Chevron Corporation (CVX, NYSE)
Industry: Oil & Gas Integrated
Annual report, fiscal year 2011


2011 Annual Report






## Contents

2 Letter to Stockholders

4 Chevron Financial Highlights

5 Chevron Operating Highlights

6 Chevron at a Glance

8 Glossary of Energy and Financial Terms

9 Financial Review

68 Five-Year Financial Summary

69 Five-Year Operating Summary
85 Chevron History

86 Board of Directors

87 Corporate Officers

88 Stockholder and Investor Information

On the Cover: Chevron’s $37 billion Gorgon liquefied natural gas (LNG) project offshore Western Australia is one of our largest single investments to date. Shown here are the processing facilities under construction on Barrow Island. First deliveries of LNG are expected in late 2014. Chevron is the largest holder of natural gas resources in Australia.

Marking a Milestone: (below) In 2011, Chevron’s El Segundo, California, refinery celebrated 100 years of operation. Beginning in 1911, when the main product was kerosene for lamps, El Segundo has grown to cover 1,000 acres (405 hectares) and has more than 1,100 miles (1,770 kilometers) of pipelines. It refines about 270,000 barrels of crude oil per day, making El Segundo the largest refinery on the West Coast of the United States.






Access to affordable energy is a primary driver of economic growth and rising living standards. Looking ahead, we see enormous opportunities to continue to deliver that energy. We have an outstanding lineup of major capital projects that are located in some of the world’s most prolific resource basins. And we have an exploration program that is one of the most successful in the industry. We are making long-term investments to develop and deliver the energy the world needs now and in the future, while creating sustained value for our stockholders, our employees and business partners, and the communities where we operate.

The online version of this report contains additional information about our company, as well as videos of our various projects. We invite you to visit our website at: Chevron.com/AnnualReport2011.






# To Our Stockholders

Chevron delivered outstanding financial and operating results in 2011. Even during turbulent economic times, we achieved record earnings, advanced our industry-leading queue of major capital projects to sustain long-term production growth and largely completed the global restructuring of our downstream business. And Chevron once again delivered superior returns for our stockholders.
2011 was a record year for our financial performance. Net income was $26.9 billion on sales and other operating revenues of $244.4 billion, and we delivered a strongly competitive 21.6 percent return on capital employed. We raised our dividend twice in 2011, marking the 24th consecutive year of increases. We generated a total stockholder return of 20.3 percent, leading our peer group in 2011 and over the past five- and 10-year periods.

Our financial performance reflected outstanding operating results. In the upstream, we ranked No. 1 in earnings per barrel relative to our peers. We began initial production of the Platong II natural gas project in Thailand. The Angola liquefied natural gas (LNG) project and Usan deepwater development offshore Nigeria are expected to begin production in 2012. Big Foot and Jack/St. Malo in the U.S. Gulf of Mexico are on schedule to come online in 2014. We also advanced our two world-class LNG projects in Western Australia. Gorgon achieved key construction milestones and is on track for a 2014 startup, and we broke ground on Wheatstone, with a planned startup in 2016.



We expanded our strategic position in natural gas in North America and Europe. Notably in 2011, we closed our acquisition of Atlas Energy in the northeastern United States, drilled our first shale gas wells in Poland and Canada, and completed an agreement to assess shale opportunities in southern China.



We continued to build on our exploration success in 2011. The success rate of our exploration wells was nearly 70 percent, exceeding our 10-year average, which is among the best in our peer group. We added crude oil and natural gas resources through discoveries in six countries and added 1.7 billion barrels of net oil-equivalent proved reserves, replacing 171 percent of production in 2011.

In our global downstream and chemicals business, we ranked No.1 in earnings per barrel in 2011, reflecting a strategic focus on reshaping our global portfolio to improve efficiency, enhance market focus and grow returns. We also ranked No.1 in refinery utilization for the third straight biennial Solomon Associates refinery benchmark study. We advanced work on our Pascagoula Base Oil Plant that, when completed in 2013, will make us the world's leading supplier of premium base oil. We also made progress on the expansion of our Oronite additives plant in Singapore.

Underpinning our operations is a focus on developing new technologies that create business value and competitive advantage. We advanced a breakthrough dual-gradient drilling technology to improve access to deepwater assets and elevate deepwater drilling safety and environmental standards that is on track for initial deployment on the Big Foot project in 2012. In the Partitioned Zone, between Kuwait and Saudi Arabia, we progressed a pilot project to enhance production of heavy oil through industry-leading steamflood technology, building on our success in Indonesia and the San Joaquin Valley in California. We continue to pursue a variety of next-generation technologies with partners that include businesses, universities and national laboratories.



Over the past decade, we’ve gone from trailing the industry in safety to becoming one of its leaders as a result of our broader commitment to operational excellence – the safety of our people, the reliability of our operations and environmental stewardship. To achieve our goal of zero incidents, we have deployed systems and processes that helped drive down injury rates to industry-leading levels. We take pride in what we’ve achieved, but we expect continual improvement in how we manage risk. Even with this emphasis, we are not incident-free. We rigorously investigate all incidents to strengthen our ability to recognize and reduce risk and achieve what we strive for – doing things the right way every time. I am committed to meeting our world-class standards in safety and operational excellence, and I know that the men and women of Chevron join me in that commitment.

Meeting the world’s long-term demand for energy requires significant investments. We move into 2012 with a $32.7 billion capital and exploratory budget. This reflects our confidence in an unparalleled project queue and is supported by our strong financial position and operational performance. Also important to our future are the investments we make in the communities where we operate. Our business generates immense value by creating jobs and supporting local business development. We also make strategic social investments focused on building stronger communities through partnerships in the areas of health, education and economic development. One of our larger social investments in 2011 was a $20 million commitment to eliminate mother-to-child transmission of HIV in Angola, Nigeria and South Africa. All told, we deployed nearly $1 billion in worldwide community investments over the past six years. I encourage you to read more about these investments in our companion publication, the 2011 Corporate Responsibility Report.

Affordable energy underpins economies and generates progress and prosperity. The people of Chevron remain focused on finding and producing affordable energy safely, reliably and efficiently. This is a responsibility that our company takes seriously. We are committed to growing our business, contributing to global economic expansion, building stronger communities and creating enduring value for our stockholders.

Thank you for investing in Chevron.



John S. Watson
Chairman of the Board and
Chief Executive Officer
February 23, 2012



## Chevron Financial Highlights

<table><tr><td>Millions of dollars, except per-share amounts</td><td>2011</td><td>2010</td><td>% Change</td></tr><tr><td>Net income attributable to Chevron Corporation</td><td>$ 26,895</td><td>$ 19,024</td><td>41.4%</td></tr><tr><td>Sales and other operating revenues</td><td>$ 244,371</td><td>$ 198,198</td><td>23.3%</td></tr><tr><td>Noncontrolling interests income</td><td>$ 113</td><td>$ 112</td><td>0.9%</td></tr><tr><td>Interest expense (after tax)</td><td>$ -</td><td>$ 41</td><td>(100.0)%</td></tr><tr><td>Capital and exploratory expenditures*</td><td>$ 29,066</td><td>$ 21,755</td><td>33.6%</td></tr><tr><td>Total assets at year-end</td><td>$ 209,474</td><td>$ 184,769</td><td>13.4%</td></tr><tr><td>Total debt at year-end</td><td>$ 10,152</td><td>$ 11,476</td><td>(11.5)%</td></tr><tr><td>Noncontrolling interests</td><td>$ 799</td><td>$ 730</td><td>9.5%</td></tr><tr><td>Chevron Corporation stockholders&#x27; equity at year-end</td><td>$ 121,382</td><td>$ 105,081</td><td>15.5%</td></tr><tr><td>Cash provided by operating activities</td><td>$ 41,098</td><td>$ 31,359</td><td>31.1%</td></tr><tr><td>Common shares outstanding at year-end (Thousands)</td><td>1,966,999</td><td>1,993,313</td><td>(1.3)%</td></tr><tr><td>Per-share data</td><td></td><td></td><td></td></tr><tr><td>Net income - diluted</td><td>$ 13.44</td><td>$ 9.48</td><td>41.8%</td></tr><tr><td>Cash dividends</td><td>$ 3.09</td><td>$ 2.84</td><td>8.8%</td></tr><tr><td>Chevron Corporation stockholders&#x27; equity</td><td>$ 61.71</td><td>$ 52.72</td><td>17.1%</td></tr><tr><td>Common stock price at year-end</td><td>$ 106.40</td><td>$ 91.25</td><td>16.6%</td></tr><tr><td>Total debt to total debt-plus-equity ratio</td><td>7.7%</td><td>9.8%</td><td></td></tr><tr><td>Return on average stockholders&#x27; equity</td><td>23.8%</td><td>19.3%</td><td></td></tr><tr><td>Return on capital employed (ROCE)</td><td>21.6%</td><td>17.4%</td><td></td></tr></table>

 \( ^{*} \) Includes equity in affiliates



The increase in 2011 was due to higher earnings for both upstream and downstream, as a result of higher prices for crude oil and refined products.



The company’s annual dividend increased for the 24th consecutive year.



The company’s stock price rose 16.6 percent in 2011.



Higher earnings improved Chevron's return on capital employed to 21.6 percent.



## Chevron Operating Highlights \( ^{1} \) 

<table><tr><td></td><td>2011</td><td>2010</td><td>% Change</td></tr><tr><td>Net production of crude oil, condensate and natural gas liquids (Thousands of barrels per day)</td><td>1,849</td><td>1,923</td><td>(3.8) %</td></tr><tr><td>Net production of natural gas (Millions of cubic feet per day)</td><td>4,941</td><td>5,040</td><td>(2.0) %</td></tr><tr><td>Total net oil-equivalent production (Thousands of oil-equivalent barrels per day)</td><td>2,673</td><td>2,763</td><td>(3.3) %</td></tr><tr><td>Refinery input (Thousands of barrels per day)</td><td>1,787</td><td>1,894</td><td>(5.6) %</td></tr><tr><td>Sales of refined products (Thousands of barrels per day)</td><td>2,949</td><td>3,113</td><td>(5.3) %</td></tr><tr><td>Net proved reserves of crude oil, condensate and natural gas liquids \( ^{2} \)  (Millions of barrels)</td><td></td><td></td><td></td></tr><tr><td>- Consolidated companies</td><td>4,295</td><td>4,270</td><td>0.6 %</td></tr><tr><td>- Affiliated companies</td><td>2,160</td><td>2,233</td><td>(3.3) %</td></tr><tr><td>Net proved reserves of natural gas \( ^{2} \)  (Billions of cubic feet)</td><td></td><td></td><td></td></tr><tr><td>- Consolidated companies</td><td>25,229</td><td>20,755</td><td>21.6 %</td></tr><tr><td>- Affiliated companies</td><td>3,454</td><td>3,496</td><td>(1.2) %</td></tr><tr><td>Net proved oil-equivalent reserves \( ^{2} \)  (Millions of barrels)</td><td></td><td></td><td></td></tr><tr><td>- Consolidated companies</td><td>8,500</td><td>7,729</td><td>10.0 %</td></tr><tr><td>- Affiliated companies</td><td>2,736</td><td>2,816</td><td>(2.8) %</td></tr><tr><td>Number of employees at year-end \( ^{3} \)</td><td>57,376</td><td>58,267</td><td>(1.5) %</td></tr></table>

 \( ^{1} \)  Includes equity in affiliates, except number of employees

 \( ^{2} \)  At the end of the year

 \( ^{3} \)  Excludes service station personnel

## Performance Graph

The stock performance graph at right shows how an initial investment of $100 in Chevron stock would have compared with an equal investment in the S&P 500 Index or the Competitor Peer Group. The comparison covers a five-year period beginning December 31, 2006, and ending December 31, 2011, and for the peer group is weighted by market capitalization as of the beginning of each year. It includes the reinvestment of all dividends that an investor would be entitled to receive and is adjusted for stock splits. The interim measurement points show the value of $100 invested on December 31, 2006, as of the end of each year between 2007 and 2011.



<table><tr><td></td><td>2006</td><td>2007</td><td>2008</td><td>2009</td><td>2010</td><td>2011</td></tr><tr><td>Chevron</td><td>100</td><td>130.48</td><td>106.52</td><td>115.15</td><td>141.50</td><td>170.18</td></tr><tr><td>S&amp;P 500</td><td>100</td><td>105.43</td><td>66.42</td><td>83.99</td><td>96.63</td><td>98.68</td></tr><tr><td>Peer Group*</td><td>100</td><td>121.81</td><td>91.49</td><td>94.94</td><td>101.18</td><td>117.79</td></tr></table>

 \( ^{*} \) Peer Group: BP p.l.c.-ADS, ExxonMobil, Royal Dutch Shell-ADR and ConocoPhillips



## Chevron at a Glance

Chevron is one of the world’s leading integrated energy companies and conducts business worldwide. Our success is driven by our people and their commitment to get results the right way – by operating responsibly, executing with excellence, applying innovative technologies and capturing new opportunities for profitable growth. We are involved in virtually every facet of the energy industry. We explore for, produce and transport crude oil and natural gas; refine, market and distribute transportation fuels and lubricants; manufacture and sell petrochemical products; generate power and produce geothermal energy; provide energy efficiency solutions; and develop the energy resources of the future, including research for advanced biofuels.

Photo: Margarida Peliganga,
Health, Environment and Safety
(HES) environment supervisor, and
Gourgiel Neto, HES field specialist,
survey the facilities at Chevron's
Malongo Terminal in Cabinda, Angola.



