UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

 

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

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2011

OR

 

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

SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from            to           

 

Commission File Number 001-00368

Chevron Corporation

(Exact name of registrant as specified in its charter)

 

 

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

 

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

 

 

 

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

 

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

 

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

 

Indicate by check mark 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 registrant’s 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.

 

 

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 registrant’s most recently completed second fiscal quarter — $205,986,778,815 (As of June 30, 2011)

 

Number of Shares of Common Stock outstanding as of February 13, 2012 — 1,976,966,530

 

DOCUMENTS INCORPORATED BY REFERENCE

(To The Extent Indicated Herein)

 

Notice of the 2012 Annual Meeting and 2012 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, in connection with the company’s 2012 Annual Meeting of Stockholders (in Part III)

 

 

 

TABLE OF CONTENTS

 

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 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 or start-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 29 through 31 in this report. In addition, such results could be affected by general domestic and international economic and political conditions. Other unpredictable or unknown factors not discussed in this report could also have material adverse effects on forward-looking statements.

 

 

 

Summary Description of Chevron

 

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 a gas-to-liquids project. Downstream operations consist primarily of refining crude oil into petroleum products; marketing of crude oil and refined products; transporting 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 on pages E-4 and E-5. As of December 31, 2011, Chevron had approximately 61,000 employees (including about 3,800 service station employees). Approximately 30,000 employees (including about 3,500 service station employees), or 49 percent, were employed in U.S. operations.

 

Overview of Petroleum Industry

 

Petroleum industry operations and profitability are influenced by many factors. Prices for crude oil, natural gas, petroleum products and petrochemicals are generally determined by supply and demand. 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. Laws and governmental policies, particularly in the areas of taxation, energy and the environment affect where and how companies conduct their operations and formulate their products and, in some cases, limit their profits directly.

 

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.

 

Operating Environment

 

Refer to pages FS-2 through FS-8 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of the company’s current business environment and outlook.

 

 

^*  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.

Chevron’s Strategic Direction

 

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 natural 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, 2011, and assets as of the end of 2011 and 2010 — for the United States and the company’s international geographic areas — are in Note 11 to the Consolidated Financial Statements beginning on page FS-37. 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-39 through FS-41.

 

Total expenditures for 2011 were $29.1 billion, including $1.7 billion for the company’s share of equity-affiliate expenditures. In 2010 and 2009, expenditures were $21.8 billion and $22.2 billion, respectively, including the company’s share of affiliates’ expenditures of $1.4 billion in 2010 and $1.6 billion in 2009.

 

Of the $29.1 billion in expenditures for 2011, 89 percent, or $25.9 billion, was related to upstream activities. Approximately 87 and 80 percent was expended for upstream operations in 2010 and 2009, respectively. International upstream accounted for about 68 percent of the worldwide upstream investment in 2011, about 82 percent in 2010 and about 80 percent in 2009. These amounts exclude the acquisition of Atlas Energy, Inc. in 2011. Refer to a discussion of the acquisition of Atlas Energy, Inc., in Note 2 to the Consolidated Financial Statements on page FS-30.

 

In 2012, the company estimates capital and exploratory expenditures will be $32.7 billion, including $3 billion of spending by affiliates. Approximately 87 percent of the total, or $28.5 billion, is budgeted for exploration and production activities, with $22.3 billion, or about 78 percent, of this amount for projects outside the United States.

 

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

 

The table on the following page summarizes the net production of liquids and natural gas for 2011 and 2010 by the company and its affiliates. Worldwide oil-equivalent production was 2.673 million barrels per day, down about three percent from 2010. The decrease was mainly associated with normal field declines, maintenance-related downtime and the impact of higher prices on entitlement volumes. The start-up and ramp-up of several major capital projects — the Perdido project in the U.S. Gulf of Mexico, the expansion at the Athabasca Oil Sands Project in Canada, the Frade Field in Brazil, and the Platong II natural gas project in Thailand — as well as acquisitions in the Marcellus Shale, partially offset the decrease in net production from 2010. Refer to the “Results of Operations” section beginning on page FS-6 for a detailed discussion of the factors explaining the 2009 — 2011 changes in production for crude oil and natural gas liquids, and natural gas.

 

The company estimates its average worldwide oil-equivalent production in 2012 will be approximately 2.680 million barrels per day based on the average Brent price of $111 per barrel in 2011. This estimate is subject to many factors and uncertainties, including quotas that may be imposed by OPEC, price effects on entitlement volumes, 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-expected declines 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 8, for a discussion of the company’s major crude oil and natural gas development projects.

 

 

Refer to Table IV on page FS-67 for 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 2011, 2010 and 2009.

 

The following table summarizes gross and net productive wells at year-end 2011 for the company and its affiliates:

 

Productive Oil and Gas Wells at December 31, 2011

 

		Productive								Productive
		Oil Wells								Gas Wells
		Gross				Net				Gross				Net
United States			49,511				32,368				14,061				7,671
Other Americas			709				533				40				17
Africa			2,548				850				17				7
Asia			12,612				10,861				3,437				2,125
Australia			807				453				64				11
Europe			332				105				222				48
Total Consolidated Companies			66,519				45,170				17,841				9,879
Equity in Affiliates			1,231				434				7				2
Total Including Affiliates			67,750				45,604				17,848				9,881
Multiple completion wells included above:			887				573				378				280

 

Refer to Table V beginning on page FS-67 for a tabulation of the company’s proved net crude oil and natural gas reserves by geographic area, at the beginning of 2009 and each year-end from 2009 through 2011. Reserves governance, technologies used in establishing proved reserves additions, and major changes to proved reserves by geographic area for the three-year period ended December 31, 2011, are summarized in the discussion for Table V. Discussion is also provided regarding the nature of, status of and planned future activities associated with the development of proved undeveloped reserves. The company recognizes reserves for projects with various development periods, sometimes exceeding five years. The external factors that impact the duration of a project include scope and complexity, remoteness or adverse operating conditions, infrastructure constraints, and contractual limitations.

 

The net proved reserve balances at the end of each of the three years 2009 through 2011 are shown in the following table.

 

Net Proved Reserves at December 31

 

		2011				2010				2009
Liquids — Millions of barrels
Consolidated Companies			4,295				4,270				4,610
Affiliated Companies			2,160				2,233				2,363
Natural Gas — Billions of cubic feet
Consolidated Companies			25,229				20,755				22,153
Affiliated Companies			3,454				3,496				3,896
Total Oil-Equivalent — Millions of barrels
Consolidated Companies			8,500				7,729				8,303
Affiliated Companies			2,736				2,816				3,012

 

At December 31, 2011, the company owned or had under lease or similar agreements undeveloped and developed crude oil and natural gas properties throughout the world. The geographical distribution of the company’s acreage is shown in the following table.

 

Acreage at December 31, 2011
(Thousands of Acres)

 

																		Developed and
		Undeveloped*								Developed								Undeveloped
		Gross				Net				Gross				Net				Gross				Net
United States			6,290				5,171				7,752				5,051				14,042				10,222
Other Americas			26,803				15,338				1,392				395				28,195				15,733
Africa			8,068				3,921				3,324				1,370				11,392				5,291
Asia			41,125				21,613				5,426				2,760				46,551				24,373
Australia			12,801				6,064				920				240				13,721				6,304
Europe			5,093				3,608				645				137				5,738				3,745
Total Consolidated Companies			100,180				55,715				19,459				9,953				119,639				65,668
Equity in Affiliates			419				191				252				100				671				291
Total Including Affiliates			110,599				55,906				19,711				10,053				120,310				65,959

 

*		The gross undeveloped acres that will expire in 2012, 2013 and 2014 if production is not established by certain required dates are 4,675, 5,993 and 2,903, respectively.

