Chevron - 10-K annual report 2010

 

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, 2010

OR

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

SECURITIES EXCHANGE ACT OF 1934

For the transition period from          to          

 

Commission File Number001-00368

(Exact name of registrant as specified in its charter)

 

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

 

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

 

 

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
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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.
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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 ofRegulation 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 ofRegulation S-K(§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of thisForm 10-Kor any amendment to thisForm 10-K.  o

 

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

 

 

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

 

Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter — $136,438,881,628 (As of June 30, 2010)

Number of Shares of Common Stock outstanding as of February 18, 2011 — 2,007,449,583

DOCUMENTS INCORPORATED BY REFERENCE

(To The Extent Indicated Herein)

Notice of the 2011 Annual Meeting and 2011 Proxy Statement, to be filed pursuant toRule 14a-6(b)under the Securities Exchange Act of 1934, in connection with the company’s 2011 Annual Meeting of Stockholders (in Part III)

 

 

 

This Annual Report onForm 10-Kof Chevron Corporation contains forward-looking statements relating to Chevron’s operations that are based on management’s current expectations, estimates and projections about the petroleum, chemicals and other energy-related industries. Words such as “anticipates,” “expects,” “intends,” “plans,” “targets,” “projects,” “believes,” “seeks,” “schedules,” “estimates,” “budgets” and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, some of which are beyond the company’s control and are difficult to predict. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements. The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this report. Unless legally required, Chevron undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.

 

Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are: 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 company’s joint-venture partners to fund their share of operations and development activities; the potential failure to achieve expected net production from existing and future crude oil and natural gas development projects; potential delays in the development, construction orstart-up of planned projects; the potential disruption or interruption of the company’s net production or manufacturing facilities or delivery/transportation networks due to war, accidents, political events, civil unrest, severe weather or crude oil production quotas that might be imposed by 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 company’s 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 32 through 34 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 onforward-lookingstatements.

 

 

 

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. Upstream operations consist primarily of exploring for, developing and producing crude oil and natural gas; processing, liquefaction, transportation and regasification associated with liquefied natural gas; transporting crude oil by major international oil export pipelines; transporting, storage and marketing of natural gas; and agas-to-liquidsproject. Downstream operations consist primarily of refining of crude oil into petroleum products; marketing of crude oil and refined products; transporting of crude oil and refined products by pipeline, marine vessel, motor equipment and rail car; and manufacturing and marketing of commodity petrochemicals, plastics for industrial uses and fuel and lubricant additives.

 

A list of the company’s major subsidiaries is presented onpages E-4and E-5. As of December 31, 2010, Chevron had approximately 62,000 employees (including about 3,900 service station employees). Approximately 30,000 employees (including about 3,600 service station employees), or 48 percent, were employed in U.S. operations.

 

Petroleum industry operations and profitability are influenced by many factors, and individual petroleum companies have little control over some of them. Governmental policies, particularly in the areas of taxation, energy and the environment have a significant impact on petroleum activities, regulating how companies are structured and where and how companies conduct their operations and formulate their products and, in some cases, limiting their profits directly. Prices for crude oil, natural gas, petroleum products and petrochemicals are generally determined by supply and demand for these commodities. However, some governments impose price controls on refined products such as gasoline or diesel fuel. The members of the Organization of Petroleum Exporting Countries (OPEC) are typically the world’s swing producers of crude oil and their production levels are a major factor in determining worldwide supply. Demand for crude oil and its products and for natural gas is largely driven by the conditions of local, national and global economies, although weather patterns and taxation relative to other energy sources also play a significant part. Seasonality is not a primary driver of changes in the company’s quarterly earnings during the year.

 

Strong competition exists in all sectors of the petroleum and petrochemical industries in supplying the energy, fuel and chemical needs of industry and individual consumers. Chevron competes with fully integrated, major global petroleum companies, as well as independent and national petroleum companies, for the acquisition of crude oil and natural gas leases and other properties and for the equipment and labor required to develop and operate those properties. In its downstream business, Chevron also competes with fully integrated, major petroleum companies and other independent refining, marketing, transportation and chemicals 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-10 of thisForm 10-Kin Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of the company’s current business environment and outlook.

 

 

 

Chevron’s primary objective is to create shareholder value and achieve sustained financial returns from its operations that will enable it to outperform its competitors. In the upstream, the company’s strategies are to grow profitably in core areas, build new legacy positions and commercialize the company’s equity natural gas resource base while growing a high-impact global gas business. In the downstream, the strategies are to improve returns and grow earnings across the value chain. The company also continues to utilize technology across all its businesses to differentiate performance, and to invest in profitable renewable energy and energy efficiency solutions.

 

The upstream and downstream activities of the company and its equity affiliates are widely dispersed geographically, with operations in North America, South America, Europe, Africa, Asia and Australia. Tabulations of segment sales and other operating revenues, earnings and income taxes for the three years ending December 31, 2010, and assets as of the end of 2010 and 2009 — for the United States and the company’s international geographic areas — are in Note 11 to the Consolidated Financial Statements beginning onpage FS-41.Similar comparative data for the company’s investments in and income from equity affiliates and property, plant and equipment are in Notes 12 and 13 on pages FS-43 through FS-45.

 

Total expenditures for 2010 were $21.8 billion, including $1.4 billion for the company’s share of equity-affiliate expenditures. In 2009 and 2008, expenditures were $22.2 billion and $22.8 billion, respectively, including the company’s share of affiliates’ expenditures of $1.6 billion in 2009 and $2.3 billion in 2008.

 

Of the $21.8 billion in expenditures for 2010, 87 percent, or $18.9 billion, was related to upstream activities. Approximately 80 percent was expended for upstream operations in 2009 and 2008. International upstream accounted for about 82 percent of the worldwide upstream investment in 2010, more than 80 percent in 2009 and about 70 percent in 2008, reflecting the company’s continuing focus on opportunities available outside the United States.

 

In 2011, the company estimates capital and exploratory expenditures will be $26.0 billion, including $2.0 billion of spending by affiliates. Approximately 85 percent of the total, or $22.6 billion, is budgeted for exploration and production activities, with $17.2 billion of that amount for projects outside the United States. Acquisition costs associated with the announced purchase of Atlas Energy, Inc., are not included.

 

Refer also to a discussion of the company’s capital and exploratory expenditures onpage FS-13.

 

The table on the following page summarizes the net production of liquids and natural gas for 2010 and 2009 by the company and its affiliates. Worldwide oil-equivalent production, including volumes from synthetic oil in 2010 and oil sands in 2009, was 2.763 million barrels per day, up about 2 percent from 2009. The increase was mainly associated with thestart-up andramp-up of several major capital projects — the expansion at Tengiz in Kazakhstan, the Tahiti Field in the U.S. Gulf of Mexico, Frade in Brazil, Agbami in Nigeria, andTombua-Landanaand Mafumeira Norte in Angola. Normal field declines and the impact of higher prices on cost-recovery volumes and other contractual provisions decreased net production from last year’s comparative period. Refer to the “Results of Operations” section beginning onpage FS-7for a detailed discussion of the factors explaining the 2008 — 2010 changes in production for crude oil and natural gas liquids, and natural gas.