<table><tr><td>Upstream and Gas</td><td>Exploration and Production Strategy: Grow profitably in core areas and build new legacy positions.</td><td>Upstream explores for and produces crude oil and natural gas. At the end of 2011, worldwide net oil-equivalent proved reserves for consolidated and affiliated companies were 11.24 billion barrels. In 2011, net oil-equivalent production averaged 2.67 million barrels per day. Major producing areas include Angola, Australia, Azerbaijan, Bangladesh, Brazil, Canada, China, Denmark, Indonesia, Kazakhstan, Nigeria, the Partitioned Zone between Kuwait and Saudi Arabia, the Philippines, South America, Thailand, the United Kingdom, the United States, Venezuela, and Vietnam. Major exploration areas include the U.S. Gulf of Mexico and the offshore areas of Western Australia and western Africa. Additional areas include the Gulf of Thailand, South China Sea, and the offshore areas of Brazil, Canada, Liberia, Norway and the United Kingdom. Shale gas exploration areas include Canada, China, Poland, Romania and the United States.</td></tr><tr><td></td><td>Gas and Midstream Strategy: Commercialize our equity gas resource base while growing a high-impact global gas business.</td><td>We are engaged in every aspect of the natural gas business - liquefaction, pipeline and marine transport, marketing and trading, and power generation. Overall, we have more than 160 trillion cubic feet of natural gas unrisked resources, an amount equivalent to approximately 27 billion barrels of crude oil. In North America, Chevron ranks among the top natural gas marketers with sales in 2011 averaging approximately 6 billion cubic feet per day. We own, operate or have an interest in an extensive network of crude oil, refined product, chemical, natural gas liquid and natural gas pipelines. Chevron Shipping Company manages a fleet of 25 vessels, including three new liquefied natural gas carriers that were completed in 2011.</td></tr><tr><td>Downstream and Chemicals</td><td>Strategy: Improve returns and grow earnings across the value chain.</td><td>Downstream and Chemicals includes refining, fuels and lubricants marketing, petrochemicals manufacturing and marketing, supply and trading, and transportation. In 2011, we processed 1.8 million barrels of crude oil per day and averaged 2.9 million barrels per day of refined product sales worldwide. Our most significant areas of operations are the west coast of North America, the U.S. Gulf Coast, Southeast Asia, South Korea, Australia and South Africa. We hold interests in 15 fuel refineries and market transportation fuels and lubricants under the Chevron, Texaco and Caltex brands. Products are sold through a network of 17,830 retail stations, including those of affiliated companies. Our chemicals business includes Chevron Phillips Chemical Company LLC, a 50 percent-owned affiliate that is one of the world&#x27;s leading manufacturers of commodity petrochemicals, and Chevron Oronite Company LLC, which develops, manufactures and markets quality additives that improve the performance of fuels and lubricants.</td></tr><tr><td>Technology</td><td>Strategy: Differentiate performance through technology.</td><td>Our three technology companies - Energy Technology, Technology Ventures and Information Technology - are focused on driving business value in every aspect of our operations. We operate technology centers in Australia, Scotland and in California and Texas in the United States. Together they provide strategic research, technology development, and technical and computing infrastructure services to our global businesses.</td></tr><tr><td>Renewable Energy and Energy Efficiency</td><td>Strategy: Invest in profitable renewable energy and energy efficiency solutions.</td><td>We are the largest producer of geothermal energy in the world, with leading positions in Indonesia and the Philippines. We are involved in developing promising renewable sources of energy, including advanced biofuels from nonfood sources. Our subsidiary Chevron Energy Solutions works with internal and external clients to develop and build sustainable energy projects that increase energy efficiency and reduce costs.</td></tr><tr><td>Operational Excellence</td><td></td><td>The foundation of business success and world-class performance at Chevron is operational excellence, which is defined as the systematic management of process safety, personal safety and health, environment, reliability, and efficiency. Safety is our highest priority. We are committed to attaining world-class standards in operational excellence. We will not be satisfied until we have zero incidents - no one injured.</td></tr></table>



# Glossary of Energy and Financial Terms

## Energy Terms

Additives Specialty chemicals incorporated into fuels and lubricants that enhance the performance of the finished products.

Barrels of oil-equivalent (BOE) A unit of measure to quantify crude oil, natural gas liquids and natural gas amounts using the same basis. Natural gas volumes are converted to barrels on the basis of energy content. See oil-equivalent gas and production.

Biofuel Any fuel that is derived from biomass – recently living organisms or their metabolic byproducts – from sources such as farming, forestry, and biodegradable industrial and municipal waste. See renewables.

Condensate Hydrocarbons that are in a gaseous state at reservoir conditions but condense into liquid as they travel up the wellbore and reach surface conditions.

Development Drilling, construction and related activities following discovery that are necessary to begin production and transportation of crude oil and natural gas.

Enhanced recovery Techniques used to increase or prolong production from crude oil and natural gas fields.

Exploration Searching for crude oil and/or natural gas by utilizing geologic and topographical studies, geophysical and seismic surveys, and drilling of wells.

Gas-to-liquids (GTL) A process that converts natural gas into high-quality transportation fuels and other products.

Greenhouse gases Gases that trap heat in Earth’s atmosphere (e.g., water vapor, ozone, carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride).

Integrated energy company A company engaged in all aspects of the energy industry, including exploring for and producing crude oil and natural gas; refining, marketing and transporting crude oil, natural gas and refined products; manufacturing and distributing petrochemicals; and generating power.

Liquefied natural gas (LNG) Natural gas that is liquefied under extremely cold temperatures to facilitate storage or transportation in specially designed vessels.

Natural gas liquids (NGLs) Separated from natural gas, these include ethane, propane, butane and natural gasoline.

Oil-equivalent gas (OEG) The volume of natural gas needed to generate the equivalent amount of heat as a barrel of crude oil. Approximately 6,000 cubic feet of natural gas is equivalent to one barrel of crude oil.

Oil sands Naturally occurring mixture of bitumen (a heavy, viscous form of crude oil), water, sand and clay. Using hydroprocessing technology, bitumen can be refined to yield synthetic oil.

Petrochemicals Compounds derived from petroleum. These include aromatics, which are used to make plastics, adhesives, synthetic fibers and household detergents; and olefins, which are used to make packaging, plastic pipes, tires, batteries, household detergents and synthetic motor oils.
Price effects on entitlement volumes The impact on Chevron's share of net production and net proved reserves due to changes in crude oil and natural gas prices between periods. Under production-sharing and variable-royalty provisions of certain agreements, price variability can increase or decrease royalty burdens and/or volumes attributable to the company. For example, at higher prices, fewer volumes are required for Chevron to recover its costs under certain production-sharing contracts.

Production Total production refers to all the crude oil (including synthetic oil), natural gas liquids and natural gas produced from a property. Net production is the company’s share of total production after deducting both royalties paid to landowners and a government’s agreed-upon share of production under a production-sharing contract. Oil-equivalent production is the sum of the barrels of liquids and the oil-equivalent barrels of natural gas produced. See barrels of oil-equivalent and oil-equivalent gas.

Production-sharing contract (PSC) An agreement between a government and a contractor (generally an oil and gas company) whereby production is shared between the parties in a prearranged manner. The contractor typically incurs all exploration, development and production costs, which are subsequently recoverable out of an agreed-upon share of any future PSC production, referred to as cost recovery oil and/or gas. Any remaining production, referred to as profit oil and/or gas, is shared between the parties on an agreed-upon basis as stipulated in the PSC. The government also may retain a share of PSC production as a royalty payment, and the contractor may owe income taxes on its portion of the profit oil and/or gas. The contractor’s share of PSC oil and/or gas production and reserves varies over time as it is dependent on prices, costs and specific PSC terms.

Renewables Energy resources that are not depleted when consumed or converted into other forms of energy (e.g., solar, geothermal, ocean and tide, wind, hydroelectric power, biofuels and hydrogen).

Reserves Crude oil and natural gas contained in underground rock formations called reservoirs and saleable hydrocarbons extracted from oil sands, shale, coalfields and other nonrenewable natural resources that are intended to be upgraded into synthetic oil or gas. Net proved reserves are the estimated quantities that geoscience and engineering data demonstrate with reasonable certainty to be economically producible in the future from known reservoirs under existing economic conditions, operating methods and government regulations, and exclude royalties and interests owned by others. Estimates change as additional information becomes available. Oil-equivalent reserves are the sum of the liquids reserves and the oil-equivalent gas reserves. See barrels of oil-equivalent and oil-equivalent gas. The company discloses only net proved reserves in its filings with the U.S. Securities and Exchange Commission. Investors should refer to proved reserves disclosures in Chevron's Annual Report on Form 10-K for the year ended December 31, 2011.

Resources Estimated quantities of oil and gas resources are recorded under Chevron's 6P system, which is modeled after the Society of Petroleum Engineers' Petroleum Resource Management System, and includes quantities classified as proved, probable and possible reserves, plus those that remain contingent on commerciality. Unrisked resources, unrisked resource base and similar terms represent the arithmetic sum of the amounts recorded under each of these classifications. Recoverable resources, potentially recoverable volumes and other similar terms represent estimated remaining quantities that are expected to be ultimately recoverable and produced in the future, adjusted to reflect the relative uncertainty represented by the various classifications. These estimates may change significantly as development work provides additional information. At times, original oil in place and similar terms are used to describe total hydrocarbons contained in a reservoir without regard to the likelihood of their being produced. All of these measures are considered by management in making capital investment and operating decisions and may provide some indication to stockholders of the resource potential of oil and gas properties in which the company has an interest.

Shale gas Natural gas produced from shale (clay-rich, very fine-grained rock) formations where the gas was sourced from within the shale itself and is trapped in rocks with low porosity and extremely low permeability. Production of shale gas requires the use of hydraulic fracturing (pumping a fluid-sand mixture into the formation under high pressure) to help produce the gas.

Synthetic oil A marketable and transportable hydrocarbon liquid, resembling crude oil, that is produced by upgrading highly viscous or solid hydrocarbons, such as extra-heavy crude oil or oil sands.

## Financial Terms

Cash flow from operating activities Cash generated from the company’s businesses; an indicator of a company’s ability to pay dividends and fund capital and common stock repurchase programs. Excludes cash flows related to the company’s financing and investing activities.

Earnings Net income attributable to Chevron Corporation as presented on the Consolidated Statement of Income.

Goodwill An asset representing the future economic benefits arising from the other assets acquired in a business combination that are not individually identified and separately recognized.

Margin The difference between the cost of purchases, producing and/or marketing a product and its sales price.

Return on capital employed (ROCE) Ratio calculated by dividing earnings (adjusted for after-tax interest expense and noncontrolling interests) by the average of total debt, noncontrolling interests and Chevron Corporation stockholders' equity for the year.

Return on stockholders' equity Ratio calculated by dividing earnings by average Chevron Corporation stockholders' equity. Average Chevron Corporation stockholders' equity is computed by averaging the sum of the beginning-of-year and end-of-year balances.

Total stockholder return (TSR) The return to stockholders as measured by stock price appreciation and reinvested dividends for a period of time.



## Financial Table of Contents

## 10

Management’s Discussion and Analysis of Financial Condition and Results of Operations
Key Financial Results 10
Earnings by Major Operating Area 10
Business Environment and Outlook 10
Operating Developments 13
Results of Operations 14
Consolidated Statement of Income 16
Selected Operating Data 18
Liquidity and Capital Resources 18
Financial Ratios 20
Guarantees, Off-Balance-Sheet Arrangements and Contractual Obligations, and Other Contingencies 20
Financial and Derivative Instruments 21
Transactions With Related Parties 22
Litigation and Other Contingencies 22
Environmental Matters 23
Critical Accounting Estimates and Assumptions 24
New Accounting Standards 27
Quarterly Results and Stock Market Data 28

## 29

Consolidated Financial Statements
Report of Management 29
Report of Independent Registered Public Accounting Firm 30
Consolidated Statement of Income 31
Consolidated Statement of Comprehensive Income 32
Consolidated Balance Sheet 33
Consolidated Statement of Cash Flows 34
Consolidated Statement of Equity 35

## 36

Notes to the Consolidated Financial Statements
Note 1 Summary of Significant Accounting Policies 36
Note 2 Acquisition of Atlas Energy, Inc. 38
Note 3 Noncontrolling Interests 39
Note 4 Information Relating to the Consolidated Statement of Cash Flows 39
Note 5 Summarized Financial Data - Chevron U.S.A. Inc. 40
Note 6 Summarized Financial Data - Chevron Transport Corporation Ltd. 41
Note 7 Summarized Financial Data - Tengizchevroil LLP 41
Note 8 Lease Commitments 41
Note 9 Fair Value Measurements 42
Note 10 Financial and Derivative Instruments 44
Note 11 Operating Segments and Geographic Data 45
Note 12 Investments and Advances 47
Note 13 Properties, Plant and Equipment 49
Note 14 Litigation 49
Note 15 Taxes 51
Note 16 Short-Term Debt 54
Note 17 Long-Term Debt 54
Note 18 New Accounting Standards 55
Note 19 Accounting for Suspended Exploratory Wells 55
Note 20 Stock Options and Other Share-Based Compensation 56
Note 21 Employee Benefit Plans 57
Note 22 Equity 63
Note 23 Restructuring and Reorganization 63
Note 24 Other Contingencies and Commitments 64
Note 25 Asset Retirement Obligations 66
Note 26 Other Financial Information 66
Note 27 Earnings Per Share 67

Five-Year Financial Summary 68
Five-Year Operating Summary 69
Supplemental Information on Oil and Gas Producing Activities 70

## 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 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. 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.



## Key Financial Results

<table><tr><td>Millions of dollars, except per-share amounts</td><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Net Income Attributable to Chevron Corporation</td><td>$ 26,895</td><td>$ 19,024</td><td>$ 10,483</td></tr><tr><td>Per Share Amounts:</td><td></td><td></td><td></td></tr><tr><td>Net Income Attributable to Chevron Corporation</td><td></td><td></td><td></td></tr><tr><td>- Basic</td><td>$ 13.54</td><td>$ 9.53</td><td>$ 5.26</td></tr><tr><td>- Diluted</td><td>$ 13.44</td><td>$ 9.48</td><td>$ 5.24</td></tr><tr><td>Dividends</td><td>$ 3.09</td><td>$ 2.84</td><td>$ 2.66</td></tr><tr><td>Sales and Other Operating Revenues</td><td>$ 244,371</td><td>$ 198,198</td><td>$ 167,402</td></tr><tr><td>Return on:</td><td></td><td></td><td></td></tr><tr><td>Capital Employed</td><td>21.6%</td><td>17.4%</td><td>10.6%</td></tr><tr><td>Stockholders&#x27; Equity</td><td>23.8%</td><td>19.3%</td><td>11.7%</td></tr></table>

## Earnings by Major Operating Area

<table><tr><td>Millions of dollars</td><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Upstream \( ^{1} \)</td><td></td><td></td><td></td></tr><tr><td>United States</td><td>$ 6,512</td><td>$ 4,122</td><td>$ 2,262</td></tr><tr><td>International</td><td>18,274</td><td>13,555</td><td>8,670</td></tr><tr><td>Total Upstream</td><td>24,786</td><td>17,677</td><td>10,932</td></tr><tr><td>Downstream \( ^{1} \)</td><td></td><td></td><td></td></tr><tr><td>United States</td><td>1,506</td><td>1,339</td><td>(121)</td></tr><tr><td>International</td><td>2,085</td><td>1,139</td><td>594</td></tr><tr><td>Total Downstream</td><td>3,591</td><td>2,478</td><td>473</td></tr><tr><td>All Other</td><td>(1,482)</td><td>(1,131)</td><td>(922)</td></tr><tr><td>Net Income Attributable to Chevron Corporation \( ^{2,3} \)</td><td>$ 26,895</td><td>$ 19,024</td><td>$ 10,483</td></tr></table>

 \( ^{1} $  2009 information has been revised to conform with the 2011 and 2010 segment

presentation.

 \( ^{2} \)  Includes foreign currency effects: $ 121 $ (423) $ (744)

 \( ^{3} \)  Also referred to as “earnings” in the discussions that follow.

Refer to the “Results of Operations” section beginning on page 14 for a discussion of financial results by major operating area for the three years ended December 31, 2011.

## Business Environment and Outlook

Chevron is a global energy company with substantial business activities in the following countries: Angola, Argentina, Australia, Azerbaijan, Bangladesh, Brazil, Cambodia, Canada, Chad, China, Colombia, Democratic Republic of the Congo, Denmark, Indonesia, Kazakhstan, Myanmar, the Netherlands, Nigeria, Norway, the Partitioned Zone between Saudi Arabia and Kuwait, the Philippines, Republic of the Congo, Singapore, South Africa, South Korea, Thailand, Trinidad and Tobago, the United Kingdom, the United States, Venezuela and Vietnam.

Earnings of the company depend mostly on the profitability of its upstream and downstream business segments. The single biggest factor that affects the results of operations for the company is movement in the price of crude oil. In the downstream business, crude oil is the largest cost component of refined products. Seasonality is not a primary driver of changes in the company’s quarterly earnings during the year.