 

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 232 billion cubic feet of natural gas through 2014. 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 indexed and fixed-price contracts.

 

Outside the United States, the company is contractually committed to deliver a total of 891 billion cubic feet of natural gas from 2012 through 2014 from operations in 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 on page FS-62 for details associated with the company’s development expenditures and costs of proved property acquisitions for 2011, 2010 and 2009.

 

The table on the next page 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, 2011. 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

 

		Wells Drilling								Net Wells Completed
		at 12/31/11								2011								2010								2009
		Gross				Net				Prod.				Dry				Prod.				Dry				Prod.				Dry
United States			105				62				909				9				634				7				582				3
Other Americas			8				4				37				—				32				—				36				—
Africa			7				3				29				—				33				—				40				—
Asia			85				37				549				15				445				15				580				10
Australia			1				—				—				—				—				—				—				—
Europe			5				—				6				—				4				—				7				—
Total Consolidated Companies			211				106				1,530				24				1,148				22				1,245				13
Equity in Affiliates			1				1				25				—				8				—				6				—
Total Including Affiliates			212				107				1,555				24				1,156				22				1,251				13

 

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, 2011. “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

 

		Wells Drilling								Net Wells Completed
		at 12/31/11								2011								2010								2009
		Gross				Net				Prod.				Dry				Prod.				Dry				Prod.				Dry
United States			2				2				5				1				1				1				4				5
Other Americas			2				1				1				—				—				1				1				2
Africa			3				1				1				—				1				—				2				1
Asia			1				1				10				1				5				5				9				1
Australia			1				1				4				1				5				2				4				2
Europe			2				1				—				1				—				—				—				—
Total Consolidated Companies			11				7				21				4				12				9				20				11
Equity in Affiliates			—				—				1				—				—				—				—				—
Total Including Affiliates			11				7				22				4				12				9				20				11

 

Refer to Table I on page FS-62 for detail of the company’s exploration expenditures and costs of unproved property acquisitions for 2011, 2010 and 2009.

 

Chevron’s 2011 key upstream activities, some of which are also discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations, beginning on page FS-2, are presented below. The comments include references to “total production” and “net production,” which are defined under “Production” in Exhibit 99.1 on page E-11.

The discussion that follows references the status of proved reserves recognition for significant long-lead-time projects not on production and for projects recently placed on production. Reserves are not discussed for exploration activities or recent discoveries that have not advanced to a project stage or for mature areas of production that do not have individual projects requiring significant levels of capital or exploratory investment. Amounts indicated for project costs represent total project costs, not the company’s share of costs for projects that are less than wholly owned.

 

 

 

Upstream activities in the United States are concentrated in California, the Gulf of Mexico, the Appalachian Basin, Colorado, Michigan, New Mexico, Ohio, Oklahoma, Texas, Wyoming and Alaska. Average net oil-equivalent production in the United States during 2011 was 678,000 barrels per day.

 

In California, the company has significant production in the San Joaquin Valley. In 2011, average net oil-equivalent production was 183,000 barrels per day, composed of 165,000 barrels of crude oil, 83 million cubic feet of natural gas and 4,000 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).

 

the floating production unit hull and topsides modules during 2011. Development drilling operations commenced in fourth quarter 2011. The facility is planned to have a design capacity of 177,000 barrels of oil-equivalent per day to accommodate production from the Jack/St. Malo development, which is estimated to have maximum total daily production of 94,000 barrels of oil equivalent, plus production from a nearby third-party field. Total project costs for the initial phase of development are estimated at $7.5 billion and start-up is expected in 2014. The project has an estimated production life of 30 years. The initial recognition of proved reserves for the project occurred in 2011.

Work continued at the 60 percent-owned and operated Big Foot discovery. The development plan includes a 15-slot drilling and production tension leg platform with water injection facilities and a design capacity of 79,000 barrels of oil equivalent per day. Fabrication of topsides, hull and other components began in first-half 2011 and initial development drilling commenced in fourth quarter 2011. First production is anticipated in 2014. The field has an estimated production life of 20 years. Initial proved reserves were recognized in 2011.

 

Tahiti 2 is the second development phase for the 58 percent-owned and operated Tahiti Field and is designed to increase recovery and return well capacity to 125,000 barrels of oil per day. The project includes three water injection wells, two additional production wells and the water injection facilities required to deliver water to the injection wells. Two water injection wells have been completed and drilling commenced on the first production well in early 2012. The water injection facilities have been installed and water injection began in first quarter 2012. Start-up of the first production well of the second phase is expected by 2013. Initial proved reserves for the Tahiti 2 project were recognized in 2011, and the field has an estimated production life of 30 years.

 

The final investment decision was made for the Tubular Bells deepwater project in fourth quarter 2011. The company has a 42.9 percent nonoperated working interest in the Tubular Bells unitized area after receiving an additional 12.9 percent equity interest relinquished by a partner in 2011. Development drilling is scheduled to begin in second quarter 2012, and plans include three producing and two injection wells, with a subsea tieback to a third-party production facility. First oil is anticipated in 2014, and maximum total daily production is expected to reach 40,000 to 45,000 barrels of oil-equivalent. At the end of 2011, proved reserves had not been recognized for this project.

 

The company has a 20.3 percent nonoperated working interest in the Caesar and Tonga unitized area. Development plans include a total of four wells and a subsea tieback to a nearby third-party production facility. Three of the four development wells have been drilled and completed as of year-end 2011. Drilling of the fourth well is expected to begin in mid-2012. Work on the subsea system, commissioning of the topsides and the initial well completion program continued into 2012. Installation of the production riser and first production are expected in mid-2012. Maximum total production is expected to be 46,000 barrels of oil-equivalent per day. Proved reserves have been recognized for the project.

 

The company has a 15.6 percent nonoperated working interest in the Mad Dog II Project. Front-end engineering and design (FEED) is expected to commence by second quarter 2012. It is anticipated that this future development would require new production facilities to support planned maximum total daily production of 120,000 to 140,000 barrels of oil equivalent. At the end of 2011, proved reserves had not been recognized for this project.

 

Development planning and unitization talks with owners of an adjacent field continued in 2011 for the Knotty Head project. Chevron has a 25 percent nonoperated working interest in this subsalt, Green Canyon Block 512 discovery. At the end of 2011, proved reserves had not been recognized for this project.

 

Deepwater exploration activities in 2011 included participation in four exploratory wells — two wildcats, one appraisal and one delineation. Following successful permitting under new, more stringent, U.S. Department of Interior guidelines, two wells resumed drilling activities after operations were halted in 2010 as a result of the deepwater drilling moratorium in the Gulf of Mexico. Drilling operations at the 43.8 percent-owned and operated Moccasin prospect resumed in first quarter 2011 and resulted in a new discovery in the Lower Tertiary Wilcox Trend. Drilling operations resumed in second quarter 2011 at the 55 percent-owned and operated Buckskin prospect, resulting in a successful appraisal well. These two discoveries, located 12 miles apart, could facilitate future co-development upon the successful completion of additional appraisal drilling planned at each prospect in 2012. Drilling was terminated at the Coronado wildcat well due to drilling conditions in the shallow section of the wellbore. The company plans to drill a replacement well at an alternate location by mid-2012.

 

Besides the activities connected with the development and exploration projects in the Gulf of Mexico, the company also has contracted capacity at the third-party Sabine Pass liquefied natural gas (LNG) regasification terminal in Louisiana and 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 access to 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.

 

future years.