 

The company estimates its average worldwide oil-equivalent production in 2011 will be approximately 2.790 million barrels per day based on the average West Texas Intermediate crude oil price of $79 per barrel in 2010. 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 production-sharing and variable-royalty provisions of certain agreements, 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, delays in completion of maintenance turnarounds,greater-than-expecteddeclines in production from mature fields, 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. Refer to the “Review of Ongoing Exploration and Production Activities in Key Areas,” beginning on page 9, for a discussion of the company’s major crude oil and natural gas development projects.

 

Refer to Table IV onpage FS-71for the company’s 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 2010, 2009 and 2008.

 

The following table summarizes gross and net productive wells at year-end 2010 for the company and its affiliates:

 

The net proved reserve balances at the end of each of the three years 2008 through 2010 are shown in the following table.

 

 

At December 31, 2010, 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 company’s acreage is shown in the following table.

 

 

The company sells crude oil and natural gas from its producing operations under a variety of contractual obligations. Most contracts generally commit the company to sell quantities based on production from specified properties, but some natural gas sales contracts specify delivery of fixed and determinable quantities, as discussed below.

 

In the United States, the company is contractually committed to deliver to third parties 253 billion cubic feet of natural gas through 2013. The company believes it can satisfy these contracts through a combination of equity production from the company’s proved developed U.S. reserves and third party purchases. These contracts include a variety of pricing terms, including both index and fixed-price contracts.

 

Outside the United States, the company is contractually committed to deliver a total of 953 billion cubic feet of natural gas from 2011 through 2013 from Australia, Colombia, Denmark and the Philippines to third parties. The sales contracts contain variable pricing formulas that are generally referenced to the prevailing market price for crude oil, natural gas or other petroleum products at the time of delivery. The company believes it can satisfy these contracts from quantities available from production of the company’s proved developed reserves in these countries.

 

Refer to Table I onpage FS-66for details associated with the company’s development expenditures and costs of proved property acquisitions for 2010, 2009 and 2008.

 

The table below summarizes the company’s net interest in productive and dry development wells completed in each of the past three years and the status of the company’s development wells drilling at December 31, 2010. A “development well” is a well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

 

 

The following table summarizes the company’s net interests in productive and dry exploratory wells completed in each of the last three years and the number of exploratory wells drilling at December 31, 2010. “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.

 

 

 

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 2010 was 708,000 barrels per day.

 

In California, the company has significant production in the San Joaquin Valley. In 2010, average net oil-equivalent production was 199,000 barrels per day, composed of 178,000 barrels of crude oil, 96 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).

regions. During the moratorium, Chevron participated in a number of industry efforts to identify opportunities to improve industry standards in prevention, intervention and spill response. In July 2010, Chevron and several other major energy companies announced plans to build and deploy a rapid response system that will be available to capture and contain oil in the unlikely event of a potential future well blowout in the deepwater Gulf of Mexico. In October 2010, the Secretary of the Interior lifted the moratorium on deepwater drilling activity, provided that operators certify compliance with new rules and requirements. The drilling moratorium and the ensuing slowdown in issuing drilling permits have resulted in delays in shallow water drilling activity, delayed drilling of exploratory deepwater wells and impacted development drilling on both operated and nonoperated projects in the Gulf of Mexico. In addition, the company’s net oil-equivalent production in the Gulf of Mexico was reduced by about 10,000 barrels per day for the full year.

 

Chevron was engaged in various exploration and development activities in the deepwater Gulf of Mexico during 2010. First oil at the Perdido Regional Development was achieved in first quarter 2010. The development includes a 37.5 percent nonoperated working interest in a producing host facility in Alaminos Canyon designed to service multiple nonoperated fields, including Chevron’s 33.3 percent-owned Great White, 60 percent-owned Silvertip and 57.5 percent-owned Tobago. The development has an expected production life of approximately 25 years.

 

The final investment decision was made for the Tahiti 2 waterflood project in third quarter 2010. Tahiti 2 is the second development phase for the 58 percent-owned and operated Tahiti Field and is designed to increase recovery and maintain

production near the facility capacity of 125,000 barrels of oil per day. The project includes three water injection wells, two additional production wells and the facilities required to deliver water to the injection wells. Drilling began on the first water injection well in September 2010. The field has an estimated production life of 30 years. As of the end of 2010, proved reserves had not been recognized for this second development phase of the Tahiti Field.

 

During 2010, work continued at the 60 percent-owned and operated Big Foot discovery. The project completed front-end engineering and design (FEED) in June 2010 and a final investment decision was made in December 2010. Total maximum production is expected to reach 79,000 barrels of oil-equivalent per day. First production is expected in 2014, and at the end of 2010 proved reserves had not been recognized. The field has an estimated production life of 20 years.

 

The topsides modifications to the host facility of the Caesar/Tonga Project were completed in 2010. The company has a 20.3 percent nonoperated working interest in the Caesar and Tonga partnerships unitized area. Development plans include a total of four wells and a subsea tieback to a nearby third-party production facility. Work on the subsea system, commissioning of the topsides and the initial well completion program carried over into 2011. A recent mechanical issue involving the production riser system has delayed first production. Proved reserves have been recognized for the project.

 

The Jack and St. Malo fields are located within 25 miles of each other and are being jointly developed. Chevron has a 50 percent working interest in Jack and a 51 percent working interest in St. Malo, following the acquisition of an additional 9.8 percent equity interest in St. Malo in March 2010. Both fields are company operated. The FEED activities initiated in 2009 continued into 2010, and a final investment decision was achieved in October 2010. The facility is planned to have an initial design capacity of 177,000 barrels of oil-equivalent per day. Total project costs for the initial phase of development are estimated at $7.5 billion andstart-up is expected in 2014. The project has an estimated production life of 30 years. At the end of 2010, proved reserves had not been recognized.

 

Assessment of development concepts continued in 2010 for the appraised resource potential on the Mad Dog II Development Project, in which the company has a 15.6 percent nonoperated working interest. These areas are outside the drilling radius of the existing floating production facility. A decision on the development concept, followed by the project moving into the FEED stage, is expected to occur in the second-half 2011. At the end of 2010, proved reserves had not been recognized.

 

Studies to screen and evaluate future development alternatives in the Tubular Bells unitized area, in which the company has a 30 percent nonoperated working interest, continued into 2010, and a subsea tieback to a planned third-party host facility was selected as the development concept. FEED commenced in fourth quarter 2010 with a final investment decision expected in second quarter 2011. At the end of 2010, proved reserves had not been recognized.

 

Deepwater exploration activities in 2010 included participation in five exploratory wells — two wildcat, two appraisal and one delineation. Drilling operations on two exploratory wells were interrupted and stopped in second quarter 2010 as a result of the deepwater drilling moratorium in the Gulf of Mexico, including drilling of the first appraisal well at the 55 percent-owned and operated Buckskin discovery. The first appraisal well at Knotty Head was completed in March 2010 and interpretation of well results continued into 2011. Chevron has a 25 percent nonoperated working interest in the Knotty Head discovery. At the end of 2010, the company had not recognized proved reserves for any of these exploration projects.

 

During 2010, the company added 15 new leases to its deepwater portfolio as a result of bid awards stemming from a Gulf of Mexico lease sale early in the year.

 

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 to enable the import of natural gas for the North America market. 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 pipeline provides access to two major salt dome storage fields and 10 major interstate pipeline systems, including an interconnect with Chevron’s Sabine Pipeline, which connects to the Henry Hub. The Henry Hub interconnects to nine interstate and four intrastate pipelines and is the pricing point for natural gas futures contracts traded on the New York Mercantile Exchange.