To sustain its long-term competitive position in the upstream business, the company must develop and replenish an inventory of projects that offer attractive financial returns for the investment required. Identifying promising areas for exploration, acquiring the necessary rights to explore for and to produce crude oil and natural gas, drilling successfully, and handling the many technical and operational details in a safe and cost-effective manner are all important factors in this effort. Projects often require long lead times and large capital commitments.

The company’s operations, especially upstream, can also be affected by changing economic, regulatory and political environments in the various countries in which it operates, including the United States. From time to time, certain governments have sought to renegotiate contracts or impose additional costs on the company. Governments may attempt to do so in the future. Civil unrest, acts of violence or strained relations between a government and the company or other governments may impact the company’s operations or investments. Those developments have at times significantly affected the company’s operations and results and are carefully considered by management when evaluating the level of current and future activity in such countries.

The company also continually evaluates opportunities to dispose of assets that are not expected to provide sufficient long-term value or to acquire assets or operations complementary to its asset base to help augment the company’s financial performance and growth. Refer to the “Results of Operations” section beginning on page 14 for discussions of net gains on asset sales during 2011. Asset dispositions and restructurings may also occur in future periods and could result in significant gains or losses.

The company closely monitors developments in the financial and credit markets, the level of worldwide economic activity, and the implications for the company of movements in prices for crude oil and natural gas. Management takes these developments into account in the conduct of daily operations and for business planning.

Comments related to earnings trends for the company’s major business areas are as follows:

Upstream Earnings for the upstream segment are closely aligned with industry price levels for crude oil and natural gas. Crude oil and natural gas prices are subject to external factors over which the company has no control, including product demand connected with global economic conditions, industry inventory levels, production quotas imposed by the Organization of Petroleum Exporting Countries (OPEC), weather-related damage and disruptions, competing fuel prices, and regional supply interruptions or fears thereof that



may be caused by military conflicts, civil unrest or political uncertainty. Any of these factors could also inhibit the company’s production capacity in an affected region. The company monitors developments closely in the countries in which it operates and holds investments, and seeks to manage risks in operating its facilities and businesses. The longer-term trend in earnings for the upstream segment is also a function of other factors, including the company’s ability to find or acquire and efficiently produce crude oil and natural gas, changes in fiscal terms of contracts, and changes in tax laws and regulations.

The company continues to actively manage its schedule of work, contracting, procurement and supply-chain activities to effectively manage costs. However, price levels for capital and exploratory costs and operating expenses associated with the production of crude oil and natural gas can be subject to external factors beyond the company’s control. External factors include not only the general level of inflation, but also commodity prices and prices charged by the industry’s material and service providers, which can be affected by the volatility of the industry’s own supply-and-demand conditions for such materials and services. Capital and exploratory expenditures and operating expenses can also be affected by damage to production facilities caused by severe weather or civil unrest.

WTI Crude Oil, Brent Crude Oil and Henry Hub Natural Gas Spot Prices – Quarterly Average



The chart above shows the trend in benchmark prices for West Texas Intermediate (WTI) crude oil, Brent crude oil and U.S. Henry Hub natural gas. The WTI price averaged $95 per barrel for the full-year 2011, compared to $79 in 2010. As of mid-February 2012, the WTI price was about $99 per barrel. The Brent price averaged $111 per barrel for the full-year 2011, compared to $80 in 2010. As of mid-February 2012, the Brent price was about $118 per barrel. The majority of the company’s equity crude production is priced based on the Brent benchmark. WTI traded at a discount to Brent throughout 2011 due to excess crude supply in the U.S. Midcontinent market. The discount narrowed in fourth quarter 2011 as crude inventories declined.

A differential in crude oil prices exists between high quality (high-gravity, low-sulfur) crudes and those of lower quality (low-gravity, high-sulfur). The amount of the differential in any period is associated with the supply of heavy crude available versus the demand, which is a function of the capacity of refineries that are able to process this lower quality feedstock into light products (motor gasoline, jet fuel, aviation gasoline and diesel fuel). The differential widened during 2011 primarily due to rising diesel prices and lower availability of light, sweet crude oil due to supply disruptions in Libya.

Chevron produces or shares in the production of heavy crude oil in California, Chad, Indonesia, the Partitioned Zone between Saudi Arabia and Kuwait, Venezuela and in certain fields in Angola, China and the United Kingdom sector of the North Sea. (See page 18 for the company’s average U.S. and international crude oil realizations.)

In contrast to price movements in the global market for crude oil, price changes for natural gas in many regional markets are more closely aligned with supply-and-demand conditions in those markets. In the United States, prices at Henry Hub averaged about $4.00 per thousand cubic feet (MCF) during 2011, compared with about $4.50 during 2010. As of mid-February 2012, the Henry Hub spot price was about $2.50 per MCF. Fluctuations in the price for natural gas in the United States are closely associated with customer demand relative to the volumes produced in North America.

Outside the United States, price changes for natural gas depend on a wide range of supply, demand and regulatory circumstances. In some locations, Chevron is investing in long-term projects to install infrastructure to produce and liquefy natural gas for transport by tanker to other markets. International natural gas realizations averaged about $5.40 per MCF during 2011, compared with about $4.60 per MCF during 2010. (See page 18 for the company’s average natural gas realizations for the U.S. and international regions.)

Net Liquids Production*
Thousands of barrels per day



United States
International

Net liquids production decreased 4 percent in 2011 mainly due to field declines and maintenance-related downtime in the United States and lower entitlement volumes in Indonesia and Kazakhstan.

 \( ^{*} \) Includes equity in affiliates.

Net Natural Gas Production*
Millions of cubic feet per day



United States
International

Net natural gas production decreased 2 percent in 2011 mainly due to field declines in the United States, Denmark and the United Kingdom. Partially offsetting the declines were increases in Bangladesh, Nigeria and new Marcellus Shale production.

 \( ^{*} \) Includes equity in affiliates.



The company’s worldwide net oil-equivalent production in 2011 averaged 2.673 million barrels per day. About one-fifth of the company’s net oil-equivalent production in 2011 occurred in the OPEC-member countries of Angola, Nigeria, Venezuela and the Partitioned Zone between Saudi Arabia and Kuwait. OPEC quotas had no effect on the company’s net crude oil production in 2011 or 2010. At their December 2011 meeting, members of OPEC supported maintaining the current production level of 30 million barrels per day and made no change to the production quotas in effect since December 2008.

The company estimates that oil-equivalent production in 2012 will average approximately 2.680 million barrels per day based on the average Brent price of $111 per barrel for the full-year 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. Investments in upstream projects generally begin well in advance of the start of the associated crude oil and natural gas production. A significant majority of Chevron’s upstream investment is made outside the United States.

Refer to the “Results of Operations” section on pages 14 through 15 for additional discussion of the company’s upstream business.

Refer to Table V beginning on page 75 for a tabulation of the company’s proved net oil and gas reserves by geographic area at the beginning of 2009 and each year-end from 2009 through 2011, and an accompanying discussion of major changes to proved reserves by geographic area for the three-year period ending December 31, 2011.

In early November 2011, while drilling a development well in the deepwater Frade Field in Brazil, an unanticipated pressure spike caused oil to migrate from the well bore through a series of fissures to the sea floor, emitting approximately 2,400 barrels of oil. The resulting surface sheen has since dissipated, and there have been no coastal or wildlife impacts. Upon detection, the company immediately took steps to stop the release. Chevron’s emergency plan, approved by the Brazilian environment and natural resources regulatory agency IBAMA, was implemented according to the law and industry standards. The source of the seep was contained within four days. As of December 31, 2011, the financial impact of the incident was not material to the company’s annual net income. However, the company’s ultimate exposure related to fines and penalties is not currently determinable, and could be significant to net income in any one period.

Downstream Earnings for the downstream segment are closely tied to margins on the refining, manufacturing and marketing of products that include gasoline, diesel, jet fuel, lubricants, fuel oil, fuel and lubricant additives, and petrochemicals. Industry margins are sometimes volatile and can be affected by the global and regional supply-and-demand balance for refined products and petrochemicals and by changes in the price of crude oil, other refinery and petrochemical feedstocks, and natural gas. Industry margins can also be influenced by inventory levels, geopolitical events, costs of materials and services, refinery or chemical plant capacity utilization, maintenance programs, and disruptions at refineries or chemical plants resulting from unplanned outages due to severe weather, fires or other operational events.

Other factors affecting profitability for downstream operations include the reliability and efficiency of the company’s refining, marketing and petrochemical assets, the effectiveness of its crude oil and product supply functions, and the volatility of tanker-charter rates for the company’s shipping operations, which are driven by the industry’s demand for crude oil and product tankers. Other factors beyond the company’s control include the general level of inflation and energy costs to operate the company’s refining, marketing and petrochemical assets.

The company’s most significant marketing areas are the West Coast of North America, the U.S. Gulf Coast, Asia and southern Africa. Chevron operates or has significant ownership interests in refineries in each of these areas. In 2011, the company’s margins improved over 2010, supported by higher global product demand and tighter global refined product supplies. The company made further progress during 2011 implementing the previously announced restructuring of its downstream businesses, including the employee-reduction programs for the United States and international operations. Approximately 2,300 employees in the downstream operations are currently expected to be released under these programs. About 2,100 employees have been released through December 31, 2011, with the programs being substantially completed. Substantially all of the remaining employees designated for release under the programs are expected to leave in 2012. About 900 of the affected employees were located in the United States. Refer to Note 23 of the Consolidated Financial Statements, on pages 63 through 64, for further discussion.



The company progressed its ongoing effort to concentrate downstream resources and capital on strategic assets. On August 1, 2011, the company completed the sale of its 220,000-barrel-per-day Pembroke Refinery and its fuels marketing and aviation assets in the United Kingdom and Ireland. Through year-end 2011, the company had also completed the sale of 13 U.S. terminals, certain marketing businesses in Africa, LPG storage and distribution operations in China, and its fuels marketing and aviation businesses in 16 countries in the Caribbean and Latin America regions. In 2012, the company also expects to complete the sale of its fuels, finished lubricants and aviation businesses in Spain and certain fuels marketing and aviation businesses in the central Caribbean, pending customary regulatory approvals.

Also in 2011, Caltex Australia Ltd. (CAL), the company’s 50 percent-owned affiliate, initiated a review of its refining operations in Australia, which is ongoing. Upon completion, should the review result in a decision to significantly alter the operational role of CAL’s refineries, Chevron may recognize a loss that could be significant to net income in any one period.

Refer to the “Results of Operations” section on pages 14 through 16 for additional discussion of the company’s downstream operations.

All Other consists of mining operations, power generation businesses, worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, energy services, alternative fuels, and technology companies. In first quarter 2010, employee-reduction programs were announced for the corporate staffs. As of 2011 year-end, 400 employees from the corporate staffs were released under the programs. Refer to Note 23 of the Consolidated Financial Statements, beginning on page 63, for further discussion.

## Operating Developments

Key operating developments and other events during 2011 and early 2012 included the following:

## Upstream

Australia Chevron and its joint-venture partners reached the final investment decision to proceed with development of the Wheatstone Project. Construction started in late 2011. Chevron holds a 72.1 percent interest in the foundation natural gas processing facilities, which are located at Ashburton North, along the northwest coast of Australia. The company plans to supply natural gas to the foundation project from the Chevron-operated and 90.2 percent-owned Wheatstone and Iago fields. The LNG facilities will also be a destination for third-party natural gas.

Through the end of 2011, Chevron has signed binding Sales and Purchase Agreements 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 sales to 85 to 90 percent of Chevron’s net LNG off-take and to sell down equity.

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

Kazakhstan/Russia
During 2011, the Caspian Pipeline Consortium began construction on a project to increase the pipeline design capacity by 670,000 barrels per day. 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.

## Nigeria In December

2011, a final investment decision was reached to develop the 40 percent-owned and operated Sonam natural gas field in the Escravos area. The project is designed to deliver 215 million cubic feet of natural gas per day to the domestic market and produce 30,000 barrels of liquids per day.

Thailand In October 2011, the 69.9 percent-owned and operated Platong II natural gas project commenced production. The project ramped up to total average daily production of 377 million cubic feet of natural gas and 11,000 barrels of condensate as of the end of 2011.

United Kingdom In fourth quarter 2011, the company reached a final investment decision for the Clair Ridge Project, located west of the Shetland Islands. Chevron has a 19.4 percent nonoperated working interest in the project.

United States In fourth quarter 2011, a final investment decision was made for the Tubular Bells project in the deepwater Gulf of Mexico. The development includes a 42.9 percent nonoperated working interest in the Tubular Bells unitized area.

Drilling operations at the 43.8 percent-owned and operated Moccasin prospect resulted in a new discovery of crude oil. The company also drilled a successful appraisal well at the 55 percent-owned Buckskin prospect. Both prospects are in the deepwater Gulf of Mexico.

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.

## Downstream

Africa During 2011, the company completed the sale of certain marketing businesses in five countries in Africa.

Caribbean and Latin America In 2011, the company completed the sale of its fuels marketing and aviation businesses in 16 countries in the Caribbean and Latin America. In fourth quarter 2011, the company signed agreements to sell certain fuels marketing and aviation businesses in the Central Caribbean. The company expects to complete these sales in 2012 following receipt of required local regulatory and government approvals.

Europe In August 2011, the company completed the sale of its refining and marketing assets in the United Kingdom and Ireland, including the Pembroke Refinery.

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

United States In January 2011, the company announced the final investment decision on a $1.4 billion project to construct a base oil manufacturing facility at the Pascagoula, Mississippi, refinery. The facility is expected to produce approximately 25,000 barrels per day of premium base oil.

## Other

Common Stock Dividends The quarterly common stock dividend increased by 8.3 percent in April 2011 and by 3.8 percent in October 2011, to $0.81 per common share, making 2011 the 24th consecutive year that the company increased its annual dividend payment.

Common Stock Repurchase Program The company purchased $4.25 billion of its common stock in 2011 under its share repurchase program. The program began in 2010 and has no set term or monetary limits.

## Results of Operations

Major Operating Areas The following section presents the results of operations for the company’s business segments – Upstream and Downstream – as well as for “All Other.” Earnings are also presented for the U.S. and international geographic areas of the Upstream and Downstream business segments. Refer to Note 11, beginning on page 45, for a discussion of the company’s “reportable segments,” as defined in accounting standards for segment reporting (Accounting Standards Codification (ASC) 280). This section should also be read in conjunction with the discussion in “Business Environment and Outlook” on pages 10 through 13.

U.S. Upstream

<table><tr><td>Millions of dollars</td><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Earnings</td><td>$ 6,512</td><td>$ 4,122</td><td>$ 2,262</td></tr></table>

U.S. upstream earnings of $6.51 billion in 2011 increased $2.4 billion from 2010. The benefit of higher crude oil realizations increased earnings by $2.8 billion between periods. Partly offsetting this effect were lower net oil-equivalent production which decreased earnings by about $400 million and higher operating expenses of $200 million.

U.S. upstream earnings of $4.1 billion in 2010 increased $1.9 billion from 2009. Higher prices for crude oil and natural gas increased earnings by $2.1 billion between periods. Partly offsetting these effects were higher operating expenses of $200 million, in part due to the Gulf of Mexico drilling moratorium. Lower exploration expenses were essentially offset by higher tax items and higher depreciation expenses.

The company’s average realization for U.S. crude oil and natural gas liquids in 2011 was $97.51 per barrel, compared with $71.59 in 2010 and $54.36 in 2009. The average natural gas realization was $4.04 per thousand cubic feet in 2011, compared with $4.26 and $3.73 in 2010 and 2009, respectively.