 

In February 2011, Chevron acquired Atlas Energy, Inc. The acquisition provided a natural gas resource position in the Marcellus Shale and Utica Shale, primarily located in southwestern Pennsylvania and Ohio. The acquisition also provided 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. In addition, the acquisition provided assets in Michigan, which include Antrim Shale producing assets and approximately 350,000 total acres in the Antrim and Collingwood/Utica Shale formations. Additional asset acquisitions in 2011 expanded the company’s holdings in the Marcellus and Utica to approximately 700,000 and 600,000 total acres, respectively. In the Marcellus, 61 natural gas wells were completed in 2011.

 

 

“Other Americas” is composed of Argentina, Brazil, Canada, Colombia, Greenland, Trinidad and Tobago, and Venezuela. Net oil-equivalent production from these countries averaged 267,000 barrels per day during 2011, including the company’s share of synthetic oil production.

 

from the platform to obtain early reservoir information. Further drilling is anticipated to commence in 2013 with full production start-up expected in 2014. The initial recognition of proved reserves occurred in 2011 for this project.

 

FEED activities continued in 2011 for the development of the heavy-oil Hebron Field and a final investment decision is expected in 2013. The project has an expected economic life of 30 years. At the end of 2011, proved reserves had not been recognized for this project.

At AOSP, 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. The AOSP Expansion 1 Project activities continued in 2011 with completion of the Scotford Upgrader expansion, which increased daily production design capacity to approximately 255,000 barrels per day.

 

During 2011, the company increased its shale exploration acreage in Alberta in the Duvernay formation. In third quarter 2011, a multiwell drilling program commenced on these 100 percent-owned and operated leases. A long-term well test is expected to begin in fourth quarter 2012, when the first well is expected to be tied into third-party processing facilities. The company also holds exploration licenses and leases in the Flemish Pass and Orphan basins offshore Atlantic Canada, the Mackenzie Delta region of the Northwest Territories and the Beaufort Sea region of Canada’s Arctic, including a 35.4 percent nonoperated working interest in the offshore Amauligak discovery.

 

In addition, Chevron holds interests in the Aitken Creek and Alberta Hub natural gas storage facilities with an approximate total capacity of 100 billion cubic feet. These facilities are located adjacent to the Duvernay, Horn River and Montney shale gas plays.

 

Greenland: In 2011, the Greenland government granted a one-year extension to the initial four-year term for License 2007/26, which includes Block 4 offshore West Greenland. Interpretation of seismic data continued into early 2012. Chevron has a 29.2 percent nonoperated working interest in this exploration license.

 

natural gas.

 

During 2011, development drilling continued at the 51.7 percent-owned and operated Frade Field, located in the Campos Basin. Eleven development wells and four injection wells had been completed as of year-end 2011. Development drilling is planned to continue through 2013, with one additional development well, one sidetrack well and several injection wells. The concession that includes the Frade project expires in 2025.

 

In the partner-operated Campos Basin Block BC-20, two areas — 37.5 percent-owned Papa-Terra and 30 percent-owned Maromba — were retained for development following the end of the exploration phase of this block. During 2011, construction progressed on a floating production, storage and offloading (FPSO) vessel and tension leg well platform for the Papa-Terra project. Development drilling was initiated in fourth quarter 2011. The facility has a planned total daily capacity of 140,000 barrels of crude oil. First production is expected in 2013, and the initial recognition of proved reserves occurred during 2011. Evaluation of the field development concept for Maromba continued into early 2012. At the end of 2011, proved reserves had not been recognized for this project. These concessions expire in 2032.

 

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 based on prior Chuchupa capital contributions. During 2011, a gas export agreement with Venezuela was extended. An onshore, multiwell drilling program commenced in late 2011. Daily net production averaged 234 million cubic feet of natural gas in 2011.

 

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. Net production in 2011 averaged 183 million cubic feet of natural gas per day. Chevron also holds a

50 percent operated interest in the Manatee Area of Block 6(d), which includes a 2005 discovery. During 2011, work progressed to mature a development concept called the Regional Cooperative Agreement.

 

65,000 barrels per day, composed of 60,000 barrels of crude oil, synthetic oil and natural gas liquids and 27 million cubic feet of natural gas.

 

Chevron holds a 34 percent interest in the Petroindependencia affiliate that is working on a heavy-oil project in three blocks within the Carabobo Area of eastern Venezuela’s Orinoco Belt. During 2011, work continued toward commercialization of the Carabobo 3 Project. Conceptual engineering for the potential development of the concession is in progress.

 

The company operates and has a working interest of 60 percent in Block 2 in the Plataforma Deltana area offshore eastern Venezuela. During 2011, work progressed to mature a development concept called the Regional Cooperative Agreement.

 

 

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 459,000 barrels per day during 2011.

 

of the N’Dola Field development with a final investment decision expected in late 2012. At year-end 2011, no proved reserves were recognized for these projects.

 

In Block 0, the Area A gas management projects at the Takula and Malongo reservoirs were designed to eliminate routine flaring of natural gas. The final project entered service in 2011, which together have reduced flaring by approximately 70 million cubic feet per day, as of year-end 2011. In Area B, the first stage of the Nemba Enhanced Secondary Recovery and Flare Reduction Project was completed in second quarter 2011. The final stage is expected to eliminate routine flaring at the North and South Nemba platforms and is scheduled to begin gas injection in 2014.

 

Also in Block 0, a two-well appraisal and exploration program was completed in 2011. The appraisal well completed in July 2011 in the Lifua Field was successful and development opportunities are being evaluated. The second well, completed in October 2011 in the pre-salt play, was not successful. Two additional exploratory wells are planned for second-half 2012.

 

In the 31 percent-owned Block 14, net production in 2011 averaged 29,000 barrels of liquids per day. Development and production rights for the various producing fields in Block 14 expire between 2023 and 2028.

 

For the Lucapa Field in Block 14, development alternatives continued to be evaluated during 2011. The project is expected to enter FEED in second quarter 2012. Development alternatives were evaluated during the year at the Malange Field and the preferred alternative is expected to enter FEED in mid-2012. As of the end of 2011, development of the Negage Field remained suspended until cooperative arrangements between Angola and Democratic Republic of the Congo are finalized. At the end of 2011, proved reserves had not been recognized for these projects.

 

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 at Soyo, Angola. The plant is designed to process 1.1 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 2011, reaching mechanical completion at year-end. The first LNG shipment from the plant is expected in second quarter 2012. The estimated total cost of the LNG plant is $10 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. The pipeline project entered construction in May 2011 and is expected to be completed in late 2013. Proved reserves have been recognized for the producing operations associated with the Angola LNG 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. A final investment decision for the Lianzi development project is expected in mid-2012. The project is expected to commence production in late 2014. At the end of 2011, proved reserves had not been recognized for the project.

 

Democratic Republic of the Congo: Chevron has a 17.7 percent nonoperated working interest in an offshore concession. Daily net production in 2011 averaged 3,000 barrels of oil-equivalent.

 

Republic of the Congo: Chevron has a 31.5 percent nonoperated working interest in the Nkossa, Nsoko and Moho-Bilondo permit areas and a 29.3 percent nonoperated working interest in the Kitina permit area, all of which are offshore. The development and production rights for Kitina, Nsoko, Nkossa and Moho-Bilondo expire in 2014, 2018, 2027 and 2030, respectively. Net production averaged 23,000 barrels of oil-equivalent per day in 2011.

 

The Moho Nord Project, located in the Moho-Bilondo Development Area, entered FEED in fourth quarter 2011. The project is expected to reach a final investment decision in 2013. At the end of 2011, proved reserves had not been recognized for this project.

 

Chad/Cameroon: Chevron has a 25 percent nonoperated working interest in crude oil producing operations in southern Chad and an approximate 21 percent interest in two affiliates that own an export pipeline that transports the crude oil to the coast of Cameroon. Average daily net production from the Chad fields in 2011 was 26,000 barrels of oil-equivalent. The Chad producing operations are conducted under a concession that expires in 2030.