 

Outside California and the Gulf of Mexico, the company manages operations across the mid-continental United States and Alaska. During 2010, the company’s U.S. production outside California and the Gulf of Mexico averaged 249,000 net oil-equivalent barrels per day, composed of 91,000 barrels of crude oil, 773 million cubic feet of natural gas and 29,000 barrels of natural gas liquids.

The company continues to pursue its interest in tight carbonate oil resources in West Texas in the Wolfcamp and associated formations where advances in drilling and completion technologies have opened up widespread targets such as the 100 percent-owned and operated Lupin Project, where first oil was realized in mid-2010. Additional production growth is expected from both operated and nonoperated interests in these formations in future years through continued use of these advances in drilling and completion technologies. The company also continued the appraisal of the Haynesville shale gas play in East Texas.

 

In the Piceance Basin in northwestern Colorado, the company continued development of its 100 percent-owned and operated natural gas field. Development drilling and completion activities continued in 2010, with 115 completed wells available to supply natural gas to the central processing facility. The 2010 work plan focused on optimization of the existing wells and facilities, completion of previously drilled wells, and designing a pilot to test liquefied petroleum gas (LPG) as an alternative fracture fluid beginning in fourth quarter 2011. 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 2010.

 

In February 2011, Chevron acquired Atlas Energy, Inc. The acquisition provides an attractive natural gas resource position in the Appalachian basin, primarily located in southwestern Pennsylvania, and consists of approximately 850,000 total acres of Marcellus Shale and Utica Shale. The acquisition provides a 49 percent interest in Laurel Mountain Midstream, LLC, an affiliate that owns more than 1,000 miles of natural gas gathering lines servicing the Marcellus. The acquisition also provides assets in Michigan, which include Antrim Shale producing assets and approximately 380,000 total acres in the Antrim and Collingwood/Utica Shale.

 

“Other Americas” is composed of Canada, Greenland, Argentina, Brazil, Colombia, Trinidad and Tobago, and Venezuela. Net oil-equivalent production from these countries averaged 247,000 barrels per day during 2010, including the company’s share of synthetic oil production.

production from the HSE unitized area is expected in late 2011. At the end of 2010, proved reserves had not been recognized for the unitized blocks.

 

FEED commenced in third quarter 2010 for the development of the heavy-oil Hebron Field. The project has an expected economic life of 30 years. At the end of 2010, proved reserves had not been recognized for this project.

 

At AOSP, the company’s production of synthetic oil averaged 24,000 barrels per day during 2010, including first production from the Jackpine Mine in third quarter 2010 as a result of AOSP Expansion 1 Project activities. The project is expected to increase total daily maximum design capacity by 100,000 barrels, to more than 255,000 barrels per day in early 2011. Oil sands are mined from both the Muskeg River and Jackpine mines and bitumen is extracted from the oil sands and upgraded into synthetic oil. Expansion of the Scotford Upgrader, also part of the AOSP Expansion 1 Project, is expected to be completed in first-half 2011.

The company acquired a new exploration lease in the Beaufort Sea in 2010 and also holds other exploration licenses and leases in the Orphan Basin offshore Atlantic Canada, the Mackenzie Delta region of the Northwest Territories and the Beaufort Sea region of Canada’s Arctic, including a 34 percent nonoperated working interest in the offshore Amauligak discovery. In addition, through 2010 the company acquired approximately 200,000 acres in Alberta’s Duvernay formation to explore for shale gas and plans to commence an appraisal drilling program in the second-half 2011. At the end of 2010, proved reserves had not been recognized for any of these exploration areas.

 

Greenland: Evaluation of the2-D seismic survey acquired over License 2007/26 in Block 4 offshore West Greenland commenced in 2010 and is planned to continue into 2011. Chevron has a 29.2 percent nonoperated working interest in this exploration license.

begin in the second-half 2011. The facility is expected to produce up to 140,000 barrels of crude oil per day. First production is expected in 2013. Evaluation of the field development concept for Maromba continued into 2011. At the end of 2010, proved reserves had not been recognized for these projects.

 

In the Santos Basin, evaluation of investment options continued into 2011 for the 20 percent-owned and partner-operated Atlanta and Oliva fields. At the end of 2010, proved reserves had not been recognized for these deepwater 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. During 2010, the company conducted a seismic survey of the offshore,near-shoreand onshore development areas. Daily net production averaged 249 million cubic feet of natural gas in 2010.

 

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 2010 averaged 223 million cubic feet of natural gas per day. In 2010, a Loran/Manatee field-specific treaty was signed by the governments of Trinidad and Tobago and Venezuela related to the company’s 2005 successful exploratory well in the Manatee Area of Block 6(d). At the end of 2010, proved reserves had not been recognized for this field.

Venezuela: Chevron holds interests in two producing affiliates located in western Venezuela and one producing affiliate in the Orinoco Belt. Chevron has a 30 percent interest in the Petropiar affiliate that operates the Hamacaheavy-oilproduction and upgrading project located in Venezuela’s 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 company’s share of average net oil-equivalent production during 2010 from these operations, including synthetic oil from Hamaca, was 58,000 barrels per day, composed of 54,000 barrels of crude oil, synthetic oil and natural gas liquids and 25 million cubic feet of natural gas.

 

In February 2010, a Chevron-led consortium was selected to participate in a heavy-oil project in three blocks within the Carabobo Area of eastern Venezuela’s Orinoco Belt. A joint operating company, Petroindependencia, was formed in May 2010, and work toward commercialization of the Carabobo 3 Project was initiated. The consortium holds a combined 40 percent interest in the project, with Petróleos de Venezuela, S.A. (PDVSA), Venezuela’s national crude oil and natural gas company, holding the remaining interest. Chevron’s interest in the project is 34 percent.

 

The company operates in two exploratory blocks in the Plataforma Deltana area offshore eastern Venezuela, 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. PDVSA has the option to increase its ownership in each of the three company-operated blocks up to 35 percent upon declaration of commerciality. In Block 2, which includes the Loran Field, a Declaration of Commerciality was accepted by the Venezuelan government in March 2010. The Loran Field in Block 2 is projected to provide the initial natural gas supply for a planned Delta Caribe liquefied natural gas plant, Venezuela’s first LNG project. Chevron has a 10 percent nonoperated working interest in the LNG facility. At the end of 2010, proved reserves had not been recognized in these exploratory blocks.

 

In Africa, the company is engaged in exploration and production activities in Angola, Chad, Democratic Republic of the Congo, Liberia, Nigeria and Republic of the Congo. Net oil-equivalent production in Africa averaged 469,000 barrels per day during 2010.

 

In the Greater Vanza/Longui Area of Block 0, development concept selection studies continued in 2010 with the start of FEED planned for second quarter 2011. FEED activities continued on the south extension of the N’Dola field development

with a final investment decision expected in fourth quarter 2011. At year-end 2010, no proved reserves had been recognized for these projects.

 

In Block 0, the Area A gas management projects are designed to eliminate routine flaring of natural gas by injecting excess natural gas into various reservoirs. Three of the four projects are in service and have reduced flaring by approximately 65 million cubic feet per day, as of year-end 2010. The Malongo Flare and Relief Modification Project is scheduled forstart-up in fourth quarter 2011. In Area B, work continued during the year on the Nemba Enhanced Secondary Recovery and Flare Reduction Project. The first stage of the project was planned to be completed with the start of gas injection in second quarter 2011 on the existing South Nemba platform. The next stage, which includes completion of a new platform and additional compression facilities, is scheduled to begin gas injection in 2014.