Net oil-equivalent production in 2011 averaged 678,000 barrels per day, down 4 percent from 2010 and 5 percent from 2009. Between 2011 and 2010, the decrease in production was associated with normal field declines and maintenance-related downtime. Partially offsetting this decrease were new production from acquisitions in the Marcellus Shale and increases at the Perdido project in the Gulf of Mexico. Natural field declines between 2010 and 2009 were








mostly offset by increased production from the Tahiti Field. The net liquids component of oil-equivalent production for 2011 averaged 465,000 barrels per day, down 5 percent from 2010 and 4 percent from 2009. Net natural gas production averaged about 1.3 billion cubic feet per day in 2011, down approximately 3 percent from 2010 and about 9 percent from 2009. Refer to the “Selected Operating Data” table on page 18 for a three-year comparative of production volumes in the United States.

International Upstream

<table><tr><td>Millions of dollars</td><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Earnings \( ^{*} \)</td><td>$ 18,274</td><td>$ 13,555</td><td>$ 8,670</td></tr><tr><td>*Includes foreign currency effects:</td><td>$ 211</td><td>$ (293)</td><td>$ (578)</td></tr></table>

International upstream earnings of $18.3 billion in 2011 increased $4.7 billion from 2010. Higher prices for crude oil increased earnings by $7.1 billion. This benefit was partly offset by higher tax items of about $1.7 billion and higher operating expenses, including fuel, of about $1.0 billion. Foreign currency effects increased earnings by $211 million in 2011, compared with a decrease of $293 million a year earlier.

Earnings of $13.6 billion in 2010 increased $4.9 billion from 2009. Higher prices for crude oil and natural gas increased earnings by $4.3 billion, and an increase in net oil-equivalent production in the 2010 period benefited income by about $1.2 billion. This net benefit was partly offset by higher operating expenses of $500 million. A favorable change in tax items of about $450 million was mostly offset by higher depreciation expenses. The 2009 period included gains of about $500 million on asset sales and tax items related to the Gorgon Project in Australia. Foreign currency effects decreased earnings by $293 million in the 2010 period, compared with a reduction of $578 million a year earlier, primarily reflecting noncash losses on balance sheet remeasurement.

The company’s average realization for international crude oil and natural gas liquids in 2011 was $101.53 per barrel, compared with $72.68 in 2010 and $55.97 in 2009. The average natural gas realization was $5.39 per thousand cubic feet in 2011, compared with $4.64 and $4.01 in 2010 and 2009, respectively.

International net oil-equivalent production of 2.0 million barrels per day in 2011 decreased about 3 percent from 2010 and remained relatively flat with 2009. The volumes in 2011 and 2010 include synthetic oil that was reported in 2009 as production from oil sands in Canada. Absent price effects on entitlement volumes, net oil-equivalent production decreased 1 percent in 2011 and increased 5 percent in 2010, when compared with the prior year’s production.

The net liquids component of international oil-equivalent production was about 1.4 million barrels per day in 2011, a decrease of approximately 3 percent from 2010 and an increase of approximately 2 percent from 2009. International net natural gas production of 3.7 billion cubic feet per day in 2011 was down 2 percent from 2010 and up 2 percent from 2009.
Refer to the “Selected Operating Data” table, on page 18, for a three-year comparative of international production volumes.

U.S. Downstream

<table><tr><td>Millions of dollars</td><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Earnings</td><td>$ 1,506</td><td>$ 1,339</td><td>$ (121)</td></tr></table>

U.S. downstream operations earned $1.5 billion in 2011, compared with $1.3 billion in 2010. Earnings benefited by $300 million from improved margins on refined products, $200 million from higher earnings from the 50 percent-owned Chevron Phillips Chemical Company LLC (CPChem), and $50 million from the absence of 2010 charges related to employee reductions. These benefits were partly offset by the absence of a $400 million gain on the sale of the company’s ownership interest in the Colonial Pipeline Company recognized in 2010.

Earnings increased $1.5 billion in 2010 from 2009. Improved margins on refined products increased earnings by about $550 million. Also contributing to the increase was the nearly $400 million gain on the sale of the company’s ownership interest in the Colonial Pipeline Company. Higher earnings from chemicals operations increased earnings by about $300 million, largely from improved margins at CPChem.

Refined product sales of 1.26 million barrels per day in 2011 declined 7 percent, mainly due to lower gasoline, gas oil, and kerosene sales. Sales volumes of refined products were 1.35 million barrels per day in 2010, a decrease of 4 percent from 2009. The decline was mainly in gasoline and jet fuel sales. U.S. branded gasoline sales decreased to 514,000 barrels per day in 2011, representing approximately 10 percent and 17 percent declines from 2010 and 2009, respectively. The decline in 2011, relative to 2010 and 2009, was primarily



Downstream earnings increased 45 percent from 2010 due to higher margins on the sale of refined products, gains on asset sales and higher earnings from CPChem.

 \( ^{*} \) Includes equity in affiliates.






due to weaker demand and previously completed exits from selected eastern U.S. retail markets.

Refer to the “Selected Operating Data” table on page 18 for a three-year comparison of sales volumes of gasoline and other refined products and refinery input volumes.

International Downstream

<table><tr><td>Millions of dollars</td><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Earnings \( ^{*} \)</td><td>2,085</td><td>1,139</td><td>594</td></tr><tr><td>*Includes foreign currency effects:</td><td>(65)</td><td>(135)</td><td>(191)</td></tr></table>

International downstream earned $2.1 billion in 2011, compared with $1.1 billion in 2010. Gains on asset sales benefited earnings by $700 million, primarily from the sale of the Pembroke Refinery and related marketing assets in the United Kingdom and Ireland. Also contributing to earnings were improved margins of $200 million and the absence of 2010 charges of $90 million related to employee reductions. These benefits were partly offset by unfavorable mark-to-market effects of derivative instruments of about $180 million. Foreign currency effects decreased earnings by $65 million in 2011, compared with a decrease of $135 million a year earlier.

Earnings of $1.1 billion in 2010 increased $545 million from 2009. Higher margins on the manufacture and sale of gasoline and other refined products increased earnings by about $1.0 billion, and a favorable swing in mark-to-market



Gasoline
Jet Fuel
Gas Oils & Kerosene
Residual Fuel Oil
Other

Sales volumes of refined products were down 4 percent from 2010 mainly due to asset sales in the United Kingdom and Ireland.

 \( ^{*} \) Includes equity in affiliates.

effects on derivative instruments benefited earnings by about $300 million. Partially offsetting these items was the absence of 2009 gains on asset sales of about $550 million and higher expenses of about $200 million, primarily related to employee reductions and transportation costs. Foreign currency effects reduced earnings by $135 million in 2010, compared with a reduction of $191 million in 2009.

Total refined product sales of 1.69 million barrels per day in 2011 declined 4 percent, primarily due to the sale of the company’s refining and marketing assets in the United Kingdom and Ireland. Excluding the impact of 2011 asset sales, sales volumes were up 3 percent between the comparative periods. International refined product sales volumes of 1.76 million barrels per day in 2010 were 5 percent lower than in 2009, mainly due to asset sales in certain countries in Africa and Latin America.

Refer to the “Selected Operating Data” table, on page 18, for a three-year comparison of sales volumes of gasoline and other refined products and refinery input volumes.

All Other

<table><tr><td>Millions of dollars</td><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Net charges \( ^{*} \)</td><td>(1,482)</td><td>(1,131)</td><td>(922)</td></tr><tr><td>*Includes foreign currency effects:</td><td>(25)</td><td>5</td><td>25</td></tr></table>

All Other includes mining operations, power generation businesses, worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, energy services, alternative fuels, and technology companies.

Net charges in 2011 increased $351 million from 2010, mainly due to higher expenses for employee compensation and benefits, and higher net corporate tax expenses.

Net charges in 2010 increased $209 million from 2009, mainly due to higher expenses for employee compensation and benefits, and higher corporate tax expenses, partly offset by lower provisions for environmental remediation at sites that previously had been closed or sold.

## Consolidated Statement of Income

Comparative amounts for certain income statement categories are shown below:

<table><tr><td>Millions of dollars</td><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Sales and other operating revenues</td><td>$ 244,371</td><td>$ 198,198</td><td>$ 167,402</td></tr></table>

Sales and other operating revenues increased in 2011, mainly due to higher prices for crude oil and refined products. Higher 2010 prices resulted in increased revenues compared with 2009.

<table><tr><td>Millions of dollars</td><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Income from equity affiliates</td><td>$ 7,363</td><td>$ 5,637</td><td>$ 3,316</td></tr></table>

Income from equity affiliates increased in 2011 from 2010 mainly due to higher upstream-related earnings from Tengizchevroil (TCO) in Kazakhstan as a result of higher prices for crude oil. Downstream-related earnings were also higher between the comparative periods, primarily due to higher earnings from CPChem as a result of higher margins on sales of commodity chemicals.

Income from equity affiliates increased in 2010 from 2009 largely due to higher upstream-related earnings from



TCO in Kazakhstan and Petropiar in Venezuela, principally related to higher prices for crude oil and increased crude oil production. Downstream-related affiliate earnings were also higher between the comparative periods, primarily due to higher earnings from CPChem, as a result of higher margins on sales of commodity chemicals. Improved margins on refined products and a favorable swing in foreign currency effects at GS Caltex in South Korea also contributed to the increase in downstream affiliate earnings in the 2010 period. Refer to Note 12, beginning on page 47, for a discussion of Chevron’s investments in affiliated companies.

<table><tr><td>Millions of dollars</td><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Other income</td><td>$ 1,972</td><td>$ 1,093</td><td>$ 918</td></tr></table>

Other income of $2.0 billion in 2011 included net gains of approximately $1.5 billion on asset sales. Other income in both 2010 and 2009 included net gains from asset sales of $1.1 billion and $1.3 billion, respectively. Interest income was approximately $145 million in 2011, $120 million in 2010 and $95 million in 2009. Foreign currency effects increased other income by $103 million in 2011, while decreasing other income by $251 million and $466 million in 2010 and 2009, respectively.

<table><tr><td>Millions of dollars</td><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Purchased crude oil and products</td><td>$ 149,923</td><td>$ 116,467</td><td>$ 99,653</td></tr></table>

Crude oil and product purchases in 2011 and 2010 increased by $33.5 billion and $16.8 billion from prior years due to higher prices for crude oil, natural gas and refined products.

<table><tr><td>Millions of dollars</td><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Operating, selling, general and administrative expenses</td><td>$ 26,394</td><td>$ 23,955</td><td>$ 22,384</td></tr></table>

Operating, selling, general and administrative expenses increased $2.4 billion between 2011 and 2010. This increase was primarily related to higher fuel expenses of $1.5 billion and higher employee compensation and benefits of $700 million. In part, increased fuel purchases reflected a new commercial arrangement that replaced a prior product exchange agreement for upstream operations in Indonesia.

Total expenses in 2010 were about $1.6 billion higher than 2009, primarily due to $600 million of higher fuel expenses; $500 million for employee compensation and benefits; $200 million of increased construction, repair and maintenance expense; and an increase of about $200 million associated with higher tanker charter rates. In addition, charges of $234 million related to employee reductions were included in the 2010 period.

<table><tr><td>Millions of dollars</td><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Exploration expense</td><td>$ 1,216</td><td>$ 1,147</td><td>$ 1,342</td></tr></table>

Exploration expenses in 2011 increased from 2010 mainly due to higher geological and geophysical costs, partly offset by lower well write-offs.

Exploration expenses in 2010 declined from 2009 mainly due to lower amounts for geological and geophysical costs and well write-offs.

<table><tr><td>Millions of dollars</td><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Depreciation, depletion and amortization</td><td>$ 12,911</td><td>$ 13,063</td><td>$ 12,110</td></tr></table>

The decrease in 2011 from 2010 mainly reflected lower production levels and the sale of the Pembroke Refinery, partially offset by higher depreciation rates for certain oil and gas producing fields. The increase in 2010 from 2009 was largely due to higher depreciation rates and higher production for certain oil and gas fields, partly offset by lower impairments.

<table><tr><td>Millions of dollars</td><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Taxes other than on income</td><td>$ 15,628</td><td>$ 18,191</td><td>$ 17,591</td></tr></table>

Taxes other than on income decreased in 2011 from 2010 primarily due to lower import duties in the United Kingdom reflecting the sale of the Pembroke Refinery and other downstream assets, partly offset by higher excise taxes in the company’s South Africa downstream operations. Taxes other than on income increased in 2010 from 2009 mainly due to higher excise taxes in Canada and the United Kingdom.

<table><tr><td>Millions of dollars</td><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Interest and debt expense</td><td>$ -</td><td>$ 50</td><td>$ 28</td></tr></table>

Interest and debt expense, net of capitalized interest, decreased in 2011 from 2010 due to lower average effective interest rates. The increase in 2010 from 2009 was primarily due to slightly higher average effective interest rates.

<table><tr><td>Millions of dollars</td><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Income tax expense</td><td>$ 20,626</td><td>$ 12,919</td><td>$ 7,965</td></tr></table>

Effective income tax rates were 43 percent in 2011, 40 percent in 2010 and 43 percent in 2009. The rate was higher in 2011 than in 2010 primarily due to higher effective tax rates in certain international upstream jurisdictions. The higher international upstream effective tax rates were driven primarily by lower utilization of non-U.S. tax credits in 2011 and the effect of changes in income tax rates between periods, which were partially offset by foreign currency remeasurement impacts. The rate was lower in 2010 than in 2009 primarily due to international upstream effects, including an increased utilization of tax credits, which had a greater impact on the rate than one-time deferred tax benefits and relatively low tax rates on asset sales in 2009. Also, a smaller portion of company income was earned in higher tax rate international upstream jurisdictions in 2010 than in 2009. Finally, foreign currency remeasurement impacts caused a reduction in the effective tax rate between periods.



