million.
For the main U.S. postretirement medical plan, the annual increase to company contributions is limited to 4 percent per year. For active employees and retirees under age 65 whose claims experiences are combined for rating purposes, the assumed health care cost-trend rates start with 7 percent in 2010 and gradually drop to 5 percent for 2018 and beyond. As an indication of the health care cost-trend rate sensitivity to the determination of OPEB expense in 2009, a 1 percent
increase in the rates for the main U.S. OPEB plan, which accounted for 84 percent of the companywide OPEB liabilities, would have increased OPEB expense $8 million.
Differences between the various assumptions used to determine expense and the funded status of each plan and actual experience are not included in benefit plan costs in the year the difference occurs. Instead, the differences are included in actuarial gain/loss and unamortized amounts have been reflected in Accumulated other comprehensive loss on the Consolidated Balance Sheet. Refer to Note 21, beginning on page FS-52, for information on the $6.7 billion of before-tax actuarial losses recorded by the company as of December 31, 2009; a description of the method used to amortize those costs; and an est