 

completed and placed on production in second-half 2012. The leases that contain the Agbami Field expire in 2023 and 2024.

 

The company holds a 30 percent nonoperated working interest in the deepwater Usan project in OML 138. During 2011, development drilling continued and the FPSO vessel was moored on location. Production start-up is expected in early 2012, with maximum total production of 180,000 barrels of crude oil per day expected within one year of start-up. The production-sharing contract (PSC) expires in 2023. Proved reserves have been recognized for this project.

 

Also in the deepwater area, the Aparo Field in OML 132 and OML 140 and the third-party-owned Bonga SW Field in OML 118 share a common geologic structure and are planned to be jointly developed. Initiation of FEED is expected in late 2012. At the end of 2011, no proved reserves were recognized for this project.

 

In the Niger Delta, ramp-up activity continued at the Escravos Gas Plant (EGP). During 2011, construction continued on Phase 3B of the EGP project, which 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 Phase 3B project is expected to be completed in 2016. Proved reserves associated with this project have been recognized.

 

The 40 percent-owned and operated Sonam Field Development includes facilities to produce natural gas from the Sonam natural gas field in the Escravos area. The project is designed to utilize EGP and to deliver 215 million cubic feet of natural gas per day to the domestic market, and produce an average of 30,000 barrels of liquids per day. A final investment decision was reached in late 2011, and first production is expected in 2016. Proved reserves associated with the project were recognized in 2011.

 

Chevron has a 75 percent-owned and operated interest in a gas-to-liquids facility at Escravos that is being developed with the Nigerian National Petroleum Corporation. The 33,000-barrel-per-day facility 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 2011, work on the project was more than 80 percent complete and start-up is planned for 2013. The estimated cost of the plant is $8.4 billion.

 

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. Construction activities continued through 2011, and start-up is scheduled for late 2012.

 

In deepwater exploration, the company has 20 percent and 27 percent nonoperated working interests in Oil Prospecting License (OPL) 214 and OPL 223, respectively. Drilling of two exploration wells commenced in fourth quarter 2011 in OPL 214, and one exploration well is planned in OPL 223 for second-half 2012. In addition, Chevron operates and holds a 95 percent interest in the deepwater Nsiko discovery in OML 140 where further exploration activities are planned.

Shallow-water exploration activities in 2011 included reprocessing 3-D seismic data from OML 86 and OML 88. In November 2011, the company began drilling a well in OML 86. In January 2012, while drilling the well, there was a release of natural gas that led to a fire. Drilling of a relief well commenced in February 2012. A root cause investigation is under way.

 

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 West African Gas Pipeline. The pipeline supplies Nigerian natural gas to customers in Benin, Ghana and Togo for industrial applications and power generation and has the capacity to transport 170 million cubic feet per day.

 

Liberia: In 2010, Chevron acquired a 70 percent interest and operatorship in three deepwater blocks off the coast of Liberia. Exploration drilling prospects were identified during 2011 based on 3-D seismic data. Two exploration wells are planned to be drilled in 2012.

 

 

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 2011, net oil-equivalent production averaged 1,029,000 barrels per day.

wholly owned by AIOC, with capacity to transport 100,000 barrels per day from Baku, Azerbaijan, to a 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 2011 from these fields averaged 296,000 barrels per day, composed of 244,000 barrels of crude oil and natural gas liquids and 312 million cubic feet of natural gas. During 2011, 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 exported via rail to Black Sea ports.

 

Also during 2011, 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 sour gas injection technology utilized in current operations. Approval of FEED is anticipated in 2012. As of year-end 2011, proved reserves had not been recognized for this expansion project.

Chevron holds a 20 percent nonoperated working interest in the Karachaganak project, which is conducted under a PSC that expires in 2038. During 2011, Karachaganak net oil-equivalent production averaged 62,000 barrels per day, composed of 38,000 barrels of liquids and 144 million cubic feet of natural gas. In 2011, access to the CPC and Atyrau-Samara (Russia) pipelines enabled approximately 204,000 barrels per day (34,000 net barrels) of Karachaganak liquids to be sold at world-market prices. The remaining liquids were sold into local and Russian markets. During 2011, a fourth train entered production and increased total liquids-stabilization capacity by 56,000 barrels per day, allowing increased sales of condensate into world markets. Karachaganak project partners have reached an agreement allowing the government of Kazakhstan to become a 10 percent equity owner in the Karachaganak project. The transfer of equity to the government is anticipated to occur in June 2012 and will result in Chevron’s working interest being reduced to 18 percent.

 

During 2011, Chevron and its partners continued to evaluate alternatives for a Phase III development of Karachaganak. The timing of the project remains uncertain until a project design is finalized. At the end of 2011, proved reserves had not been recognized for the project.

 

Kazakhstan/Russia: Chevron has a 15 percent interest in the CPC affiliate. During 2011, CPC transported an average of approximately 684,000 barrels of crude oil per day, including 608,000 barrels per day from Kazakhstan and 76,000 barrels per day from Russia. During 2011, the partners began construction on a project to increase 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 maximum capacity of 1.4 million barrels per day in 2016.

 

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

 

Bangladesh: Chevron holds a 98 percent interest in two operated PSCs covering Blocks 12, 13 and 14. Net oil-equivalent production from these operations in 2011 averaged 74,000 barrels per day, composed of 434 million cubic feet of natural gas and 2,000 barrels of liquids. In 2011, the Muchai compression project achieved mechanical completion and is expected to support additional production starting in second quarter 2012 from the Bibiyana, Jalalabad and Moulavi Bazar natural gas fields. Proved reserves have been recognized for this project. The Bibiyana Expansion Project entered FEED in July 2011. Project scope includes expansion of the gas plant, additional development drilling and an enhanced liquids recovery unit, with an estimated total maximum daily production of 57,000 barrels of oil equivalent. A final investment decision is expected in mid-2012. At the end of 2011, proved reserves had not been recognized for this project. Also in 2011, the company relinquished its interest in Block 7 subsequent to the completion of an unsuccessful exploratory well.

Thailand: Chevron has operated and nonoperated working interests in multiple offshore blocks. The company’s net oil-equivalent production in 2011 averaged 209,000 barrels per day, composed of 65,000 barrels of crude oil and condensate and 867 million cubic feet of natural gas. All of the company’s natural gas production is sold to PTT Public Company Limited, Thailand’s national oil company, under long-term sales contracts.

 

Operated interests are in the Pattani Basin with ownership interests ranging from 35 percent to 80 percent. Concessions for producing areas within this basin expire between 2020 and 2035. Chevron has a 16 percent nonoperated working interest in the Arthit and North Arthit fields located in the Malay Basin. Concessions for the producing areas within this basin expire between 2036 and 2040.

 

Start-up of the 69.9 percent-owned and operated Platong II natural gas project occurred in October 2011, and total average daily production ramped up to 377 million cubic feet of natural gas and 11,000 barrels of condensate as of the end of 2011. Proved reserves have been recognized for this project.

 

During 2011, the company drilled nine exploration wells in the Pattani Basin. All of the wells were successful and development alternatives are being evaluated. 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.

 

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, a central processing platform and a pipeline to shore. FEED continued during 2011. Maximum total daily production is expected to be 490 million cubic feet of natural gas and 4,000 barrels of condensate. A final investment decision is expected to be reached in 2012. At the end of 2011, proved reserves had not been recognized for the development project.

 

During the year, work continued on preparations for a 2012 exploration drilling program to further evaluate the potential of the three company-operated blocks in the Malay Basin. The company also completed the evaluation of Block 122 offshore eastern Vietnam and reached a decision to exit the block.