Selected Operating Data \( ^{1,2} \) 

<table><tr><td></td><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>U.S. Upstream</td><td></td><td></td><td></td></tr><tr><td>Net Crude Oil and Natural Gas</td><td></td><td></td><td></td></tr><tr><td>Liquids Production (MBPD)</td><td>465</td><td>489</td><td>484</td></tr><tr><td>Net Natural Gas Production (MMCFFD) \( ^{3} \)</td><td>1,279</td><td>1,314</td><td>1,399</td></tr><tr><td>Net Oil-Equivalent Production (MBOEPD)</td><td>678</td><td>708</td><td>717</td></tr><tr><td>Sales of Natural Gas (MMCFFD)</td><td>5,836</td><td>5,932</td><td>5,901</td></tr><tr><td>Sales of Natural Gas Liquids (MBPD)</td><td>15</td><td>22</td><td>17</td></tr><tr><td>Revenues From Net Production</td><td></td><td></td><td></td></tr><tr><td>Liquids (B/Bbl)</td><td>$ 97.51</td><td>$ 71.59</td><td>$ 54.36</td></tr><tr><td>Natural Gas (B/MCF)</td><td>$ 4.04</td><td>$ 4.26</td><td>$ 3.73</td></tr><tr><td>International Upstream</td><td></td><td></td><td></td></tr><tr><td>Net Crude Oil and Natural Gas</td><td></td><td></td><td></td></tr><tr><td>Liquids Production (MBPD) \( ^{4} \)</td><td>1,384</td><td>1,434</td><td>1,362</td></tr><tr><td>Net Natural Gas Production (MMCFFD) \( ^{3} \)</td><td>3,662</td><td>3,726</td><td>3,590</td></tr><tr><td>Net Oil-Equivalent Production (MBOEPD) \( ^{5} \)</td><td>1,995</td><td>2,055</td><td>1,987</td></tr><tr><td>Sales of Natural Gas (MMCFFD)</td><td>4,361</td><td>4,493</td><td>4,062</td></tr><tr><td>Sales of Natural Gas Liquids (MBPD)</td><td>24</td><td>27</td><td>23</td></tr><tr><td>Revenues From Liftings</td><td></td><td></td><td></td></tr><tr><td>Liquids (B/Bbl)</td><td>$101.53</td><td>$ 72.68</td><td>$ 55.97</td></tr><tr><td>Natural Gas (B/MCF)</td><td>$ 5.39</td><td>$ 4.64</td><td>$ 4.01</td></tr><tr><td>Worldwide Upstream</td><td></td><td></td><td></td></tr><tr><td>Net Oil-Equivalent Production (MBOEPD) \( ^{3,5} \)</td><td></td><td></td><td></td></tr><tr><td>United States</td><td>678</td><td>708</td><td>717</td></tr><tr><td>International</td><td>1,995</td><td>2,055</td><td>1,987</td></tr><tr><td>Total</td><td>2,673</td><td>2,763</td><td>2,704</td></tr><tr><td>U.S. Downstream</td><td></td><td></td><td></td></tr><tr><td>Gasoline Sales (MBPD) \( ^{6} \)</td><td>649</td><td>700</td><td>720</td></tr><tr><td>Other Refined Product Sales (MBPD)</td><td>608</td><td>649</td><td>683</td></tr><tr><td>Total Refined Product Sales (MBPD)</td><td>1,257</td><td>1,349</td><td>1,403</td></tr><tr><td>Sales of Natural Gas Liquids (MBPD)</td><td>146</td><td>139</td><td>144</td></tr><tr><td>Refinery Input (MBPD)</td><td>854</td><td>890</td><td>899</td></tr><tr><td>International Downstream</td><td></td><td></td><td></td></tr><tr><td>Gasoline Sales (MBPD) \( ^{6} \)</td><td>447</td><td>521</td><td>555</td></tr><tr><td>Other Refined Product Sales (MBPD)</td><td>1,245</td><td>1,243</td><td>1,290</td></tr><tr><td>Total Refined Product Sales (MBPD) \( ^{7} \)</td><td>1,692</td><td>1,764</td><td>1,851</td></tr><tr><td>Sales of Natural Gas Liquids (MBPD)</td><td>63</td><td>78</td><td>88</td></tr><tr><td>Refinery Input (MBPD)</td><td>933</td><td>1,004</td><td>979</td></tr></table>

 \( ^{1} \)  Includes company share of equity affiliates.

 \( ^{2} \)  MBPD – thousands of barrels per day; MMCFFD – millions of cubic feet per day; MBOEPD – thousands of barrels of oil-equivalents per day; Bbl – Barrel; MCF = Thousands of cubic feet. Oil-equivalent gas (OEG) conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of oil.

 \( ^{3} \)  Includes natural gas consumed in operations (MMCFFD):

<table><tr><td>United States</td><td>69</td><td>62</td><td>58</td></tr><tr><td>International</td><td>513</td><td>475</td><td>463</td></tr><tr><td>$ Includes: Canada - synthetic oil</td><td>40</td><td>24</td><td>-</td></tr><tr><td>Venezuela affiliate - synthetic oil</td><td>32</td><td>28</td><td>-</td></tr><tr><td>$ Includes Canada oil sands:</td><td>-</td><td>-</td><td>26</td></tr><tr><td>$ Includes branded and unbranded gasoline.</td><td></td><td></td><td></td></tr><tr><td>$ Includes sales of affiliates (MBPD):</td><td>556</td><td>562</td><td>516</td></tr></table>

## Liquidity and Capital Resources

Cash, cash equivalents, time deposits and marketable securities
Total balances were $20.1 billion and $17.1 billion at December 31, 2011 and 2010, respectively. Cash provided by operating activities in 2011 was $41.1 billion, compared with $31.4 billion in 2010 and $19.4 billion in 2009. Cash provided by operating activities was net of contributions to employee pension plans of approximately $1.5 billion, $1.4 billion and $1.7 billion in 2011, 2010 and 2009, respectively. Cash provided by operating activities during 2011 was more than sufficient to fund the $27.4 billion cash component of the company's capital and exploratory program and pay $6.1 billion of dividends to shareholders. In addition, the company completed the $4.5 billion acquisition of Atlas Energy, Inc., funded from the company's operating cash flows. Cash provided by investing activities included proceeds and deposits related to asset sales of $3.5 billion in 2011, $2.0 billion in 2010, and $2.6 billion in 2009.

Restricted cash of $1.2 billion and $855 million associated with various capital-investment projects, acquisitions pending tax deferred exchanges, and Upstream abandonment activities at December 31, 2011 and 2010, respectively, was invested in short-term marketable securities and recorded as “Deferred charges and other assets” on the Consolidated Balance Sheet.

Dividends Dividends paid to common stockholders were approximately $6.1 billion in 2011, $5.7 billion in 2010 and $5.3 billion in 2009. In October 2011, the company increased its quarterly dividend by 3.8 percent to 81 cents per common share. This followed an increase of 8.3 percent announced in second quarter 2011.



Operating cash flows were approximately $9.7 billion higher than 2010 primarily due to higher crude oil prices.



Total Interest Expense (right scale)
Total Debt (left scale)

Total debt decreased $1.3 billion during 2011 to $10.2 billion. All interest cost was capitalized as part of the cost of major projects.



<table><tr><td rowspan="2">Millions of dollars</td><td colspan="4">2011</td><td colspan="4">2010</td><td>2009</td></tr><tr><td>U.S.</td><td>Int&#x27;l.</td><td>Total</td><td>U.S.</td><td>Int&#x27;l.</td><td>Total</td><td>U. S.</td><td>Int&#x27;l.</td><td>Total</td></tr><tr><td>Upstream \( ^{1} \)</td><td>$ 8,318</td><td>$17,554</td><td>$25,872</td><td>$3,450</td><td>$15,454</td><td>$18,904</td><td>$3,294</td><td>$15,002</td><td>$18,296</td></tr><tr><td>Downstream</td><td>1,461</td><td>1,150</td><td>2,611</td><td>1,456</td><td>1,096</td><td>2,552</td><td>2,087</td><td>1,449</td><td>3,536</td></tr><tr><td>All Other</td><td>575</td><td>8</td><td>583</td><td>286</td><td>13</td><td>299</td><td>402</td><td>3</td><td>405</td></tr><tr><td>Total</td><td>$10,354</td><td>$18,712</td><td>$29,066</td><td>$5,192</td><td>$16,563</td><td>$21,755</td><td>$5,783</td><td>$16,454</td><td>$22,237</td></tr><tr><td>Total, Excluding Equity in Affiliates</td><td>$10,077</td><td>$17,294</td><td>$27,371</td><td>$4,934</td><td>$15,433</td><td>$20,367</td><td>$5,558</td><td>$15,094</td><td>$20,652</td></tr></table>

 \( ^{1} \)  Excludes the acquisition of Atlas Energy, Inc. in 2011.

Debt and capital lease obligations Total debt and capital lease obligations were $10.2 billion at December 31, 2011, down from $11.5 billion at year-end 2010.

The $1.3 billion decrease in total debt and capital lease obligations during 2011 included the early redemption of a $1.5 billion bond due to mature in March 2012. The company’s debt and capital lease obligations due within one year, consisting primarily of commercial paper, redeemable long-term obligations and the current portion of long-term debt, totaled $5.9 billion at December 31, 2011, compared with $5.6 billion at year-end 2010. Of these amounts, $5.6 billion and $5.4 billion were reclassified to long-term at the end of each period, respectively. At year-end 2011, settlement of these obligations was not expected to require the use of working capital in 2012, as the company had the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis.

At December 31, 2011, the company had $6.0 billion in committed credit facilities with various major banks, expiring in December 2016, which enable the refinancing of short-term obligations on a long-term basis. These facilities support commercial paper borrowing and can also be used for general corporate purposes. The company's practice has been to continually replace expiring commitments with new commitments on substantially the same terms, maintaining levels management believes appropriate. Any borrowings under the facilities would be unsecured indebtedness at interest rates based on the London Interbank Offered Rate or an average of base lending rates published by specified banks and on terms reflecting the company's strong credit rating. No borrowings were outstanding under these facilities at December 31, 2011. In addition, the company has an automatic shelf registration statement that expires in March 2013 for an unspecified amount of nonconvertible debt securities issued or guaranteed by the company.

The major debt rating agencies routinely evaluate the company’s debt, and the company’s cost of borrowing can increase or decrease depending on these debt ratings. The company has outstanding public bonds issued by Chevron Corporation, Chevron Corporation Profit Sharing/Savings Plan Trust Fund and Texaco Capital Inc. All of these securities are the obligations of, or guaranteed by, Chevron Corporation and are rated AA by Standard and Poor’s Corporation and Aa1 by Moody’s Investors Service. The company’s U.S. commercial paper is rated A-1+ by Standard and Poor’s and P-1 by Moody’s. All of these ratings denote high-quality, investment-grade securities.

The company’s future debt level is dependent primarily on results of operations, the capital program and cash that may be generated from asset dispositions. Based on its high-quality debt ratings, the company believes that it has substantial borrowing capacity to meet unanticipated cash requirements. The company also can modify capital spending plans during any extended periods of low prices for crude oil and natural gas and narrow margins for refined products and commodity chemicals to provide flexibility to continue paying the common stock dividend and maintain the company’s high-quality debt ratings.

Common stock repurchase program In July 2010, the Board of Directors approved an ongoing share repurchase program with no set term or monetary limits. The company expects to repurchase between $500 million and $2 billion of its common shares per quarter, at prevailing prices, as permitted by securities laws and other legal requirements and subject to market conditions and other factors. During 2011, the company purchased 42.3 million common shares for $4.25 billion. From the inception of the program through 2011, the company had purchased 51.1 million shares for $5.0 billion.

Capital and exploratory expenditures 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 and $1.6 billion, respectively.
Of the $29.1 billion of expenditures in 2011, 89 percent, or $25.9 billion, was related to upstream activities. Approximately 87 percent and 80 percent were expended for upstream operations in 2010 and 2009. 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.

The company estimates that in 2012 capital and exploratory expenditures will be $32.7 billion, including $3.0 billion of spending






by affiliates. Approximately 87 percent of the total, or $28.5 billion, is budgeted for exploration and production activities. Approximately $22.3 billion, or 78 percent, of this amount is for projects outside the United States. Spending in 2012 is primarily focused on major development projects in Angola, Australia, Brazil, Canada, China, Kazakhstan, Nigeria, Russia, the United Kingdom and the U.S. Gulf of Mexico. Also included is funding for enhancing recovery and mitigating natural field declines for currently-producing assets, and for focused exploration and appraisal activities.

Worldwide downstream spending in 2012 is estimated at $3.6 billion, with about $2.1 billion for projects in the United States. Major capital outlays include projects under construction at refineries in the United States and South Korea, expansion of additives production capacity in Singapore, and chemicals projects in the United States and Saudi Arabia.

Investments in technology, power generation and other corporate businesses in 2012 are budgeted at $600 million.

Noncontrolling interests The company had noncontrolling interests of $799 million and $730 million at December 31, 2011 and 2010, respectively. Distributions to noncontrolling interests totaled $71 million and $72 million in 2011 and 2010, respectively.

Pension Obligations Information related to pension plan contributions is included on page 57 in Note 21 to the Consolidated Financial Statements under the heading “Cash Contributions and Benefit Payments.” Refer also to the discussion of pension accounting in “Critical Accounting Estimates and Assumptions,” beginning on page 24.

## Financial Ratios

## Financial Ratios

<table><tr><td></td><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Current Ratio</td><td>1.6</td><td>1.7</td><td>1.4</td></tr><tr><td>Interest Coverage Ratio</td><td>165.4</td><td>101.7</td><td>62.3</td></tr><tr><td>Debt Ratio</td><td>7.7%</td><td>9.8%</td><td>10.3%</td></tr></table>

Current Ratio – current assets divided by current liabilities, which indicates the company’s ability to repay its short-term liabilities with short-term assets. The current ratio in all periods was adversely affected by the fact that Chevron’s inventories are valued on a last-in, first-out basis. At year-end 2011, the book value of inventory was lower than replacement costs, based on average acquisition costs during the year, by approximately $9.0 billion.

Interest Coverage Ratio – income before income tax expense, plus interest and debt expense and amortization of capitalized interest, less net income attributable to noncontrolling interests, divided by before-tax interest costs. This ratio indicates the company’s ability to pay interest on outstanding debt. The company’s interest coverage ratio in 2011 was higher than 2010 and 2009 due to higher before-tax income.

Debt Ratio – total debt as a percentage of total debt plus Chevron Corporation Stockholders’ Equity, which indicates the company’s leverage. The decrease between 2011 and 2010 was due to lower debt and a higher Chevron Corporation stockholders’ equity balance. The decrease between 2010 and 2009 was due to a higher Chevron Corporation stockholders’ equity balance.



Debt (left scale)
CVX Stockholders' Equity (left scale)
Ratio (right scale)
The ratio of total debt to total debt-plus-Chevron Corporation Stockholders' Equity decreased to 7.7 percent at the end of 2011 due to lower debt and an increase in Stockholders' Equity.

## Guarantees, Off-Balance-Sheet Arrangements and Contractual Obligations, and Other Contingencies

## Direct Guarantee

<table><tr><td rowspan="2">Millions of dollars</td><td colspan="5">Commitment Expiration by Period</td></tr><tr><td>Total</td><td>2012</td><td>2013-2014</td><td>2015-2016</td><td>After 2016</td></tr><tr><td>Guarantee of non-consolidated affiliate or joint-venture obligation</td><td>$ 601</td><td>$ 38</td><td>$ 77</td><td>$ 77</td><td>$ 409</td></tr></table>

The company’s guarantee of approximately $600 million is associated with certain payments under a terminal use agreement entered into by a company affiliate. The terminal commenced operations in third quarter 2011. Over the approximate 16-year term of the guarantee, the maximum guarantee amount will be reduced over time as certain fees are paid by the affiliate. There are numerous cross-indemnity agreements with the affiliate and the other partners to permit recovery of amounts paid under the guarantee. Chevron has recorded no liability for its obligation under this guarantee.

Indemnifications Information related to indemnifications is included on page 64 in Note 24 to the Consolidated Financial Statements under the heading “Indemnifications.”

Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements The company and its subsidiaries have certain other contingent liabilities with respect to long-term unconditional purchase obligations and commitments, including throughput and take-or-pay agreements, some of which relate to suppliers’



financing arrangements. The agreements typically provide goods and services, such as pipeline and storage capacity, drilling rigs, utilities, and petroleum products, to be used or sold in the ordinary course of the company’s business. The aggregate approximate amounts of required payments under these various commitments are: 2012 – $6.0 billion; 2013 – $4.0 billion; 2014 – $3.9 billion; 2015 – $3.2 billion; 2016 – $1.9 billion; 2017 and after – $7.4 billion. A portion of these commitments may ultimately be shared with project partners. Total payments under the agreements were approximately $6.6 billion in 2011, $6.5 billion in 2010 and $8.1 billion in 2009.