 

Also in Block 0, a two-well exploration and appraisal program was completed in 2010. The first well, completed in February 2010, was successful and development opportunities are being evaluated. The second well, completed in June 2010, was not successful. Two additional exploratory wells are planned for 2011.

 

In the 31 percent-owned Block 14, net production in 2010 averaged 34,000 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 drilling continued at the Tombua and Landana fields during 2010. Drilling is planned to continue in 2011 with maximum total daily production of 75,000 barrels of crude oil anticipated in second quarter 2011.

 

In the Lucapa Field, development alternatives continued to be evaluated during 2010, and a successful exploration
well was completed in the fourth quarter. The project is expected to enter FEED in third quarter 2011. A new development area in the Malange Field was awarded in 2010, following a successful 2009 appraisal well. As of the end of 2010, development of the Negage Field remained suspended until cooperative arrangements between Angola and Democratic Republic of the Congo could be finalized. At the end of 2010, proved reserves had not been recognized for these projects.

 

In the 20 percent-owned Block 2 and the 16.3 percent-owned FST areas, combined production during 2010 averaged 2,000 barrels of net liquids per day.

 

In addition to the exploration and production activities in Angola, Chevron has a 36.4 percent ownership interest in the Angola LNG affiliate that began construction in 2008 of an onshore natural gas liquefaction plant in Soyo, Angola. The plant is designed to process more than 1 billion cubic feet of natural gas per day with expected average total daily sales of 670 million cubic feet of regasified LNG and up to 63,000 barrels of natural gas liquids. Construction continued during 2010 with plantstart-upscheduled for 2012. The estimated total cost of the LNG plant is $9.0 billion, with an estimated life in excess of 20 years. The company also holds a 38.1 percent interest in a pipeline project that is expected to transport up to 250 million cubic feet of natural gas per day from Block 0 and Block 14 to the Angola LNG plant. This project is expected to enter construction in the second-half 2011 and be completed by 2013. Proved reserves have been recognized for the producing operations associated with these projects.

 

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. The Lianzi development project continued FEED through 2010. A final investment decision is expected in fourth quarter 2011. No proved reserves have been recognized for the project.

 

Republic of the Congo: Chevron has a 31.5 percent nonoperated working interest in the Nkossa, Nsoko andMoho-Bilondopermit areas and a 29.3 percent nonoperated working interest in the Kitina permit area, all of which are offshore. Maximum total production of 93,000 barrels of crude oil per day was reached in fourth quarter 2010 at Moho-Bilondo. Chevron’s development and production rights for Moho-Bilondo expire in 2030. The development and production rights for Nsoko, Kitina and Nkossa expire in 2018, 2019 and 2027, respectively. Net production from the Republic of the Congo fields averaged 25,000 barrels of oil-equivalent per day in 2010.

 

During 2010, two successful exploration wells were drilled in the Moho-Bilondo permit area. Development alternatives are under evaluation.

 

Democratic Republic of the Congo: Chevron has a 17.7 percent nonoperated working interest in an offshore concession. Daily net production in 2010 averaged 2,000 barrels of oil-equivalent.

deepwater offshore blocks. In 2010, the company’s net oil-equivalent production in Nigeria averaged 253,000 barrels per day, composed of 239,000 barrels of liquids and 86 million cubic feet of natural gas.

 

During July 2010, an equity redetermination at the Agbami Field, located in deepwater Oil Mining Lease (OML) 127 and OML 128, reduced the company’s ownership by about 1 percent, to 67.3 percent. In May 2010, drilling started on a 10-well Phase 2 development program that is designed to offset field decline. The program is expected to continue through 2014 with the first wells expected to be completed and placed on production in second-half 2011. The leases that contain the Agbami Field expire in 2023 and 2024.

 

Also in the deepwater area, the Aparo Field in OML 132 and OML 140 and the third-party-owned Bonga SW Field in offshore OML 118 share a common geologic structure and are planned to be jointly developed under a unitization agreement. The agreement will be finalized in advance of a final investment decision. Subsurface and surface facility studies are expected to be completed in second quarter 2011. A decision on project scope is expected by third quarter 2011, prior to entering FEED. At the end of 2010, no proved reserves were recognized for this project.

 

Chevron operates and holds a 95 percent interest in the deepwater Nsiko discovery in OML 140. Development activities continued in 2010, with FEED expected to start after commercial terms are resolved and further exploration drilling is completed. At the end of 2010, the company had not recognized proved reserves for this project.

 

The company 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 (FPSO) vessel. During 2010, development drilling and construction of the FPSO vessel continued. The FPSO vessel is expected to depart the fabrication facility in second quarter 2011. Productionstart-up is scheduled for 2012, with maximum total production of 180,000 barrels of crude oil per day expected within one year ofstart-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.

 

Additional exploration drilling is planned for third quarter 2011 in Oil Prospecting License (OPL) 214 and OPL 223. The company has 20 percent and 27 percent nonoperated working interests in the licenses, respectively. At the end of 2010, proved reserves had not been recognized for these exploration activities.

 

In the Niger Delta, construction on the Phase 3A expansion of the Escravos Gas Plant (EGP) was completed in 2009, and first gas was delivered to the new facilities in June 2010. As a result of the expansion, the plant’s total daily processing capacity increased from 285 million to 680 million cubic feet of natural gas, and daily LPG and condensate export capacity increased from 15,000 to 58,000 barrels. By year-end 2010, plant input had ramped up to 230 million cubic feet of natural gas per day, resulting in daily natural gas sales into the domestic market of 180 million cubic feet and daily export sales of 8,000 barrels of LPG and condensate. The anticipated life of EGP Phase 3A is 25 years. Phase 3B of the EGP project is designed to gather 120 million cubic feet of natural gas per day from eight offshore fields and to compress and transport the natural gas to onshore facilities. The engineering, procurement, construction and installation contract for the gas gathering and compression platform is expected to be signed in second quarter 2011. The Phase 3B project is expected to be completed in 2013. Proved reserves associated with this project have been recognized.

The 40 percent-owned and operated Gas Supply Expansion project includes facilities to develop the Sonam natural gas field in the Escravos area and to add a third gas processing train at EGP. The project is designed to deliver 215 million cubic feet of natural gas per day to the domestic market and produce 43,000 barrels of liquids per day. A final investment decision is expected in third quarter 2011. At the end of 2010, proved reserves associated with the project had not been recognized.

 

The company has a 40 percent-owned and operated interest in the Onshore Asset Gas Management project that 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. Twoon-siteconstruction contracts were awarded in third quarter 2010 andstart-up is scheduled for 2012.

 

Chevron has a 75 percent-owned and operated interest in agas-to-liquidsfacility at Escravos that is being developed with the Nigerian National Petroleum Corporation. The33,000 barrel-per-dayfacility is designed to process 325 million cubic feet per day of natural gas supplied from the Phase 3A expansion of EGP. At the end of 2010, work on the project was approximately 70 percent complete andstart-up is planned for 2013. The estimated cost of the plant is $8.4 billion.

 

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. As of early 2011, timing of the final investment decision remains uncertain. At the end of 2010, proved reserves associated with this project had not been recognized.