 

working interest in Blocks 53/30 and 64/18, and a 59.2 percent working interest in Block 42/05 under three separate PSCs. The three deepwater blocks cover approximately 4.8 million acres. During 2011, a 3-D seismic acquisition program was completed for Blocks 64/18 and 53/30 and a three-well exploration program was initiated. The first well was unsuccessful. The second and third wells are expected to be completed by mid-2012.

 

The company signed a joint study agreement to explore for natural gas from shale resources in the Qiannan Basin in April 2011 and commenced seismic operations in July 2011.

 

The company also has nonoperated working interests of 32.7 percent in Blocks 16/08 and 16/19 in the Pearl River Mouth Basin and nonoperated working interests of 24.5 percent in the QHD 32-6 Field and 16.2 percent in Block 11/19 in the Bohai Bay.

 

 

The company’s net oil-equivalent production in 2011 from its interests in Indonesia averaged 208,000 barrels per day, composed of 166,000 barrels of liquids and 253 million cubic feet of natural gas. The largest producing field is Duri, located in the Rokan PSC. Duri has been under steamflood since 1985 and is one of the world’s largest steamflood developments. The North Duri Development is divided into multiple expansion areas. Government approval of the construction contract bid awards for North Duri Area 13 expansion project is expected in mid-2012 with start-up scheduled for 2013. The Rokan PSC expires in 2021.

 

During 2011, two deepwater development projects in the Kutei Basin progressed under a single plan of development. In the first of these projects, Chevron advanced FEED for the Gendalo-Gehem deepwater natural gas project. The project includes two separate hub developments, natural gas and condensate pipelines, and an onshore receiving facility. Maximum daily total production from the project is expected to be about 1.1 billion cubic feet of natural gas and 31,000 barrels of condensate. Gas from the project is expected to be used domestically and for LNG export. The company’s working interest is approximately 63 percent. At the end of 2011, proved reserves had not been recognized for this project.

 

In the second of these projects, FEED was completed in December 2011 for the Bangka deepwater natural gas project and the contracting approval process began with the government of Indonesia. The project scope includes a subsea tie back to a floating production unit. The company’s working interest is 62 percent. At year-end 2011, proved reserves had not been recognized for this project.

 

Exploration activities continued in the Central Sumatra Basin where six successful appraisal wells were drilled in the Bekasap, Duri and Kulin fields in 2011, and evaluation of a well drilled in the Jorang Field continued in 2012. Also in 2011, seismic data acquisition was completed for West Papua I and is under way for West Papua III. Processing of the seismic data is planned for 2012.

 

In West Java, Chevron operates the wholly owned Salak geothermal field with a total power-generation capacity of 377 megawatts and 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 the company’s operation in Duri, Sumatra. In the Suoh-Sekincau prospect area of Sumatra, the company holds a 95 percent-owned and operated interest in a license to explore and develop a geothermal prospect.

 

progressed during 2011 and is expected to enter FEED in second-half 2012. At the end of 2011, proved reserves had not been recognized for these projects.

 

Also in 2011, the Central Gas Utilization Project entered FEED. The project is intended to increase natural gas utilization and eliminate routine flaring. A final investment decision is expected in 2013. At year-end 2011, proved reserves had not 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 2011 averaged 25,000 barrels per day, composed of 126 million cubic feet of natural gas and 4,000 barrels of condensate. During 2011, studies were progressed to maintain capacity.

 

Chevron also develops and produces geothermal resources under an agreement with the Philippine government. During 2011, efforts continued to seek a new 25-year contract with the government for the continued operation of the steam fields, which supply geothermal resources to third-party, 637-megawatt power generation facilities in southern Luzon. Chevron also has a 90 percent-owned and operated interest in the Kalinga geothermal prospect area in northern Luzon and is in the early phase of geological and geophysical assessments.

 

 

In Australia, the company’s exploration and production efforts are concentrated off the northwest coast. During 2011, the average net oil-equivalent production from Australia was 101,000 barrels per day.

 

2 billion cubic feet of natural gas and 39,000 barrels of condensate. Total estimated projects costs are $5.4 billion and start-up is expected in 2013. Proved reserves have been recognized for the project.

The NWS Oil Redevelopment Project recommenced production from the Cossack, Hermes, Lambert and Wanaea fields in September 2011. The project included replacement of an FPSO vessel and a portion of existing subsea infrastructure. The project is expected to extend production from these fields beyond 2020.

 

Chevron holds a 47.3 percent ownership interest across most of the Greater Gorgon Area and is the operator of the Gorgon Project, which combines the development of the Gorgon and nearby Io/Jansz natural gas field. The project’s scope includes a three-train, 15 million-metric-ton-per-year LNG facility, a carbon sequestration project and a domestic natural gas plant. Maximum total daily production from the project is expected to reach about 2.6 billion cubic feet of natural gas and 20,000 barrels of condensate. Total estimated project costs for the first phase of development are $37 billion.

 

Work on the Gorgon Project progressed on schedule. As of year-end 2011, more than one-third of the construction activities across numerous fronts on Barrow Island and in fabrication yards in various countries had been completed. The development drilling program also commenced in July 2011.

 

Through year-end 2011, Chevron has signed binding LNG Sales and Purchase Agreements (SPAs) with six Asian customers for delivery of about 4.7 million metric tons of LNG per year, which brings delivery commitments to about 70 percent of Chevron’s share of LNG from this project. Discussions continue with potential customers to increase long-term sales to 85 to 90 percent of Chevron’s net LNG off-take. Binding SPAs were also signed in 2011 for delivery of about 55 million cubic feet per day of natural gas to two Western Australian state-owned utilities starting in 2015. 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 late 2014. The project’s estimated economic life exceeds 40 years from the time of start-up.

 

A project for development of a fourth train at the Gorgon LNG facility is expected to enter FEED in late 2012. At the end of 2011, proved reserves had not been recognized for the fields associated with this expansion.

 

Chevron and its joint-venture partners are proceeding with development of the Wheatstone Project. In September 2011, the company announced the final investment decision. Construction started in late 2011. Chevron holds a 72.1 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 foundation project from the company-operated and 90.2 percent-owned Wheatstone and Iago fields. Maximum total daily production is expected to be about 1.4 billion cubic feet of natural gas and 25,000 barrels of condensate. The LNG facilities will also be a destination for third-party natural gas. Total estimated project costs for the first phase of development are $29 billion.

 

Through the end of 2011, Chevron has signed binding SPAs with two Asian customers for the delivery of about 60 percent of Chevron’s net LNG off-take from the Wheatstone Project. Discussions continue with potential customers to increase long-term sales to 85 to 90 percent of Chevron’s net LNG off-take and to sell down equity. Start-up of the first LNG train is expected in 2016. During 2011, the company recognized proved reserves for this project.

 

In the Browse Basin, the Browse LNG development participants entered FEED in 2011, undertaking environmental, geophysical, geotechnical and engineering and design studies for the Brecknock, Calliance and Torosa fields. At the end of 2011, proved reserves had not been recognized for any of the Browse Basin fields.

 

During 2011, the company announced a natural gas discovery at the 50 percent-owned and operated Orthrus Deep prospect in Block WA-24-R. The company also announced natural gas discoveries at the 50 percent-owned and operated Vos prospect in WA-439-P and the 67 percent-owned and operated Acme West prospect in Block WA-205-P in 2011, and at the 50 percent-owned and operated Satyr-3 prospect in WA-374-P in January 2012. These discoveries are expected to support potential expansion opportunities at company-operated LNG facilities.

 

In Europe, the company is engaged in exploration and production activities in Bulgaria, Denmark, the Netherlands, Norway, Poland, Romania and the United Kingdom. Net oil-equivalent production in Europe averaged 139,000 barrels per day during 2011.

 

and operated Alba Field, and the 32.4 percent-owned and jointly operated Britannia Field.