The following table summarizes the company’s significant contractual obligations:

## Contractual Obligations \( ^{1} \) 

<table><tr><td colspan="7">Millions of dollars</td><td colspan="2">Payments Due by Period</td></tr><tr><td></td><td></td><td></td><td>2012</td><td>2013-2014</td><td>2015-2016</td><td>2016</td><td>After 2016</td><td></td></tr><tr><td>On Balance Sheet: \( ^{2} \)</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Short-Term Debt \( ^{3} \)</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Long-Term Debt \( ^{3} \)</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Noncancelable Capital Lease Obligations</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Interest</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Off Balance Sheet:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Noncancelable Operating Lease Obligations</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Throughput and Take-or-Pay Agreements \( ^{4} \)</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Other Unconditional Purchase Obligations \( ^{4} \)</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr></table>

 \( ^{1} \)  Excludes contributions for pensions and other postretirement benefit plans. Information on employee benefit plans is contained in Note 21 beginning on page 57.

 \( ^{2} \)  Does not include amounts related to the company’s income tax liabilities associated with uncertain tax positions. The company is unable to make reasonable estimates for the periods in which these liabilities may become payable. The company does not expect settlement of such liabilities will have a material effect on its results of operations, consolidated financial position or liquidity in any single period.

 \( ^{3} $  $ 5.6 billion of short-term debt that the company expects to refinance is included in long-term debt. The repayment schedule above reflects the projected repayment of the entire amounts in the 2013–2014 period.

 \( ^{4} \)  Does not include commodity purchase obligations that are not fixed or determinable. These obligations are generally monetized in a relatively short period of time through sales transactions or similar agreements with third parties. Examples include obligations to purchase LNG, regasified natural gas and refinery products at indexed prices.

## Financial and Derivative Instruments

The market risk associated with the company’s portfolio of financial and derivative instruments is discussed below. The estimates of financial exposure to market risk do not represent the company’s projection of future market changes. The actual impact of future market changes could differ materially due to factors discussed elsewhere in this report, including those set forth under the heading “Risk Factors” in Part I, Item 1A, of the company’s 2011 Annual Report on Form 10-K.

Derivative Commodity Instruments Chevron is exposed to market risks related to the price volatility of crude oil, refined products, natural gas, natural gas liquids, liquefied natural gas and refinery feedstocks.

The company uses derivative commodity instruments to manage these exposures on a portion of its activity, including firm commitments and anticipated transactions for the purchase, sale and storage of crude oil, refined products, natural gas, natural gas liquids and feedstock for company refineries. The company also uses derivative commodity instruments for limited trading purposes. The results of these activities were not material to the company’s financial position, results of operations or cash flows in 2011.

The company’s market exposure positions are monitored and managed on a daily basis by an internal Risk Control group in accordance with the company’s risk management policies, which have been approved by the Audit Committee of the company’s Board of Directors.

The derivative commodity instruments used in the company’s risk management and trading activities consist mainly of futures, options and swap contracts traded on the New York Mercantile Exchange and on electronic platforms of the Inter-Continental Exchange and Chicago Mercantile Exchange. In addition, crude oil, natural gas and refined product swap contracts and option contracts are entered into principally with major financial institutions and other oil and gas companies in the “over-the-counter” markets.

Derivatives beyond those designated as normal purchase and normal sale contracts are recorded at fair value on the Consolidated Balance Sheet in accordance with accounting standards for derivatives (ASC 815), with resulting gains and losses reflected in income. Fair values are derived principally from published market quotes and other independent third-party quotes. The change in fair value of Chevron’s derivative commodity instruments in 2011 was a quarterly average increase of $22 million in total assets and a quarterly average decrease of $17 million in total liabilities.

The company uses a Value-at-Risk (VaR) model to estimate the potential loss in fair value on a single day from the effect of adverse changes in market conditions on derivative commodity instruments held or issued. VaR is the maximum projected loss not to be exceeded within a given probability or confidence level over a given period of time. The company’s VaR model uses the Monte Carlo simulation method that involves generating hypothetical scenarios from the specified probability distributions and constructing a full distribution of a portfolio’s potential values.

The VaR model utilizes an exponentially weighted moving average for computing historical volatilities and correlations, a 95 percent confidence level, and a one-day holding period. That is, the company’s 95 percent, one-day VaR corresponds to the unrealized loss in portfolio value that would not be exceeded on average more than one in every 20 trading days, if the portfolio were held constant for one day.

The one-day holding period is based on the assumption that market-risk positions can be liquidated or hedged within one day. For hedging and risk management, the company uses conventional exchange-traded instruments such as futures and options as well as non-exchange-traded swaps, most of which can be liquidated or hedged effectively within one day. The following table presents the 95 percent/one-day VaR for each of the company’s primary risk exposures in the area of derivative commodity instruments at December 31, 2011 and 2010.



<table><tr><td>Millions of dollars</td><td>2011</td><td>2010</td></tr><tr><td>Crude Oil</td><td>$ 22</td><td>$ 15</td></tr><tr><td>Natural Gas</td><td>4</td><td>4</td></tr><tr><td>Refined Products</td><td>11</td><td>14</td></tr></table>

Foreign Currency The company may enter into foreign currency derivative contracts to manage some of its foreign currency exposures. These exposures include revenue and anticipated purchase transactions, including foreign currency capital expenditures and lease commitments. The foreign currency derivative contracts, if any, are recorded at fair value on the balance sheet with resulting gains and losses reflected in income. There were no open foreign currency derivative contracts at December 31, 2011.

Interest Rates The company may enter into interest rate swaps from time to time as part of its overall strategy to manage the interest rate risk on its debt. Interest rate swaps, if any, are recorded at fair value on the balance sheet with resulting gains and losses reflected in income. At year-end 2011, the company had no interest rate swaps.

## Transactions With Related Parties

Chevron enters into a number of business arrangements with related parties, principally its equity affiliates. These arrangements include long-term supply or offtake agreements and long-term purchase agreements. Refer to “Other Information” in Note 12 of the Consolidated Financial Statements, page 48, for further discussion. Management believes these agreements have been negotiated on terms consistent with those that would have been negotiated with an unrelated party.

## Litigation and Other Contingencies

MTBE Information related to methyl tertiary butyl ether (MTBE) matters is included on page 49 in Note 14 to the Consolidated Financial Statements under the heading “MTBE.”

Ecuador Information related to Ecuador matters is included in Note 14 to the Consolidated Financial Statements under the heading “Ecuador”, beginning on page 49.

Environmental The company is subject to loss contingencies pursuant to laws, regulations, private claims and legal proceedings related to environmental matters that are subject to legal settlements or that in the future may require the company to take action to correct or ameliorate the effects on the environment of prior release of chemicals or petroleum substances, including MTBE, by the company or other parties. Such contingencies may exist for various sites, including, but not limited to, federal Superfund sites and analogous sites under state laws, refineries, crude oil fields, service stations, terminals, land development areas, and mining operations, whether operating, closed or divested. These future costs are not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties.

Although the company has provided for known environmental obligations that are probable and reasonably estimable, the amount of additional future costs may be material to results of operations in the period in which they are
recognized. The company does not expect these costs will have a material effect on its consolidated financial position or liquidity. Also, the company does not believe its obligations to make such expenditures have had, or will have, any significant impact on the company’s competitive position relative to other U.S. or international petroleum or chemical companies.



The following table displays the annual changes to the company’s before-tax environmental remediation reserves, including those for federal Superfund sites and analogous sites under state laws.

<table><tr><td>Millions of dollars</td><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Balance at January 1</td><td>$ 1,507</td><td>$ 1,700</td><td>$ 1,818</td></tr><tr><td>Net Additions</td><td>343</td><td>220</td><td>351</td></tr><tr><td>Expenditures</td><td>(446)</td><td>(413)</td><td>(469)</td></tr><tr><td>Balance at December 31</td><td>$ 1,404</td><td>$ 1,507</td><td>$ 1,700</td></tr></table>

Included in the $1,404 million year-end 2011 reserve balance were remediation activities at approximately 180 sites for which the company had been identified as a potentially responsible party or otherwise involved in the remediation by the U.S. Environmental Protection Agency (EPA) or other regulatory agencies under the provisions of the federal Superfund law or analogous state laws. The company’s remediation reserve for these sites at year-end 2011 was $185 million. The federal Superfund law and analogous state laws provide for joint and several liability for all responsible parties. Any future actions by the EPA or other regulatory agencies to require Chevron to assume other potentially responsible parties’ costs at designated hazardous waste sites are not expected to have a material effect on the company’s results of operations, consolidated financial position or liquidity.



Of the remaining year-end 2011 environmental reserves balance of $1,219 million, $675 million related to the company’s U.S. downstream operations, including refineries and other plants, marketing locations (i.e., service stations and terminals), chemical facilities, and pipelines. The remaining $544 million was associated with various sites in international downstream ($95 million), upstream ($368 million) and other businesses ($81 million). Liabilities at all sites, whether operating, closed or divested, were primarily associated with the company’s plans and activities to remediate soil or groundwater contamination or both. These and other activities include one or more of the following: site assessment; soil excavation; offsite disposal of contaminants; onsite containment, remediation and/or extraction of petroleum hydrocarbon liquid and vapor from soil; groundwater extraction and treatment; and monitoring of the natural attenuation of the contaminants.

The company manages environmental liabilities under specific sets of regulatory requirements, which in the United States include the Resource Conservation and Recovery Act and various state and local regulations. No single remediation site at year-end 2011 had a recorded liability that was material to the company’s results of operations, consolidated financial position or liquidity.

It is likely that the company will continue to incur additional liabilities, beyond those recorded, for environmental remediation relating to past operations. These future costs are not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company's liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties.

The company records asset retirement obligations when there is a legal obligation associated with the retirement of long-lived assets and the liability can be reasonably estimated. These asset retirement obligations include costs related to environmental issues. The liability balance of approximately $12.8 billion for asset retirement obligations at year-end 2011 related primarily to upstream properties.

For the company’s other ongoing operating assets, such as refineries and chemicals facilities, no provisions are made for exit or cleanup costs that may be required when such assets reach the end of their useful lives unless a decision to sell or otherwise abandon the facility has been made, as the indeterminate settlement dates for the asset retirements prevent estimation of the fair value of the asset retirement obligation.

Refer also to Note 25 on page 66, related to the company’s asset retirement obligations and the discussion of “Environmental Matters” beginning on page 23.

Suspended Wells The company suspends the costs of exploratory wells pending a final determination of the commercial potential of the related crude oil and natural gas fields. The ultimate disposition of these well costs is dependent on the results of future drilling activity or development decisions or both. At December 31, 2011, the company had approximately $2.4 billion of suspended exploratory wells included in properties, plant and equipment, a decrease of $284 million from 2010. The 2010 balance reflected an increase of $283 million from 2009.

The future trend of the company’s exploration expenses can be affected by amounts associated with well write-offs, including wells that had been previously suspended pending determination as to whether the well had found reserves that could be classified as proved. The effect on exploration expenses in future periods of the $2.4 billion of suspended wells at year-end 2011 is uncertain pending future activities, including normal project evaluation and additional drilling.

Refer to Note 19, beginning on page 55, for additional discussion of suspended wells.

Income Taxes Information related to income tax contingencies is included on pages 51 through 53 in Note 15 and page 64 in Note 24 to the Consolidated Financial Statements under the heading “Income Taxes.”

Other Contingencies Information related to other contingencies is included on pages 65 through 66 in Note 24 to the Consolidated Financial Statements under the heading “Other Contingencies.”

## Environmental Matters

Virtually all aspects of the businesses in which the company engages are subject to various federal, state and local environmental, health and safety laws and regulations. These regulatory requirements continue to increase in both number and complexity over time and govern not only the manner in which the company conducts its operations, but also the products it sells. Most of the costs of complying with laws and regulations pertaining to company operations and products are embedded in the normal costs of doing business.

Accidental leaks and spills requiring cleanup may occur in the ordinary course of business. In addition to the costs for environmental protection associated with its ongoing operations and products, the company may incur expenses for corrective actions at various owned and previously owned facilities and at third-party-owned waste disposal sites used by the company. An obligation may arise when operations are closed or sold or at non-Chevron sites where company products have been handled or disposed of. Most of the expenditures to fulfill these obligations relate to facilities and sites where past operations followed practices and procedures that were considered acceptable at the time but now require investigative or remedial work or both to meet current standards.

Using definitions and guidelines established by the American Petroleum Institute, Chevron estimated its worldwide environmental spending in 2011 at approximately $2.7 billion for its consolidated companies. Included in these expenditures were approximately $1.0 billion of environmental capital expenditures and $1.7 billion of costs associated with the prevention, control, abatement or elimination of hazardous substances and pollutants from operating, closed or divested sites, and the abandonment and restoration of sites.

For 2012, total worldwide environmental capital expenditures are estimated at $1.0 billion. These capital costs are in addition to the ongoing costs of complying with environmental regulations and the costs to remediate previously contaminated sites.



It is not possible to predict with certainty the amount of additional investments in new or existing facilities or amounts of incremental operating costs to be incurred in the future to: prevent, control, reduce or eliminate releases of hazardous materials into the environment; comply with existing and new environmental laws or regulations; or remediate and restore areas damaged by prior releases of hazardous materials. Although these costs may be significant to the results of operations in any single period, the company does not expect them to have a material effect on the company’s liquidity or financial position.

## Critical Accounting Estimates and Assumptions

Management makes many estimates and assumptions in the application of generally accepted accounting principles (GAAP) that may have a material impact on the company’s consolidated financial statements and related disclosures and on the comparability of such information over different reporting periods. All such estimates and assumptions affect reported amounts of assets, liabilities, revenues and expenses, as well as disclosures of contingent assets and liabilities. Estimates and assumptions are based on management’s experience and other information available prior to the issuance of the financial statements. Materially different results can occur as circumstances change and additional information becomes known.

The discussion in this section of “critical” accounting estimates and assumptions is according to the disclosure guidelines of the Securities and Exchange Commission (SEC), wherein:

1. the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change; and
2. the impact of the estimates and assumptions on the company’s financial condition or operating performance is material.

Besides those meeting these “critical” criteria, the company makes many other accounting estimates and assumptions in preparing its financial statements and related disclosures. Although not associated with “highly uncertain matters,” these estimates and assumptions are also subject to revision as circumstances warrant, and materially different results may sometimes occur.

For example, the recording of deferred tax assets requires an assessment under the accounting rules that the future realization of the associated tax benefits be “more likely than not.” Another example is the estimation of crude oil and natural gas reserves under SEC rules, which require “… by analysis of geosciences and engineering data, (the reserves) can be estimated with reasonable certainty to be economically producible… under existing economic conditions” where existing economic conditions include prices based on the average price during the 12-month period prior to the end of the reporting period. Refer to Table V, “Reserve Quantity Information,” beginning on page 75, for the changes in these estimates for the three years ending December 31, 2011, and to Table VII, “Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves” on page 84 for estimates of proved-reserve values for each of the three years ended December 31, 2011. Note 1 to the Consolidated Financial Statements, beginning on page 36, includes a description of the “successful efforts” method of accounting for oil and gas exploration and production activities. The estimates of crude oil and natural gas reserves are important to the timing of expense recognition for costs incurred.