 

Chevron is the largest shareholder, with a 37 percent interest, in the West African Gas Pipeline Company Limited affiliate, which constructed, owns and operates the421-mileWest African Gas Pipeline. The pipeline supplies Nigerian natural gas to customers in Benin, Ghana and Togo for industrial applications and power generation. Compression facilities designed to increase capacity to 170 million cubic feet per day were commissioned in February 2011.

 

Liberia: In 2010, Chevron acquired a 70 percent interest and operatorship in three deepwater blocks off the coast of Liberia. Three-D seismic data was purchased in September, and an exploration well is planned for fourth quarter 2011.

 

 

In Asia, the company is engaged in upstream activities in Azerbaijan, Bangladesh, Cambodia, China, Indonesia, Kazakhstan, Myanmar, the Partitioned Zone located between Saudi Arabia and Kuwait, the Philippines, Russia, Thailand, Turkey, and Vietnam. During 2010, net oil-equivalent production averaged 1,069,000 barrels per day.

per day and transports the majority of ACG production. Another production export route for crude oil is the Western Route Export Pipeline, wholly owned by AIOC, with capacity to transport 100,000 barrels per day from Baku, Azerbaijan, to the marine terminal at Supsa, Georgia.

Kazakhstan: Chevron participates in two major upstream developments in western Kazakhstan. The company holds a 50 percent interest in the Tengizchevroil (TCO) affiliate, which is operating and developing the Tengiz and Korolev crude oil fields under a concession that expires in 2033. Chevron’s net oil-equivalent production in 2010 from these fields averaged 308,000 barrels per day, composed of 252,000 barrels of crude oil and natural gas liquids and 338 million cubic feet of natural gas. During 2010, the majority of TCO’s 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 by tanker to Baku for transport by the BTC pipeline to Ceyhan or by rail to Black Sea ports.

 

Also during 2010, TCO continued to evaluate alternatives for another expansion project to increase total daily crude oil production between 250,000 and 300,000 barrels. The expansion project will rely on technology developed for the Sour Gas Injection/Second Generation Plant project completed in 2008. Approval of FEED is anticipated in the second-half 2011. As of year-end 2010, no proved reserves have been recognized for this expansion project.

 

Chevron holds a 20 percent nonoperated working interest in the Karachaganak project, which is being developed in phases. During 2010, Karachaganak net oil-equivalent production averaged 64,000 barrels per day, composed of 39,000 barrels of liquids and 149 million cubic feet of natural gas. In 2010, access to the CPC and Atyrau-Samara (Russia) pipelines enabled approximately 175,000 barrels per day (31,000 net barrels) of Karachaganak liquids to be sold at world-market prices. The remaining liquids were sold into Russian markets. During 2010, work continued on a fourth train that is designed to increase total liquids stabilization capacity by 56,000 barrels per day. The fourth train is expected to start up in second quarter 2011.

 

During 2010, Chevron and its partners continued to evaluate alternatives for a Phase III development of Karachaganak. Timing for the Phase III project remains uncertain and depends on finalizing a project design. Proved reserves have not been recognized for a Phase III project. Karachaganak operations are conducted under a PSC that expires in 2038.

 

Kazakhstan/Russia: Chevron has a 15 percent interest in the CPC affiliate. During 2010, CPC transported an average of approximately 743,000 barrels of crude oil per day, including 607,000 barrels per day from Kazakhstan and 136,000 barrels per day from Russia. In December 2010, partners made a final investment decision to increase the pipeline capacity by 670,000 barrels per day. The total estimated cost of the project is $5.4 billion. The project is expected to be implemented in three phases, with capacity increasing progressively until reaching full capacity in 2016.

 

Russia: In June 2010, Chevron signed a Heads of Agreement with Rosneft covering the exploration, development and production of hydrocarbons from the Shatsky Ridge Block in the Black Sea. Technical and commercial evaluation of the opportunity is ongoing in 2011. No proved reserves have been recognized for these activities.

 

Turkey: In September 2010, Chevron signed a Joint Operating Agreement for a 50 percent interest in a 5.6 million acre exploration block located in the Black Sea. The initial exploration well was completed in November 2010 and was unsuccessful. Future plans are under evaluation.

 

Chevron relinquished its 25 percent nonoperated working interest in the Silopi licenses in southeast Turkey, following the evaluation of an unsuccessful exploration well, which was completed in the Lale prospect during first quarter 2010.

 

Bangladesh: Chevron holds interests in three operated PSCs covering Blocks 7, 12, 13 and 14. The company has a 43 percent interest in Block 7 and a 98 percent interest in Blocks 12, 13 and 14. Net oil-equivalent production from these operations in 2010 averaged 69,000 barrels per day, composed of 404 million cubic feet of natural gas and 2,000 barrels of liquids. In 2010, preliminary construction and development activities were completed at the Muchai compression project, which 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. Also in 2010, the company completed seismic data evaluation and prepared to drill an exploration well in Block 7 that is expected to be completed by mid-2011.

 

Cambodia: Chevron owns a 30 percent interest and operates the1.2 million-acre BlockA, located offshore in the Gulf of Thailand. The company completed three successful exploration wells during 2010. A30-yearproduction permit under the PSC is expected to be approved by the government in the first-half 2011. A final investment decision for construction of a wellhead platform and a floating storage and offloading vessel is expected in 2011. At year-end 2010, proved reserves had not been recognized for the project.

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 Thailand’s PTT Public Company Limited. The company’s average net natural gas production in 2010 was 81 million cubic feet per day. In July 2010, a compression project entered service to support additional natural gas demand.

Basin. Concessions for the producing areas within this basin expire between 2036 and 2040.

 

During 2010, construction at the 69.9 percent-owned and operated Platong Gas II project continued. The project is designed to add 440 million cubic feet per day of production capacity andstart-up is expected in fourth quarter 2011. Proved reserves have been recognized for this project.

 

During 2010, the company drilled seven exploration wells in the Pattani Basin. Four of the wells were successful and were under evaluation to validate the development strategy. Three unsuccessful explorations wells were drilled in Block G4/50. In fourth quarter, the company withdrew from this block. At the end of 2010, proved reserves had not been recognized for these activities. For 2011, eleven operated exploratory wells are planned. The company also holds exploration interests in a number of blocks that are inactive, pending resolution of border issues between Thailand and Cambodia.

 

Vietnam: Chevron is the operator of two PSCs in the Malay Basin off the southwest coast of Vietnam. The company has a 42.4 percent interest in a PSC that includes Blocks B and 48/95, and a 43.4 percent interest in a PSC for Block 52/97. The company also has a 20 percent ownership interest in an operated PSC in Block 122 offshore eastern Vietnam.

 

In the blocks off the southwest coast, the Block B Gas Development is designed to produce natural gas from the Malay Basin for delivery 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 entered FEED in 2010, and a final investment decision is expected in fourth quarter 2011. Maximum total production is planned to be about 500 million cubic feet of natural gas per day. At the end of 2010, proved reserves had not been recognized for this project.

 

In conjunction with the Block B Gas Development, a partner-operated pipeline will be required to support the offshore development. Chevron has a 28.7 percent interest in the pipeline, which is planned to transport natural gas to customers in southern Vietnam. The project entered FEED in 2009, and the engineering and design work is being performed by the pipeline operator.

 

During the year, seismic processing and prospect mapping were completed for Block 122. Proved reserves had not been recognized as of the end of 2010. Future activity in Block 122 may be affected by an ongoing territorial dispute between Vietnam and China.

three separate PSCs for the exploration period. The three deepwater blocks cover approximately 5.2 million acres. One exploration well is planned for 2011 following the completion of an environmental impact study and a3-D seismic acquisition program.