 

The final investment decision was reached in fourth quarter 2011 for the Clair Ridge Project, located west of the Shetland Islands, in which the company has a 19.4 percent nonoperated working interest. Total design capacity is planned to be 120,000 barrels of crude oil per day, and total estimated projects costs are $7 billion. Production is scheduled to begin in 2016. Initial proved reserves were recognized for this phase of the project in 2011.

 

At the 70 percent-owned and operated Alder discovery, FEED activities progressed during 2011 and a final investment decision is planned for late 2012. In the 40 percent-owned and operated Rosebank area northwest of the Shetland Islands, seismic, geophysical, geotechnical and environmental surveys were completed during 2011, and FEED is expected to begin in the second-half 2012. At the end of 2011, proved reserves have not been recognized for these projects.

 

Also west of the Shetland Islands, a three-well exploration and appraisal drilling program continued through 2011 and was completed in early 2012. This program comprised exploration wells on the Lagavulin and Aberlour prospects and appraisal drilling and well testing of the Cambo discovery. The Lagavulin well was unsuccessful and the results from the other wells are under evaluation. Licenses P1196 (Lagavulin) and P1165 (Talisker) were relinquished in November 2011 at the termination of the license period.

 

In addition, the company entered into a master regasification agreement for access to available capacity at the South Hook LNG terminal in southwest Wales in 2011.

 

 

Romania: The company holds a 100 percent interest in the EV-2 Barlad shale concession. This license, located in northeast Romania, covers 1.6 million acres. In 2011, the company acquired 2-D seismic data across the EV-2 Barlad concession. A multiwell drilling program is expected to begin in late 2012. Also during 2011, the company continued negotiations on license agreements for three shale exploration blocks in southeast Romania, Blocks 17, 18 and 19, which comprise approximately 670,000 acres.

 

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 2011, U.S. and international sales of natural gas were 5.8 billion and 4.4 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 87 thousand barrels per day, respectively, in 2011. Substantially all of the international sales of natural gas liquids are from company operations in Africa, Kazakhstan, Indonesia and the United Kingdom.

 

Refer to “Selected Operating Data,” on page FS-10 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 7 for information related to the company’s delivery commitments for the sale of crude oil and natural gas.

 

 

At the end of 2011, the company had a refining network capable of processing about 2 million barrels of crude oil per day. Operable capacity at December 31, 2011, and daily refinery inputs for 2009 through 2011 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)

 

				December 31, 2011
								Operable				Refinery Inputs
Locations				Number				Capacity				2011				2010				2009
Pascagoula		Mississippi			1				330				327				325				345
El Segundo		California			1				269				244				250				247
Richmond		California			1				257				192				228				218
Kapolei		Hawaii			1				54				47				46				49
Salt Lake City		Utah			1				45				44				41				40
Perth Amboy1		New Jersey			1				80				—				—				—
Total Consolidated Companies — United States					6				1,035				854				890				899
Pembroke2		United Kingdom			—				—				122				211				205
Cape Town3		South Africa			1				110				77				70				72
Burnaby, B.C.		Canada			1				55				43				40				49
Total Consolidated Companies — International					2				165				242				321				326
Affiliates4		Various Locations			7				767				691				683				653
Total Including Affiliates — International					9				932				933				1,004				979
Total Including Affiliates — Worldwide					15				1,967				1,787				1,894				1,878

 

 

Average crude oil distillation capacity utilization during 2011 was 89 percent, compared with 92 percent in 2010. At the U.S. fuel refineries, crude oil distillation capacity utilization averaged 89 percent in 2011, compared with 95 percent in 2010. Chevron processes both imported and domestic crude oil in its U.S. refining operations. Imported crude oil accounted for about 85 percent and 84 percent of Chevron’s U.S. refinery inputs in 2011 and 2010, respectively.

 

At the Pascagoula Refinery, construction progressed on 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. In February 2012, the company signed an agreement to sell its idled 80,000-barrel-per-day refinery, which is operating as a terminal, at Perth Amboy. The sale is expected to close in second quarter 2012.

 

At the refinery in El Segundo, construction progressed 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 third quarter 2012. At the Richmond Refinery, the company filed an application for a conditional use permit for a revised project and the City of Richmond published its Notice of Preparation of the revised Environmental Impact Report in second quarter 2011. 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 on page FS-57.

Outside the United States, GS Caltex, the company’s 50 percent-owned affiliate, progressed the construction of a 53,000-barrel-per-day gas oil fluid catalytic cracking unit at the Yeosu Refinery in South Korea. The unit is scheduled for start-up in 2013. The unit is designed to increase high-value product yield and lower feedstock costs. Construction continued on modifications to the 64 percent-owned Star Petroleum Refinery in Thailand to meet regional specifications for cleaner fuels. Project completion is scheduled for 2012. During August 2011, the company completed the sale of the Pembroke Refinery in the United Kingdom. Also in 2011, Caltex Australia Ltd., the company’s 50 percent-owned affiliate, initiated a review of its refining operations in Australia, which is ongoing.

 

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, 2011.

 

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 2011, the company supplied directly or through retailers and marketers approximately 8,170 Chevron- and Texaco-branded motor vehicle service stations, primarily in the southern and western states. Approximately 490 of these outlets are company-owned or -leased stations.

 

Outside the United States, Chevron supplied directly or through retailers and marketers approximately 9,660 branded service stations, including affiliates. In British Columbia, Canada, the company markets under the Chevron brand. The company markets in 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 continued its ongoing effort to concentrate downstream resources and capital on strategic assets. In 2011, the company completed the sale of its fuels marketing and aviation businesses in 16 countries in the Caribbean and Latin America and certain marketing businesses in five countries in Africa. In August 2011, the company also completed the sale of its marketing businesses in Ireland and the United Kingdom. In 2012, the company expects to complete the sale of its fuels marketing, finished lubricants and aviation fuels businesses in Spain as well as certain fuels marketing and aviation businesses in the central Caribbean, following receipt of required local regulatory and government approvals. In addition, the company converted more than 240 company-operated service stations into retailer-owned sites in various countries outside the United States.

Chevron markets commercial aviation fuel at approximately 170 airports worldwide. The company also markets an extensive line of lubricant and coolant products under the brand names 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 2011, CPChem owned or had joint-venture interests in 38 manufacturing facilities and four research and technical centers around the world.

 

CPChem’s 35 percent-owned Saudi Polymers Company expects to commence commercial operations on a new petrochemical project in Al Jubail, Saudi Arabia, in 2012. The joint-venture project includes olefins, polyethylene, polypropylene, 1-hexene and polystyrene units.

 

In the United States, CPChem continued with plans to construct a 1-hexene plant at the company’s Cedar Bayou complex in Baytown, Texas, capable of producing in excess of 200,000 tons per year. Start-up is expected 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. CPChem is also conducting a feasibility study to evaluate a potential U.S. Gulf Coast ethylene cracker and derivatives complex to capitalize on advantaged feedstock sourced from emerging shale gas development in North America.

 

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. In February 2012, the company reached a final investment decision to significantly increase the capacity of the existing additives plant in Singapore.

 

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.

 

Pipeline Mileage at December 31, 2011

 

 

Work was completed in first quarter 2012 to return the Cal-Ky Pipeline to 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 company is leading the construction of a 136 mile, 24-inch pipeline 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 Texas and Louisiana.

 

Refer to pages 14, 16 and 17 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 2011. During 2011, the company had 48 deep-sea vessels chartered on a voyage basis, or for a period of less than one year. The table below summarizes the capacity of the company’s controlled fleet.

 

Controlled Tankers at December 31, 2011¹

 

 

The company’s 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. The company retired one U.S.-flagged product tanker in 2011.