The discussion of the critical accounting policy for “Impairment of Properties, Plant and Equipment and Investments in Affiliates,” beginning on page 26, includes reference to conditions under which downward revisions of proved-reserve quantities could result in impairments of oil and gas properties. This commentary should be read in conjunction with disclosures elsewhere in this discussion and in the Notes to the Consolidated Financial Statements related to estimates, uncertainties, contingencies and new accounting standards. Significant accounting policies are discussed in Note 1 to the Consolidated Financial Statements, beginning on page 36. The development and selection of accounting estimates and assumptions, including those deemed “critical,” and the associated disclosures in this discussion have been discussed by management with the Audit Committee of the Board of Directors.

The areas of accounting and the associated “critical” estimates and assumptions made by the company are as follows:

Pension and Other Postretirement Benefit Plans The determination of pension plan obligations and expense is based on a number of actuarial assumptions. Two critical assumptions are the expected long-term rate of return on plan assets and the discount rate applied to pension plan obligations. For other postretirement benefit (OPEB) plans, which provide for certain health care and life insurance benefits for qualifying retired employees and which are not funded, critical assumptions in determining OPEB obligations and expense are the discount rate and the assumed health care cost-trend rates.

Note 21, beginning on page 57, includes information on the funded status of the company’s pension and OPEB plans at the end of 2011 and 2010; the components of pension and OPEB expense for the three years ended December 31, 2011; and the underlying assumptions for those periods.



Pension and OPEB expense is reported on the Consolidated Statement of Income as “Operating expenses” or “Selling, general and administrative expenses” and applies to all business segments. The year-end 2011 and 2010 funded status, measured as the difference between plan assets and obligations, of each of the company’s pension and OPEB plans is recognized on the Consolidated Balance Sheet. The differences related to overfunded pension plans are reported as a long-term asset in “Deferred charges and other assets.” The differences associated with underfunded or unfunded pension and OPEB plans are reported as “Accrued liabilities” or “Reserves for employee benefit plans.” Amounts yet to be recognized as components of pension or OPEB expense are reported in “Accumulated other comprehensive loss.”

To estimate the long-term rate of return on pension assets, the company uses a process that incorporates actual historical asset-class returns and an assessment of expected future performance and takes into consideration external actuarial advice and asset-class factors. Asset allocations are periodically updated using pension plan asset/liability studies, and the determination of the company's estimates of long-term rates of return are consistent with these studies. The expected long-term rate of return on U.S. pension plan assets, which account for 70 percent of the company's pension plan assets, has remained at 7.8 percent since 2002. For the 10 years ending December 31, 2011, actual asset returns averaged 5.0 percent for this plan. The actual return for 2011 was slightly negative and was associated with the broad decline in the financial markets in the second half of the year. Additionally, with the exception of two other years within this 10 year period, actual asset returns for this plan equaled or exceeded 7.8 percent.

The year-end market-related value of assets of the major U.S. pension plan used in the determination of pension expense was based on the market value in the preceding three months, as opposed to the maximum allowable period of five years under U.S. accounting rules. Management considers the three-month period long enough to minimize the effects of distortions from day-to-day market volatility and still be contemporaneous to the end of the year. For other plans, market value of assets as of year-end is used in calculating the pension expense.

The discount rate assumptions used to determine U.S. and international pension and postretirement benefit plan obligations and expense reflect the prevailing rates available on high-quality fixed-income debt instruments. At December 31, 2011, the company selected a 3.8 percent discount rate for the major U.S. pension plan and 4.0 percent for its OPEB plan. These rates were selected based on a cash flow analysis that matched estimated future benefit payments to the Citigroup Pension Discount Yield Curve as of year-end 2011. The discount rates at the end of 2010 and 2009 were 4.8 percent and 5.3 percent, respectively, for the major U.S. pension plan, and 5.0 percent and 5.8 percent, respectively, for the company's U.S. OPEB plan.

An increase in the expected long-term return on plan assets or the discount rate would reduce pension plan expense, and vice versa. Total pension expense for 2011 was $1.2 billion. As an indication of the sensitivity of pension expense to the long-term rate of return assumption, a 1 percent increase in the expected rate of return on assets of the company's primary U.S. pension plan would have reduced total pension plan expense for 2011 by approximately $75 million. A 1 percent increase in the discount rate for this same plan, which accounted for about 63 percent of the companywide pension obligation, would have reduced total pension plan expense for 2011 by approximately $145 million.

An increase in the discount rate would decrease the pension obligation, thus changing the funded status of a plan reported on the Consolidated Balance Sheet. The aggregate funded status recognized on the Consolidated Balance Sheet at December 31, 2011, was a net liability of approximately $5.4 billion. As an indication of the sensitivity of pension liabilities to the discount rate assumption, a 0.25 percent increase in the discount rate applied to the company's primary U.S. pension plan would have reduced the plan obligation by approximately $375 million, which would have decreased the plan's underfunded status from approximately $2.5 billion to $2.1 billion. Other plans would be less underfunded as discount rates increase. The actual rates of return on plan assets and discount rates may vary significantly from estimates because of unanticipated changes in the world's financial markets.

In 2011, the company’s pension plan contributions were $1.5 billion (including $1.2 billion to the U.S. plans). In 2012, the company estimates contributions will be approximately $900 million. Actual contribution amounts are dependent upon investment results, changes in pension obligations, regulatory requirements and other economic factors. Additional funding may be required if investment returns are insufficient to offset increases in plan obligations.

For the company’s OPEB plans, expense for 2011 was $220 million, and the total liability, which reflected the unfunded status of the plans at the end of 2011, was $3.8 billion.

As an indication of discount rate sensitivity to the determination of OPEB expense in 2011, a 1 percent increase in the discount rate for the company's primary U.S. OPEB plan, which accounted for about 76 percent of the companywide OPEB expense, would have decreased OPEB expense by approximately $10 million. A 0.25 percent increase in the discount rate for the same plan, which accounted for about 81 percent of the companywide OPEB liabilities, would have decreased total OPEB liabilities at the end of 2011 by approximately $75 million.

For the main U.S. postretirement medical plan, the annual increase to company contributions is limited to 4 percent per year. For active employees and retirees under age 65 whose claims experiences are combined for rating purposes, the assumed health care cost-trend rates start with 8 percent in 2012 and gradually drop to 5 percent for 2023 and beyond. As an indication of the health care cost-trend rate sensitivity to the determination of OPEB expense in 2011, a 1 percent increase in the rates for the main U.S. OPEB plan, which accounted for 81 percent of the companywide OPEB liabilities, would have increased OPEB expense by $8 million.



Differences between the various assumptions used to determine expense and the funded status of each plan and actual experience are not included in benefit plan costs in the year the difference occurs. Instead, the differences are included in actuarial gain/loss and unamortized amounts have been reflected in “Accumulated other comprehensive loss” on the Consolidated Balance Sheet. Refer to Note 21, beginning on page 57, for information on the $9.6 billion of before-tax actuarial losses recorded by the company as of December 31, 2011; a description of the method used to amortize those costs; and an estimate of the costs to be recognized in expense during 2012.

Impairment of Properties, Plant and Equipment and Investments in Affiliates The company assesses its properties, plant and equipment (PP&E) for possible impairment whenever events or changes in circumstances indicate that the carrying value of the assets may not be recoverable. Such indicators include changes in the company's business plans, changes in commodity prices and, for crude oil and natural gas properties, significant downward revisions of estimated proved reserve quantities. If the carrying value of an asset exceeds the future undiscounted cash flows expected from the asset, an impairment charge is recorded for the excess of carrying value of the asset over its estimated fair value.

Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters, such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles, and the outlook for global or regional market supply-and-demand conditions for crude oil, natural gas, commodity chemicals and refined products. However, the impairment reviews and calculations are based on assumptions that are consistent with the company's business plans and long-term investment decisions. Refer also to the discussion of impairments of properties, plant and equipment in Note 9 beginning on page 42.

No major individual impairments of PP&E and Investments were recorded for the three years ending December 31, 2011. A sensitivity analysis of the impact on earnings for these periods if other assumptions had been used in impairment reviews and impairment calculations is not practicable, given the broad range of the company's PP&E and the number of assumptions involved in the estimates. That is, favorable changes to some assumptions might have avoided the need to impair any assets in these periods, whereas unfavorable changes might have caused an additional unknown number of other assets to become impaired.
Investments in common stock of affiliates that are accounted for under the equity method, as well as investments in other securities of these equity investees, are reviewed for impairment when the fair value of the investment falls below the company's carrying value. When such a decline is deemed to be other than temporary, an impairment charge is recorded to the income statement for the difference between the investment's carrying value and its estimated fair value at the time.

In making the determination as to whether a decline is other than temporary, the company considers such factors as the duration and extent of the decline, the investee's financial performance, and the company's ability and intention to retain its investment for a period that will be sufficient to allow for any anticipated recovery in the investment's market value. Differing assumptions could affect whether an investment is impaired in any period or the amount of the impairment, and are not subject to sensitivity analysis.

From time to time, the company performs impairment reviews and determines whether any write-down in the carrying value of an asset or asset group is required. For example, when significant downward revisions to crude oil and natural gas reserves are made for any single field or concession, an impairment review is performed to determine if the carrying value of the asset remains recoverable. Also, if the expectation of sale of a particular asset or asset group in any period has been deemed more likely than not, an impairment review is performed, and if the estimated net proceeds exceed the carrying value of the asset or asset group, no impairment charge is required. Such calculations are reviewed each period until the asset or asset group is disposed of. Assets that are not impaired on a held-and-used basis could possibly become impaired if a decision is made to sell such assets. That is, the assets would be impaired if they are classified as held-for-sale and the estimated proceeds from the sale, less costs to sell, are less than the assets' associated carrying values.

Goodwill Goodwill resulting from a business combination is not subject to amortization. As required by accounting standards for goodwill (ASC 350), the company tests such goodwill at the reporting unit level for impairment on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount.

Contingent Losses Management also makes judgments and estimates in recording liabilities for claims, litigation, tax matters and environmental remediation. Actual costs can frequently vary from estimates for a variety of reasons. For



example, the costs from settlement of claims and litigation can vary from estimates based on differing interpretations of laws, opinions on culpability and assessments on the amount of damages. Similarly, liabilities for environmental remediation are subject to change because of changes in laws, regulations and their interpretation, the determination of additional information on the extent and nature of site contamination, and improvements in technology.

Under the accounting rules, a liability is generally recorded for these types of contingencies if management determines the loss to be both probable and estimable. The company generally reports these losses as “Operating expenses” or “Selling, general and administrative expenses” on the Consolidated Statement of Income. An exception to this handling is for income tax matters, for which benefits are recognized only if management determines the tax position is “more likely than not” (i.e., likelihood greater than 50 percent) to be allowed by the tax jurisdiction. For additional discussion of income tax uncertainties, refer to Note 15 beginning on page 51. Refer also to the business segment discussions elsewhere in this section for the effect on earnings from losses associated with certain litigation, environmental remediation and tax matters for the three years ended December 31, 2011.

An estimate as to the sensitivity to earnings for these periods if other assumptions had been used in recording these liabilities is not practicable because of the number of contingencies that must be assessed, the number of underlying assumptions and the wide range of reasonably possible outcomes, both in terms of the probability of loss and the estimates of such loss.

## New Accounting Standards

Refer to Note 18, on page 55 in the Notes to Consolidated Financial Statements, for information regarding new accounting standards.



<table><tr><td rowspan="2">Millions of dollars, except per-share amounts</td><td colspan="8">2011</td><td rowspan="2">2010</td></tr><tr><td>4th Q</td><td>3rd Q</td><td>2nd Q</td><td>1st Q</td><td>4th Q</td><td>3rd Q</td><td>2nd Q</td><td>1st Q</td></tr><tr><td>Revenues and Other Income</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Sales and other operating revenues \( ^{1} \)</td><td>$ 58,027</td><td>$61,261</td><td>$ 66,671</td><td>$ 58,412</td><td>$ 51,852</td><td>$ 48,554</td><td>$ 51,051</td><td>$ 46,741</td><td></td></tr><tr><td>Income from equity affiliates</td><td>1,567</td><td>2,227</td><td>1,882</td><td>1,687</td><td>1,510</td><td>1,242</td><td>1,650</td><td>1,235</td><td></td></tr><tr><td>Other income</td><td>391</td><td>944</td><td>395</td><td>242</td><td>665</td><td>(78)</td><td>303</td><td>203</td><td></td></tr><tr><td>Total Revenues and Other Income</td><td>59,985</td><td>64,432</td><td>68,948</td><td>60,341</td><td>54,027</td><td>49,718</td><td>53,004</td><td>48,179</td><td></td></tr><tr><td>Costs and Other Deductions</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Purchased crude oil and products</td><td>36,363</td><td>37,600</td><td>40,759</td><td>35,201</td><td>30,109</td><td>28,610</td><td>30,604</td><td>27,144</td><td></td></tr><tr><td>Operating expenses</td><td>5,948</td><td>5,378</td><td>5,260</td><td>5,063</td><td>5,343</td><td>4,665</td><td>4,591</td><td>4,589</td><td></td></tr><tr><td>Selling, general and administrative expenses</td><td>1,330</td><td>1,115</td><td>1,200</td><td>1,100</td><td>1,408</td><td>1,181</td><td>1,136</td><td>1,042</td><td></td></tr><tr><td>Exploration expenses</td><td>386</td><td>240</td><td>422</td><td>168</td><td>335</td><td>420</td><td>212</td><td>180</td><td></td></tr><tr><td>Depreciation, depletion and amortization</td><td>3,313</td><td>3,215</td><td>3,257</td><td>3,126</td><td>3,439</td><td>3,401</td><td>3,141</td><td>3,082</td><td></td></tr><tr><td>Taxes other than on income \( ^{1} \)</td><td>2,680</td><td>3,544</td><td>4,843</td><td>4,561</td><td>4,623</td><td>4,559</td><td>4,537</td><td>4,472</td><td></td></tr><tr><td>Interest and debt expense</td><td>-</td><td>-</td><td>-</td><td>-</td><td>4</td><td>9</td><td>17</td><td>20</td><td></td></tr><tr><td>Total Costs and Other Deductions</td><td>50,020</td><td>51,092</td><td>55,741</td><td>49,219</td><td>45,261</td><td>42,845</td><td>44,238</td><td>40,529</td><td></td></tr><tr><td>Income Before Income Tax Expense</td><td>9,965</td><td>13,340</td><td>13,207</td><td>11,122</td><td>8,766</td><td>6,873</td><td>8,766</td><td>7,650</td><td></td></tr><tr><td>Income Tax Expense</td><td>4,813</td><td>5,483</td><td>5,447</td><td>4,883</td><td>3,446</td><td>3,081</td><td>3,322</td><td>3,070</td><td></td></tr><tr><td>Net Income</td><td>$ 5,152</td><td>$ 7,857</td><td>$ 7,760</td><td>$ 6,239</td><td>$ 5,320</td><td>$ 3,792</td><td>$ 5,444</td><td>$ 4,580</td><td></td></tr><tr><td>Less: Net income attributable to noncontrolling interests</td><td>29</td><td>28</td><td>28</td><td>28</td><td>25</td><td>24</td><td>35</td><td>28</td><td></td></tr><tr><td>Net Income Attributable to Chevron Corporation</td><td>$ 5,123</td><td>$ 7,829</td><td>$ 7,732</td><td>$ 6,211</td><td>$ 5,295</td><td>$ 3,768</td><td>$ 5,409</td><td>$ 4,552</td><td></td></tr><tr><td>Per Share of Common Stock</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net Income Attributable to Chevron Corporation</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>- Basic</td><td>$ 2.61</td><td>$ 3.94</td><td>$ 3.88</td><td>$ 3.11</td><td>$ 2.65</td><td>$ 1.89</td><td>$ 2.71</td><td>$ 2.28</td><td></td></tr><tr><td>- Diluted</td><td>$ 2.58</td><td>$ 3.92</td><td>$ 3.85</td><td>$ 3.09</td><td>$ 2.64</td><td>$ 1.87</td><td>$ 2.70</td><td>$ 2.27</td><td></td></tr><tr><td>Dividends</td><td>$ 0.81</td><td>$ 0.78</td><td>$ 0.78</td><td>$ 0.72</td><td>$ 0.72</td><td>$ 0.72</td><td>$ 0.72</td><td>$ 0,68</td><td></td></tr><tr><td>Common Stock Price Range - High \( ^{2} \)</td><td>$ 110.01</td><td>$ 109.75</td><td>$ 109.94</td><td>$ 109.65</td><td>$ 92.39</td><td>$ 82.19</td><td>$ 83.41</td><td>$ 81.09</td><td></td></tr><tr><td>- Low \( ^{2} \)</td><td>$ 86.68</td><td>$ 87.30</td><td>$ 97.00</td><td>$ 90.12</td><td>$ 80.41</td><td>$ 66.83</td><td>$ 67.80</td><td>$ 69.55</td><td></td></tr><tr><td> \( ^{1} \) Includes excise, value-added and similar taxes:</td><td>$ 1,713</td><td>$ 1,974</td><td>$ 2,264</td><td>$ 2,134</td><td>$ 2,136</td><td>$ 2,182</td><td>$ 2,201</td><td>$ 2,072</td><td></td></tr><tr><td> \( ^{2} \) Intraday price.</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr></table>

The company’s common stock is listed on the New York Stock Exchange (trading symbol: CVX). As of February 13, 2012, stockholders of record numbered approximately 178,000. There are no restrictions on the company’s ability to pay dividends.