 

Also in the Pearl River Mouth Basin, the company has nonoperated working interests of 32.7 percent in Blocks 16/08 and 16/19. Following storm damage in 2009, production was partially restored from Block 16/08 and Block 16/19 in March 2010 and is expected to be fully restored in 2011. Also in Block 16/19, first production from the joint development of the HZ25-3 and HZ25-1 crude oil fields was achieved in March 2010.

 

In the Bohai Bay, the company holds nonoperated interests of 24.5 percent in the QHD-32-6 Field and 16.2 percent in Block 11/19, both of which are in production. In 2010, production was partially restored from Block 11/19 after a shut-in caused by a storm in 2009. Production is expected to be fully restored in 2013.

Basin in fourth quarter 2010 following an unsuccessful obligation well in 2009. Chevron also relinquished its interest in the 100 percent-owned and operated East Ambalat PSC in December 2010. The relinquishments of NE Madura III and East Ambalat are both pending approval by the government of Indonesia.

 

The company’s net oil-equivalent production in 2010 from all of its interests in Indonesia averaged 226,000 barrels
per day. The daily oil-equivalent rate comprised 187,000 barrels of liquids and 236 million cubic feet of natural gas.
The largest producing field is Duri, located in the Rokan PSC. Duri has been under steamflood operation since 1985
and is one of the world’s largest steamflood developments. The North Duri Development is divided into multiple expansion areas.

The expansion in Area 12 was completed in 2010 with the additional drilling of 72 production, 24 steam injection, and 10 observation wells. During the year,ramp-up of steam injection continued with the project reaching a maximum total daily production of 45,000 barrels in September 2010. A final investment decision regarding North Duri Area 13 was reached May 2010, and is awaiting final development plan and bid award approvals from the government of Indonesia. The Rokan PSC expires in 2021.

 

In 2010, Chevron advanced its development plans for the Gendalo-Gehem deepwater natural gas project located in the Kutei Basin, awarding major FEED contracts for the floating production units, subsea and pipeline components, and onshore receiving facility. Maximum daily total production from the project is expected to be 1.1 billion cubic feet of natural gas and 31,000 barrels of condensate. Completion of FEED is dependent upon government approvals and achieving project milestones. The Bangka deepwater natural gas project progressed during the year, and entered FEED in fourth quarter 2010. During 2010, the company reached an agreement to farm-out a portion of its working interest in the PSCs of the two projects. Government approval of the farm-out is expected in the second-half 2011. In addition, in 2011 the company expects to farm-in an Indonesian company to the PSCs for the two projects. Following government approval of the agreements, the company’s production interest in the Gendalo-Gehem and Bangka projects will be 55.1 percent and 54 percent, respectively. Proved reserves have not been recognized for these projects.

 

Also in the Kutei Basin, the company reached a final investment decision in August 2010 for an oil development project in the West Seno Field and recognized proved reserves related to the project.

 

A drilling campaign continued through 2010 in South Natuna Sea Block B to provide additional supply for long-term natural gas sales contracts, with additional development drilling planned for 2011. The North Belut development project achieved maximum total daily production of 240 million cubic feet of natural gas and 33,000 barrels of liquids in February 2010. Development of the South Belut project continued during the year. The Bawal project reached final investment decision in October 2010 and is expected to begin production in 2012.

 

Exploration activities continued in the Central Sumatra Basin during 2010. Two wells drilled in the Rokan Block were successful and placed on production. Additional appraisal drilling near the Duri Field identified further expansion opportunities that will be further assessed with3-D seismic in 2011. Chevron’s operated working interests in two exploration blocks in western Papua, West Papua I and West Papua III, were reduced to 51 percent in second quarter 2010. Geological studies of the two blocks continued in 2010, and2-D seismic acquisition is expected to start in the first-half 2011.

 

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-owned300-megawattcogeneration facility in support of the company’s operation in North Duri, Sumatra. In December 2010, the company was awarded a license and operatorship to explore and develop a geothermal prospect in the Suoh-Sekincau prospect area at Lampung in southern Sumatra.

 

carbonate reservoir and, if successful, could significantly increase heavy oil recovery. No proved reserves have been recognized for this project.

 

Also in 2010, assessment of alternatives continued on the Central Gas Utilization Project to increase natural gas utilization and eliminate routine flaring. A final investment decision is expected in 2012. No proved reserves have been recognized for this project.

Philippines: The company holds a 45 percent nonoperated working interest in the Malampaya natural gas field located 50 miles offshore Palawan Island. Net oil-equivalent production in 2010 averaged 25,000 barrels per day, composed of 124 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 new25-yearcontract with the government by the end of 2011 to operate the steam fields, which supply geothermal resources to 637 megawatt power generation facilities.

 

In November 2010, Chevron signed a farm-in agreement and a Joint Operating Agreement with two Philippine corporations to explore, develop and operate the Kalinga geothermal prospect in northern Luzon, Philippines. The company has a 90 percent-owned and operated interest in the project.

 

In Australia, the company’s exploration and production efforts are concentrated off the northwest coast. During 2010, the average net oil-equivalent production from Australia was 111,000 barrels per day.

production in 2013. Proved reserves have been recognized for the project.

 

Work also progressed on the NWS Oil Redevelopment Project, which is designed to replace the existing FPSO vessel and a portion of existing subsea infrastructure that services production from the Cossack, Hermes, Lambert and Wanaea offshore fields. Work commenced in January 2011 on the subsea infrastructure refurbishment, and construction of the new FPSO vessel is expected to be completed in second quarter 2011. The project is expected to start up in third quarter 2011 and extend production past 2020.

 

The NWS Venture continues to progress additional gas supply opportunities through development of several small fields on the western flank of the Goodwyn reservoirs. The project is expected to enter FEED in the first-half 2011. 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 2010. Chevron’s 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 holds a 47.3 percent ownership interest across most of the area and is the operator of the Gorgon Project, which combines the development of the offshore Gorgon and nearby Io/Jansz natural gas fields as one large-scale project. Total estimated project costs for the first phase of development are $37 billion. The project’s scope also includes a three-train, 15 million-metric-ton-per-year LNG facility, a carbon sequestration project and a domestic natural gas plant.

Chevron has signed five binding LNG Sales and Purchase Agreements (SPAs) with Asian customers for delivery of about 4.7 million metric tons of LNG per year. Negotiations continue to finalize the two remaining nonbinding Heads of Agreement (HOAs) to binding SPAs, which would bring LNG delivery commitments to a combined total of about 90 percent of Chevron’s share of LNG from the project. Construction on Barrow Island and other activities for the project progressed during 2010 with the awarding of approximately $25 billion of contracts for materials and services, clearing of the plant site, completion of the first stage of the construction village, commencement of module fabrication, and progression of studies on the possible expansion of the project. Proved reserves have been recognized for the Greater Gorgon Area fields included in the project, and first production of natural gas from the fields is expected in 2014. The project’s estimated economic life exceeds 40 years from the time ofstart-up.

 

FEED activities for the company’s majority-owned and operated Wheatstone Project continued in 2010. Chevron holds an 80 percent interest in the foundation natural gas processing facilities, which include a two-train 8.9 million-metric-ton-per-year LNG facility and a separate domestic gas plant located at Ashburton North, along the northwest coast of Australia. The company plans to supply natural gas to the facilities from two Chevron-operated licenses comprising the majority of the Wheatstone Field and the nearby Iago Field.