 

The foreign-flagged vessels are engaged primarily in transporting crude oil from the Middle East, Southeast Asia, the Black Sea, South America, Mexico and West Africa to ports in the United States, Europe, Australia and Asia. The company’s foreign-flagged vessels also transport refined products to and from various locations worldwide.

 

In addition to the vessels described above, the company has contracts in place to build LNG carriers and a dynamic-positioning shuttle tanker to support future upstream projects. The company also owns a one-sixth interest in each of seven LNG carriers transporting cargoes for the North West Shelf Venture in Australia.

 

Chevron’s U.S.-based mining company continues its efforts to divest its remaining coal mining operations. The company completed the sale of the North River Mine and other coal-related assets in Alabama in second quarter 2011, and the sale of its Kemmerer, Wyoming, surface coal mine in first quarter 2012. The company is pursuing the sale of its 50 percent interest in Youngs Creek Mining Company, LLC, which was formed to develop a coal mine in northern Wyoming. Activities related to final reclamation continued in 2011 at the company-operated surface coal mine in McKinley, New Mexico, which ceased coal production at the end of 2009.

 

At year-end 2011, Chevron had 153 million tons of proven and probable coal reserves in the United States, including reserves of low-sulfur coal. Coal sales from wholly owned mines in 2011 were 6 million tons, down about 2 million tons from 2010.

In addition to the coal operations, Chevron owns and operates the Questa molybdenum mine in New Mexico. At year-end 2011, Chevron had 53 million pounds of proven molybdenum reserves at Questa. Production and underground development at Questa continued at reduced levels in 2011 in response to weak prices for molybdenum.

 

Chevron’s Global Power Company manages 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 recovered waste heat to produce electricity and support industrial thermal hosts. The 13th facility is a wind farm, located in Casper, Wyoming, that is designed to optimize the use of a decommissioned refinery site for delivery of clean, renewable energy to the local utility.

 

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 company’s geothermal operations and renewable energy projects, refer to pages 19 and 20 and “Research and Technology” below.

 

CES is a wholly owned subsidiary that develops and builds sustainable energy projects that increase energy efficiency and production of renewable power, reduce energy costs, and ensure reliable, high-quality energy for government, education and business facilities. Since 2000, CES has developed hundreds of projects that have helped customers reduce their energy costs and environmental impact. Projects announced in 2011 include the City of Dinuba solar project in California; the Houston Independent School District renewable and energy efficiency project in Texas; the Eglin Air Force Base energy management systems upgrade project in Florida; and the Oceanic Time Warner solar project in Hawaii.

 

The company’s energy technology organization supports Chevron’s 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 disciplines. The information technology organization integrates computing, telecommunications, data management, security and network technology to provide a standardized digital infrastructure and enable Chevron’s global operations and business processes.

 

Chevron Technology Ventures (CTV) manages investments and projects in emerging energy technologies and their integration into Chevron’s core businesses. As of the end of 2011, CTV continued to explore technologies such as next-generation biofuels and advanced solar. In 2011, the company completed construction and commissioned the world’s largest solar-to-steam generation project for use in enhanced-oil-recovery operations in Coalinga, California. The project will test the viability of using solar power to produce steam to improve oil recovery.

 

Chevron’s research and development expenses were $627 million, $526 million and $603 million for the years 2011, 2010 and 2009, 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 company designs, operates and maintains its facilities to avoid potential spills or leaks and minimize the impact of those that may occur. Chevron requires its facilities and operations to have operating standards and processes and emergency response plans that address all credible and significant risks identified by site-specific risk and impact assessments. Chevron also requires that sufficient resources be available to execute these plans. In the unlikely event that a major spill or leak occurs, Chevron also maintains a Worldwide Emergency Response Team comprised of employees who are trained in various aspects of emergency response, including post-incident remediation.

To complement the company’s capabilities, Chevron maintains active membership in international oil spill response cooperatives, including the Marine Spill Response Corporation, which operates in U.S. territorial waters, and Oil Spill Response, Ltd. (OSRL), which operates globally. The company is a founding member of the Marine Well Containment Company, whose primary mission is to expediently deploy containment equipment and systems to capture and contain crude oil in the unlikely event of a future loss of control of a deepwater well in the Gulf of Mexico. In addition, the company is a member of the Subsea Well Response Project (SWRP). SWRP’s objective is to further develop the industry’s capability to contain and shut in subsea well control incidents in different regions of the world. In late 2011, upon detection of ocean floor oil seeps in the deepwater Frade Field in Brazil, Chevron rapidly deployed capabilities and processes in coordination with OSRL. In early 2012, the company rapidly deployed response capabilities to address a natural gas well control incident in Nigeria.

 

Virtually all aspects of the company’s 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 the company’s operations are, or are expected to become, embedded in the normal costs of conducting business.

 

In 2011, the company’s U.S. capitalized environmental expenditures were $345 million, representing about 3 percent of the company’s 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 company’s refineries, oil and gas producing facilities, and marketing facilities. For 2012, the company estimates U.S. capital expenditures for environmental control facilities will be approximately $410 million. The future annual capital costs are uncertain and will be governed by several factors, including future changes to regulatory requirements.

 

Regulations intended to protect the environment, including those intended to address concerns about greenhouse gas emissions and global climate change, continue to evolve. Legislation, regulations and market-based programs that could affect the company’s operations exist at the international or multinational (such as the Kyoto Protocol and the European Union’s Emissions Trading System), national (such as the U.S. Environmental Protection Agency’s rules for stricter emission standards and increased renewable fuel content for transportation fuels), and regional (such as California’s Global Warming Solutions Act) levels.

 

Refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages FS-14 through FS-16 for additional information on environmental matters and their impact on Chevron and on the company’s 2011 environmental expenditures, remediation provisions and year-end environmental reserves. Refer also to Item 1A. Risk Factors on pages 29 through 31 for a discussion of greenhouse gas regulation and climate change.

 

The company’s Internet Web site is www.chevron.com. Information contained on the company’s Internet Web site is not part of this Annual Report on Form 10-K. The company’s 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 company’s Web site soon after such reports are filed with or furnished to the Securities and Exchange Commission (SEC). The reports are also available on the SEC’s Web site at www.sec.gov.

 

 

Chevron is a global energy company with a diversified business portfolio, a strong balance sheet, and a history of generating sufficient cash to pay dividends and fund capital and exploratory expenditures. Nevertheless, some inherent risks could materially impact the company’s financial results of operations or financial condition.

 

Chevron is exposed to the effects of changing commodity prices.

 

Chevron is primarily in a commodities business with a history of price volatility. The single largest variable that affects the company’s results of operations is the price of crude oil, which can be influenced by general 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 geopolitical risk. Chevron accepts the risk of changing commodity prices as part of its business planning process. As such, an investment in the company carries significant exposure to fluctuations in crude oil prices.

During extended periods of historically low prices for crude oil, the company’s 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 Chevron’s 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 company’s 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 on schedule; and efficient and profitable operation of mature properties.

 

The company’s operations could be disrupted by natural or human factors.

 

Chevron operates in both urban areas and remote and sometimes inhospitable regions. The company’s operations and facilities are therefore subject to disruption from either natural or human causes beyond its control, including hurricanes, floods and other forms of severe weather, war, civil unrest and other political events, fires, earthquakes, system failures, cyber threats and terrorist acts, any of which could result in suspension of operations or harm to people or the natural environment.

 

The company’s operations have inherent risks and hazards that require significant and continuous oversight.

 

Chevron’s results depend on its ability to identify and mitigate the risks and hazards inherent to operating in the crude oil and natural gas industry. The company seeks to minimize these operational risks by carefully designing and building its facilities and conducting its operations in a safe and reliable manner. However, failure to manage these risks effectively could result in unexpected incidents, including releases, explosions or mechanical failures resulting in personal injury, loss of life, environmental damage, loss of revenues, legal liability and/or disruption to operations. Chevron has implemented and maintains a system of corporate policies, behaviors and compliance mechanisms to manage safety, health, environmental, reliability and efficiency risks; to verify compliance with applicable laws and policies; and to respond to and learn from unexpected incidents. Nonetheless, in certain situations where Chevron is not the operator, the company may have limited influence and control over third parties, which may limit its ability to manage and control such risks.

 

Chevron’s business subjects the company to liability risks from litigation or government action.

 

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 its 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 or significant delays in operations 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 company’s 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 company’s causation of or contribution to the asserted damage, or to other mitigating factors.

 

The company does not insure against all potential losses, which could result in significant financial exposure.

 

The company does not have commercial insurance or third-party indemnities to cover fully all operational risks or potential liability in the event of a significant incident or series of incidents causing catastrophic loss. As a result the company is, to a substantial extent, self-insured for such events. The company relies on existing liquidity, financial resources and borrowing capacity to meet short-term obligations that would arise from such an event or series of events. The occurrence of a significant incident or unforeseen liability for which the company is not fully insured or for which insurance recovery is significantly delayed could have a material adverse effect on the company’s results of operations or financial condition.

 

Political instability and significant changes in the regulatory environment could harm Chevron’s business.

 

The company’s 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 company’s partially or wholly owned businesses or to impose additional taxes or royalties.

 

In certain locations, governments have imposed or proposed restrictions on the company’s operations, export and exchange controls, burdensome taxes, and public disclosure requirements that might harm the company’s competitiveness or relations with other governments or third parties. In other countries, political conditions have existed that may threaten the safety of employees and the company’s continued presence in those countries and internal unrest, acts of violence or strained relations between a government and the company or other governments may adversely affect the company’s operations. Those developments have, at times, significantly affected the company’s related operations and results and are carefully considered by management when evaluating the level of current and future activity in such countries. At December 31, 2011, 22 percent of the company’s net proved reserves were located in Kazakhstan. The company also has significant interests in OPEC-member countries, including Angola, Nigeria and Venezuela and in the Partitioned Zone between Saudi Arabia and Kuwait. Twenty-two percent of the company’s net proved reserves, including affiliates, were located in OPEC countries at December 31, 2011.

 

Regulation of greenhouse gas emissions could increase Chevron’s operational costs and reduce demand for Chevron’s 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 company’s 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. 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 depending on the laws enacted in each jurisdiction, the company’s activities in it and market conditions. Greenhouse gas emissions that could be regulated include those arising from the company’s exploration and production of crude oil and natural gas; 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 company’s products. Some of these activities, such as consumers’ and customers’ use of the company’s products, as well as actions taken by the company’s competitors in response to such laws and regulations, are beyond the company’s control.

 

The effect of regulation on the company’s 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 would 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 company’s ability to recover the costs incurred through the pricing of the company’s 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 company’s sales volumes, revenues and margins.

 

Changes in management’s estimates and assumptions may have a material impact on the company’s consolidated financial statements and financial or operations performance in any given period.

 

In preparing the company’s periodic reports under the Securities Exchange Act of 1934, including its financial statements, Chevron’s 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 management’s 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 company’s business plans, general market conditions or changes in commodity prices, could affect reported amounts of assets, liabilities or expenses.

 

 

None.

 

The location and character of the company’s 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-62 through FS-76. Note 13, “Properties, Plant and Equipment,” to the company’s financial statements is on page FS-41.

 

 

Ecuador

Information related to Ecuador matters is included in Note 14 to the Consolidated Financial Statements under the heading Ecuador, beginning on page FS-41.

 

Certain Governmental Proceedings

In November 2008, the California Air Resources Board (CARB) proposed a civil penalty against Chevron’s Sacramento, California, terminal for alleged violations between August and December 2007 of CARB’s regulations governing the minimum concentration of additives in gasoline. Due to a computer programming error, the Sacramento terminal’s automatic dispensers allegedly failed to inject additive detergent into a gasoline line. It appears that the resolution of these notices of violation may result in the payment of a civil penalty exceeding $100,000.

 

In November 2008, CARB proposed a civil penalty against Chevron’s Richmond, California, refinery for a notice of violation relating to gasoline that was not properly certified as to composition. The composition certificates for the gasoline were corrected 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 continue. It appears that the resolution of these notices of violation may result in the payment of a civil penalty exceeding $100,000.

 

In July 2009, CARB issued a notice of violation against Chevron Products Company for alleged violations of CARB’s regulations governing the certification of gasoline that occurred during storage at a third-party facility and which had been self-reported by Chevron on discovery. Chevron believes that this matter will not result in the payment of a civil penalty exceeding $100,000.

 

In 2011, CARB made penalty demands with respect to four notices of violation against Chevron for alleged violations of CARB’s fuel blend regulations at certain California terminals and refineries. It appears that the resolution of these notices of violation may result in the payment of a civil penalty exceeding $100,000.

 

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 Chevron undertook to install and operate certain air emission control equipment at its Hawaii Refinery pursuant to a Clean Air Act settlement with the United States Environmental Protection Agency (EPA) and DOH. Chevron has disputed many of the allegations.

 

Chevron has entered into negotiations with the EPA with respect to alleged air quality violations at Chevron’s Perth Amboy, New Jersey refinery identified in a September 16, 2008 Compliance Order issued by the EPA. The alleged violations relate to certain management and reporting requirements set forth in the EPA’s Leak Detection and Repair regulations (these regulations pertain to the control and monitoring of fugitive emissions from refinery process equipment). Based on discussions with the EPA, it appears that the resolution of this matter may result in the payment of a civil penalty exceeding $100,000.

 

The EPA indicated that it would assess Chevron’s Salt Lake City Refinery a civil penalty for alleged violations of federal requirements and Utah’s air pollution laws. These alleged violations were the subject of an August 20, 2008 EPA Notice of Violation (NOV) for which no penalty was assessed at the time. It appears that the resolution of this NOV may result in the payment of a civil penalty exceeding $100,000.

 

The South Coast Air Quality Management District (SCAQMD) issued a NOV to Chevron’s Huntington Beach, California, terminal seeking a civil penalty for alleged violations involving the repair of two holes in the roof of a tank at the terminal. Based on a July 8, 2011, settlement communication with the SCAQMD, it appears that the resolution of this NOV may result in the payment of a civil penalty exceeding $100,000.

Chevron reached a final resolution of an administrative penalty proceeding brought by the Utah Department of Environmental Quality by agreeing to pay the State of Utah a civil penalty of $500,000 as the result of two crude oil releases. The first release occurred in June 2010 and the second occurred in December 2010. In addition, Chevron agreed to pay the State of Utah and the Salt Lake City Corporation $4 million in damages and restoration projects. The public review period passed and the penalty has been paid.

 

 

Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 C.F.R. § 229.104) is included in Exhibit 95 of this Annual Report on Form 10-K.

 

 

The information on Chevron’s 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-20.

 

CHEVRON CORPORATION
ISSUER PURCHASES OF EQUITY SECURITIES

 

 

 

 

The selected financial data for years 2007 through 2011 are presented on page FS-61.

 

 

The index to Management’s Discussion and Analysis of Financial Condition and Results of Operations, Consolidated Financial Statements and Supplementary Data is presented on page FS-1.

 

 

The company’s discussion of interest rate, foreign currency and commodity price market risk is contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations — “Financial and Derivative

Instruments,” beginning on page FS-13 and in Note 10 to the Consolidated Financial Statements, “Financial and Derivative Instruments,” beginning on page FS-36.

 

 

The index to Management’s Discussion and Analysis, Consolidated Financial Statements and Supplementary Data is presented on page FS-1.