 

Through the end of 2010, Chevron has signed nonbinding HOAs with three Asian customers for the delivery of about 80 percent of Chevron’s net LNG offtake from the Wheatstone Project. Under these HOAs, the customers also agreed to acquire a combined 21.8 percent nonoperated working interest in the Wheatstone field licenses and a 17.5 percent interest in the foundation natural gas processing facilities at the time of the final investment decision. Negotiations continue to move the three nonbinding HOAs to binding SPAs with these customers. Agreements were also signed in 2009 and amended in 2010 with two companies to participate in the Wheatstone Project as combined 20 percent LNG facility owners and suppliers of natural gas for the project’s first two LNG trains. During 2010, a Native Title Heads of Agreement was reached with the local indigenous people for the land required at Ashburton North and submissions were made for various additional environmental approvals. The final investment decision for the project is expected insecond-half2011. At the end of 2010, the company had not recognized proved reserves for this project.

 

In the Browse Basin, the Browse LNG development participants commenced design evaluation for the Brecknock, Calliance and Torosa fields in early 2010. At the end of 2010, proved reserves had not been recognized.

 

During 2010, Chevron announced natural gas discoveries at the 50 percent-owned Brederode prospect in BlockWA-364-P,the 50 percent-owned Yellowglen prospect in Block WA-268-P, the 50 percent-owned Sappho prospect in Block WA-392-P, and the 67 percent-owned Clio and Acme prospects in Block WA-205-P. In February 2011, the company announced a natural gas discovery in the 50 percent-owned Orthrus prospect in Block WA-24-R. All prospects are Chevron operated. The Clio and Acme prospects are expected to help support potential expansion opportunities at the Wheatstone LNG facilities while the Yellowglen, Sappho and Orthrus prospects are expected to help underpin further expansion opportunities on the Gorgon Project. Proved reserves had not been recognized for any of these exploration discoveries.

 

In Europe, the company is engaged in exploration and production activities in Denmark, the Netherlands, Norway, Poland, Romania and the United Kingdom. Net oil-equivalent production in Europe averaged 159,000 barrels per day during 2010.

 

Denmark: Chevron has a 15 percent working interest in the partner-operated Danish Underground Consortium (DUC), which produces crude oil and natural gas from 13 of 15 fields in the Danish North Sea. Net oil-equivalent production in 2010 from DUC averaged 51,000 barrels per day, composed of 32,000 barrels of crude oil and 116 million cubic feet of natural gas. During 2010, four development wells were drilled and completed in the Halfdan, Tyra and Valdemar fields. The installation of new facilities for the Halfdan Phase IV project was completed in 2010, withhook-up and tie-in planned for second quarter 2011.

 

Netherlands: Chevron operates and holds interests ranging from 34.1 percent to 80 percent in 10 blocks in the Dutch sector of the North Sea. In 2010, the company’s net oil-equivalent production from the producing blocks was 8,000 barrels per day, composed of 2,000 barrels of crude oil and 35 million cubic feet of natural gas. Five blocks comprise the A/B Gas Project, where development continued in 2010 and into 2011. In September 2010, the company acquired a 60 percent interest in the P/1 and P/2 blocks, which contain several natural gas discoveries.

covers 1.5 million acres. A2-D seismic program is planned to begin in fourth quarter 2011 on the EV-2 Barlad concession.

 

United Kingdom: The company’s average net oil-equivalent production in 2010 from 10 offshore fields was 97,000 barrels per day, composed of 64,000 barrels of crude oil and natural gas liquids and 194 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.

 

The 70 percent-owned and operated Alder discovery entered FEED in 2010, following selection of the development concept. The final investment decision is planned for late 2011. Evaluation of development alternatives continued during 2010 for the Clair Ridge Project, located west of the Shetland Islands, in which the company has a 19.4 percent nonoperated working interest. Evaluation resulted in the selection of a preferred alternative consisting of a bridge-linked, twin-jacket structure. The final investment decision is expected mid-2011. In the 40 percent-owned and operated Rosebank area northwest of the Shetland Islands, seismic, geophysical, geotechnical and environmental surveys were conducted during 2010, and feasibility engineering activities are scheduled to continue through 2011. At the end of 2010, proved reserves had not been recognized for any of these development projects.

 

Also west of the Shetland Islands, a three-well exploration and appraisal drilling program began in September 2010 and is expected to be completed in fourth quarter 2011. This program comprises exploration wells on the Lagavulin prospect in the 60 percent-owned and operated license block P1196 and on the Aberlour prospect in the 40 percent-owned and operated license block P1194, followed by appraisal drilling and well testing of the Cambo discovery in the 32.5 percent nonoperated license blocks P1028 and P1189. As of the end of 2010, proved reserves had not been recognized for any of these prospects.

 

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 2010, U.S. and international sales of natural gas were 5.9 billion and 4.5 billion cubic feet per day, respectively, which includes the company’s share of equity affiliates’ sales. Outside the United States, substantially all of the natural gas sales from the company’s producing interests are from operations in Australia, Bangladesh, Europe, Kazakhstan, Indonesia,

Latin America, the Philippines and Thailand.

 

U.S. and international sales of natural gas liquids were 161 thousand and 105 thousand barrels per day, respectively, in 2010. Substantially all of the international sales of natural gas liquids are from company operations in Africa, Australia, Indonesia and the United Kingdom.

 

Refer to “Selected Operating Data,” on pageFS-11 in Management’s Discussion and Analysis of Financial Condition and Results of Operations, for further information on the company’s sales volumes of natural gas and natural gas liquids. Refer also to “Delivery Commitments” on page 8 for information related to the company’s delivery commitments for the sale of crude oil and natural gas.

 

 

At the end of 2010, the company had a refining network capable of processing more than 2 million barrels of crude oil per day. Operable capacity at December 31, 2010, and daily refinery inputs for 2008 through 2010 for the company and affiliate refineries were as follows:

 

 

Average crude oil distillation capacity utilization during 2010 was 92 percent, compared with 91 percent in 2009. At the U.S. fuel refineries, crude oil distillation capacity utilization averaged 95 percent in 2010, compared with 96 percent in 2009, and cracking and coking capacity utilization averaged 90 percent and 85 percent in 2010 and 2009, respectively. Cracking and coking units are the primary facilities used in fuel refineries to convert feedstocks into gasoline and other light products. Chevron processes both imported and domestic crude oil in its U.S. refining operations. Imported crude oil accounted for about 84 percent and 85 percent of Chevron’s U.S. refinery inputs in 2010 and 2009, respectively.

 

At the Pascagoula Refinery, the company commissioned a continuous catalytic reformer that is expected to improve equipment reliability and utilization and to allow the refinery to optimize production of high-value products. Also in Pascagoula, a final investment decision was reached in first quarter 2011 to construct a facility to produce approximately 25,000 barrels per day of premium base oil for use in manufacturing high-performance finished lubricants, such as motor oils for consumer and commercial applications. Project completion is expected by year-end 2013.

At the refinery in El Segundo, construction began in late 2010 on a new processing unit designed to further improve the facility’s overall reliability, enhance high-value product yield and provide additional flexibility to process a broad range of crude slates. Project completion is expected in 2012. At the Richmond Refinery, the company continued to evaluate its options with respect to permitting of the Renewal Project. The project is designed to improve the refinery’s ability to process higher sulfur crudes, without changing the refinery’s capacity to process crude blends in the intermediate-light gravity range. Improved ability to process higher sulfur crudes is expected to provide increased flexibility to process lower API-gravity crudes within the refinery’s existing capacity range. Refer also to a discussion of contingencies related to this project in Note 24 to the Consolidated Financial Statements onpage FS-59.

 

Outside the United States, GS Caltex, the company’s 50 percent-owned affiliate, commissioned and reached full capacity on a new 60,000-barrel-per-day heavy-oil hydrocracker at the Yeosu Refinery in South Korea during 2010. Also at the Yeosu Refinery, GS Caltex announced plans to construct a 53,000-barrel-per-day gas oil fluid catalytic cracking unit. The unit is scheduled forstart-up in 2013. Both units are designed to increase high-value product yield and lower feedstock costs. Construction began in 2010 on modifications to the 64 percent-owned Star Petroleum Refinery in Thailand to meet regional specifications for cleaner motor gasoline and diesel fuels. Project completion is scheduled for 2012. Also in 2010, the company solicited bids for the sale of certain operations in the United Kingdom and Ireland, including the Pembroke Refinery.

 

The company markets petroleum products under the principal brands of “Chevron,” “Texaco” and “Caltex” throughout many parts of the world. The table below identifies the company’s and affiliates’ refined products sales volumes, excluding intercompany sales, for the three years ended December 31, 2010.

 

 

In the United States, the company markets under the Chevron and Texaco brands. At year-end 2010, the company supplied directly or through retailers and marketers approximately 8,250 Chevron- and Texaco-branded motor vehicle service stations, primarily in the southern and western states. Approximately 500 of these outlets are company-owned or -leased stations. In 2010, the company discontinued sales of Chevron- and Texaco-branded motor fuels in the District of Columbia, Delaware, Indiana, Kentucky, North Carolina, New Jersey, Maryland, Ohio, Pennsylvania, South Carolina, Virginia, West Virginia and parts of Tennessee, 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 represented approximately 8 percent of the company’s total U.S. retail fuels sales volumes in 2009. In addition, the company has completed six of 13 planned U.S. terminal divestitures.

 

Outside the United States, Chevron supplied directly or through retailers and marketers approximately 11,300 branded service stations, including affiliates. In British Columbia, Canada, the company markets under the Chevron brand. The

company markets in the United Kingdom, Ireland, Latin America and the Caribbean using the Texaco brand. In the Asia-Pacific region, southern Africa, Egypt and Pakistan, the company uses the Caltex brand. The company also operates through affiliates under various brand names. In South Korea, the company operates through its 50 percent-owned affiliate, GS Caltex, and in Australia through its 50 percent-owned affiliate, Caltex Australia Limited.

 

The company progressed its ongoing effort to concentrate downstream resources and capital on strategic assets. In December 2010 and February 2011, the company completed the sale of fuels-marketing businesses in Malawi, Mauritius, Réunion, Tanzania and Zambia. The company expects to complete the sale of its fuels-marketing businesses in Mozambique and Zimbabwe later in 2011, following receipt of required local regulatory and government approvals. In November 2010, the company signed an agreement for the sale of its fuels-marketing and aviation fuels businesses in Antigua, Barbados, Belize, Costa Rica, Dominica, French Guiana, Grenada, Guadeloupe, Guyana, Martinique, Nicaragua, St. Kitts, St. Lucia, St. Vincent, and Trinidad and Tobago and expects to complete all transactions by third quarter 2011, following receipt of required local regulatory and government approvals. In February 2011, the company announced an agreement to sell its fuels, finished lubricants and aviation fuels businesses in Spain. In 2010, the company also solicited bids for its fuels-marketing and aviation fuels businesses in the United Kingdom and Ireland. In addition, the company converted more than 150 company-operated service stations into retailer-owned sites in various countries outside the United States.

 

Chevron markets commercial aviation fuel at approximately 200 airports, worldwide. The company also markets an extensive line of lubricant and coolant products under brand names including Havoline, Delo, Ursa, Meropa and Taro.

 

Chevron owns a 50 percent interest in its Chevron Phillips Chemical Company LLC (CPChem) affiliate. At the end of 2010, CPChem owned or had joint-venture interests in 36 manufacturing facilities and four research and technical centers around the world.

 

During 2010, CPChem commenced operations at its 49 percent-owned Q-Chem II project in both Mesaieed and Ras Laffan, Qatar. The project includes a 350,000-metric-ton-per-year high-density polyethylene plant and a345,000-metric-ton-per-yearnormal alpha olefins plant in Mesaieed, each utilizing CPChem’s proprietary technology. Also included in the project is a separate joint venture for a 1.3 million-metric-ton-per-year ethylene cracker in Ras Laffan, in whichQ-Chem IIowns 54 percent of the capacity rights, which will provide ethylene feedstock to the high-density polyethylene and normal alpha olefins plants.

 

CPChem’s 35 percent-owned Saudi Polymers Company continued construction on a petrochemical project in Al Jubail, Saudi Arabia. The joint-venture project includes olefins, polyethylene, polypropylene, 1-hexene and polystyrene units. Projectstart-up is expected in late 2011.

 

In the United States, CPChem announced in fourth quarter 2010 the development of a 200,000-ton-per-year 1-hexene plant at the company’s Cedar Bayou complex in Baytown, Texas, withstart-upexpected in 2014. The plant is expected to be the largest 1-hexene unit in the world and will utilize CPChem’s proprietary 1-hexene technology.

 

Chevron’s 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 primarily in engine applications, such as passenger car, heavy-duty diesel, marine, locomotive and motorcycle engines, and additives for fuels that are blended to improve engine performance and extend engine life. During 2010, the company achieved full capacity at the detergent expansion facility in Singapore. This additional capacity enhances the company’s ability to produce detergent components for applications in marine and automotive engines.

 

Pipelines: Chevron owns and operates an extensive network of crude oil, refined product, chemical, natural gas liquid and natural gas pipelines and other infrastructure assets in the United States. The company also has direct and indirect interests in other U.S. and international pipelines. The company’s ownership interests in pipelines are summarized in the following table.

 

 

During 2010, the company completed a project to expand capacity by approximately 2 billion cubic feet at the Keystone natural gas storage facility near Midland, Texas, bringing total capacity to nearly 7 billion cubic feet.

 

Work continued in 2010 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 company’s equity production. The pipeline is expected to return to service in 2012. The company is leading the construction of a 136 mile,24-inchpipeline from the Jack/St. Malo facility to Green Canyon 19 in the U.S. Gulf of Mexico, where there is an interconnect to pipelines delivering crude oil into Louisiana.

 

In 2010, the company sold its 23.4 percent ownership interest in the Colonial Pipeline Company, which transports products from supply centers on the U.S. Gulf Coast to customers located along the Eastern seaboard.

 

Refer to pages 16, 17 and 18 in the Upstream section for information on the Chad/Cameroon pipeline, the West Africa Gas Pipeline, the Baku-Tbilisi-Ceyhan Pipeline, the Western Route Export Pipeline and the Caspian Pipeline Consortium.

 

Tankers: All tankers in Chevron’s controlled seagoing fleet were utilized during 2010. At any given time during 2010, the company had 41 deep-sea vessels chartered on a voyage basis, or for a period of less than one year. Additionally, the table on the following page summarizes the capacity of the company’s controlled fleet.