## Management’s Responsibility for Financial Statements

## To the Stockholders of Chevron Corporation

Management of Chevron is responsible for preparing the accompanying consolidated financial statements and the related information appearing in this report. The statements were prepared in accordance with accounting principles generally accepted in the United States of America and fairly represent the transactions and financial position of the company. The financial statements include amounts that are based on management’s best estimates and judgment.

As stated in its report included herein, the independent registered public accounting firm of PricewaterhouseCoopers LLP has audited the company’s consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States).

The Board of Directors of Chevron has an Audit Committee composed of directors who are not officers or employees of the company. The Audit Committee meets regularly with members of management, the internal auditors and the independent registered public accounting firm to review accounting, internal control, auditing and financial reporting matters. Both the internal auditors and the independent registered public accounting firm have free and direct access to the Audit Committee without the presence of management.

## Management’s Report on Internal Control Over Financial Reporting

The company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). The company’s management, including the Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of the company’s internal control over financial reporting based on the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the results of this evaluation, the company’s management concluded that internal control over financial reporting was effective as of December 31, 2011.

The effectiveness of the company’s internal control over financial reporting as of December 31, 2011, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report included herein.



John S. Watson
Chairman of the Board
and Chief Executive Officer

February 23, 2012



Patricia E. Yarrington
Vice President
and Chief Financial Officer



Matthew J. Foehr
Vice President
and Comptroller



To the Stockholders and the Board of Directors of Chevron Corporation:

In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of income, comprehensive income, equity and of cash flows present fairly, in all material respects, the financial position of Chevron Corporation and its subsidiaries at December 31, 2011, and December 31, 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

San Francisco, California

February 23, 2012



<table><tr><td rowspan="2"></td><td colspan="3">Year ended December 31</td></tr><tr><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Revenues and Other Income</td><td></td><td></td><td></td></tr><tr><td>Sales and other operating revenues*</td><td>$ 244,371</td><td>$ 198,198</td><td>$ 167,402</td></tr><tr><td>Income from equity affiliates</td><td>7,363</td><td>5,637</td><td>3,316</td></tr><tr><td>Other income</td><td>1,972</td><td>1,093</td><td>918</td></tr><tr><td>Total Revenues and Other Income</td><td>253,706</td><td>204,928</td><td>171,636</td></tr><tr><td>Costs and Other Deductions</td><td></td><td></td><td></td></tr><tr><td>Purchased crude oil and products</td><td>149,923</td><td>116,467</td><td>99,653</td></tr><tr><td>Operating expenses</td><td>21,649</td><td>19,188</td><td>17,857</td></tr><tr><td>Selling, general and administrative expenses</td><td>4,745</td><td>4,767</td><td>4,527</td></tr><tr><td>Exploration expenses</td><td>1,216</td><td>1,147</td><td>1,342</td></tr><tr><td>Depreciation, depletion and amortization</td><td>12,911</td><td>13,063</td><td>12,110</td></tr><tr><td>Taxes other than on income*</td><td>15,628</td><td>18,191</td><td>17,591</td></tr><tr><td>Interest and debt expense</td><td>-</td><td>50</td><td>28</td></tr><tr><td>Total Costs and Other Deductions</td><td>206,072</td><td>172,873</td><td>153,108</td></tr><tr><td>Income Before Income Tax Expense</td><td>47,634</td><td>32,055</td><td>18,528</td></tr><tr><td>Income Tax Expense</td><td>20,626</td><td>12,919</td><td>7,965</td></tr><tr><td>Net Income</td><td>27,008</td><td>19,136</td><td>10,563</td></tr><tr><td>Less: Net income attributable to noncontrolling interests</td><td>113</td><td>112</td><td>80</td></tr><tr><td>Net Income Attributable to Chevron Corporation</td><td>$ 26,895</td><td>$ 19,024</td><td>$ 10,483</td></tr><tr><td>Per Share of Common Stock</td><td></td><td></td><td></td></tr><tr><td>Net Income Attributable to Chevron Corporation</td><td></td><td></td><td></td></tr><tr><td>- Basic</td><td>$ 13.54</td><td>$ 9.53</td><td>$ 5.26</td></tr><tr><td>- Diluted</td><td>$ 13.44</td><td>$ 9.48</td><td>$ 5.24</td></tr></table>

See accompanying Notes to the Consolidated Financial Statements.



<table><tr><td rowspan="2"></td><td colspan="3">Year ended December 31</td></tr><tr><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Net Income</td><td>$ 27,008</td><td>$ 19,136</td><td>$ 10,563</td></tr><tr><td>Currency translation adjustment</td><td></td><td></td><td></td></tr><tr><td>Unrealized net change arising during period</td><td>17</td><td>6</td><td>60</td></tr><tr><td>Unrealized holding (loss) gain on securities</td><td></td><td></td><td></td></tr><tr><td>Net (loss) gain arising during period</td><td>(11)</td><td>(4)</td><td>2</td></tr><tr><td>Derivatives</td><td></td><td></td><td></td></tr><tr><td>Net derivatives gain (loss) on hedge transactions</td><td>20</td><td>25</td><td>(69)</td></tr><tr><td>Reclassification to net income of net realized loss (gain)</td><td>9</td><td>5</td><td>(23)</td></tr><tr><td>Income taxes on derivatives transactions</td><td>(10)</td><td>(10)</td><td>32</td></tr><tr><td>Total</td><td>19</td><td>20</td><td>(60)</td></tr><tr><td>Defined benefit plans</td><td></td><td></td><td></td></tr><tr><td>Actuarial loss</td><td></td><td></td><td></td></tr><tr><td>Amortization to net income of net actuarial loss</td><td>773</td><td>635</td><td>575</td></tr><tr><td>Actuarial loss arising during period</td><td>(3,250)</td><td>(857)</td><td>(1,099)</td></tr><tr><td>Prior service cost</td><td></td><td></td><td></td></tr><tr><td>Amortization to net income of net prior service credits</td><td>(26)</td><td>(61)</td><td>(65)</td></tr><tr><td>Prior service cost arising during period</td><td>(27)</td><td>(12)</td><td>(34)</td></tr><tr><td>Defined benefit plans sponsored by equity affiliates</td><td>(81)</td><td>(12)</td><td>65</td></tr><tr><td>Income taxes on defined benefit plans</td><td>1,030</td><td>140</td><td>159</td></tr><tr><td>Total</td><td>(1,581)</td><td>(167)</td><td>(399)</td></tr><tr><td>Other Comprehensive Loss, Net of Tax</td><td>(1,556)</td><td>(145)</td><td>(397)</td></tr><tr><td>Comprehensive Income</td><td>25,452</td><td>18,991</td><td>10,166</td></tr><tr><td>Comprehensive income attributable to noncontrolling interests</td><td>(113)</td><td>(112)</td><td>(80)</td></tr><tr><td>Comprehensive Income Attributable to Chevron Corporation</td><td>$ 25,339</td><td>$ 18,879</td><td>$ 10,086</td></tr></table>

See accompanying Notes to the Consolidated Financial Statements.



<table><tr><td rowspan="2"></td><td colspan="2">At December 31</td></tr><tr><td>2011</td><td>2010</td></tr><tr><td>Assets</td><td></td><td></td></tr><tr><td>Cash and cash equivalents</td><td>$ 15,864</td><td>$ 14,060</td></tr><tr><td>Time deposits</td><td>3,958</td><td>2,855</td></tr><tr><td>Marketable securities</td><td>249</td><td>155</td></tr><tr><td>Accounts and notes receivable (less allowance: 2011 - $98; 2010 - $184)</td><td>21,793</td><td>20,759</td></tr><tr><td>Inventories:</td><td></td><td></td></tr><tr><td>Crude oil and petroleum products</td><td>3,420</td><td>3,589</td></tr><tr><td>Chemicals</td><td>502</td><td>395</td></tr><tr><td>Materials, supplies and other</td><td>1,621</td><td>1,509</td></tr><tr><td>Total inventories</td><td>5,543</td><td>5,493</td></tr><tr><td>Prepaid expenses and other current assets</td><td>5,827</td><td>5,519</td></tr><tr><td>Total Current Assets</td><td>53,234</td><td>48,841</td></tr><tr><td>Long-term receivables, net</td><td>2,233</td><td>2,077</td></tr><tr><td>Investments and advances</td><td>22,868</td><td>21,520</td></tr><tr><td>Properties, plant and equipment, at cost</td><td>233,432</td><td>207,367</td></tr><tr><td>Less: Accumulated depreciation, depletion and amortization</td><td>110,824</td><td>102,863</td></tr><tr><td>Properties, plant and equipment, net</td><td>122,608</td><td>104,504</td></tr><tr><td>Deferred charges and other assets</td><td>3,889</td><td>3,210</td></tr><tr><td>Goodwill</td><td>4,642</td><td>4,617</td></tr><tr><td>Total Assets</td><td>$ 209,474</td><td>$ 184,769</td></tr><tr><td>Liabilities and Equity</td><td></td><td></td></tr><tr><td>Short-term debt</td><td>$ 340</td><td>$ 187</td></tr><tr><td>Accounts payable</td><td>22,147</td><td>19,259</td></tr><tr><td>Accrued liabilities</td><td>5,287</td><td>5,324</td></tr><tr><td>Federal and other taxes on income</td><td>4,584</td><td>2,776</td></tr><tr><td>Other taxes payable</td><td>1,242</td><td>1,466</td></tr><tr><td>Total Current Liabilities</td><td>33,600</td><td>29,012</td></tr><tr><td>Long-term debt</td><td>9,684</td><td>11,003</td></tr><tr><td>Capital lease obligations</td><td>128</td><td>286</td></tr><tr><td>Deferred credits and other noncurrent obligations</td><td>19,181</td><td>19,264</td></tr><tr><td>Noncurrent deferred income taxes</td><td>15,544</td><td>12,697</td></tr><tr><td>Reserves for employee benefit plans</td><td>9,156</td><td>6,696</td></tr><tr><td>Total Liabilities</td><td>87,293</td><td>78,958</td></tr><tr><td>Preferred stock (authorized 100,000,000 shares; $1.00 par value; none issued)</td><td>-</td><td>-</td></tr><tr><td>Common stock (authorized 6,000,000,000 shares; $0.75 par value; 2,442,676,580 shares issued at December 31, 2011 and 2010)</td><td>1,832</td><td>1,832</td></tr><tr><td>Capital in excess of par value</td><td>15,156</td><td>14,796</td></tr><tr><td>Retained earnings</td><td>140,399</td><td>119,641</td></tr><tr><td>Accumulated other comprehensive loss</td><td>(6,022)</td><td>(4,466)</td></tr><tr><td>Deferred compensation and benefit plan trust</td><td>(298)</td><td>(311)</td></tr><tr><td>Treasury stock, at cost (2011 - 461,509,656 shares; 2010 - 435,195,799 shares)</td><td>(29,685)</td><td>(26,411)</td></tr><tr><td>Total Chevron Corporation Stockholders&#x27; Equity</td><td>121,382</td><td>105,081</td></tr><tr><td>Noncontrolling interests</td><td>799</td><td>730</td></tr><tr><td>Total Equity</td><td>122,181</td><td>105,811</td></tr><tr><td>Total Liabilities and Equity</td><td>$ 209,474</td><td>$ 184,769</td></tr></table>

See accompanying Notes to the Consolidated Financial Statements.



<table><tr><td rowspan="2"></td><td colspan="3">Year ended December 31</td></tr><tr><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Operating Activities</td><td></td><td></td><td></td></tr><tr><td>Net Income</td><td>$ 27,008</td><td>$ 19,136</td><td>$ 10,563</td></tr><tr><td>Adjustments</td><td></td><td></td><td></td></tr><tr><td>Depreciation, depletion and amortization</td><td>12,911</td><td>13,063</td><td>12,110</td></tr><tr><td>Dry hole expense</td><td>377</td><td>496</td><td>552</td></tr><tr><td>Distributions less than income from equity affiliates</td><td>(570)</td><td>(501)</td><td>(103)</td></tr><tr><td>Net before-tax gains on asset retirements and sales</td><td>(1,495)</td><td>(1,004)</td><td>(1,255)</td></tr><tr><td>Net foreign currency effects</td><td>(103)</td><td>251</td><td>466</td></tr><tr><td>Deferred income tax provision</td><td>1,589</td><td>559</td><td>467</td></tr><tr><td>Net decrease (increase) in operating working capital</td><td>2,318</td><td>76</td><td>(2,301)</td></tr><tr><td>Increase in long-term receivables</td><td>(150)</td><td>(12)</td><td>(258)</td></tr><tr><td>Decrease in other deferred charges</td><td>341</td><td>48</td><td>201</td></tr><tr><td>Cash contributions to employee pension plans</td><td>(1,467)</td><td>(1,450)</td><td>(1,739)</td></tr><tr><td>Other</td><td>339</td><td>697</td><td>670</td></tr><tr><td>Net Cash Provided by Operating Activities</td><td>41,098</td><td>31,359</td><td>19,373</td></tr><tr><td>Investing Activities</td><td></td><td></td><td></td></tr><tr><td>Acquisition of Atlas Energy</td><td>(3,009)</td><td>-</td><td>-</td></tr><tr><td>Advance to Atlas Energy</td><td>(403)</td><td>-</td><td>-</td></tr><tr><td>Capital expenditures</td><td>(26,500)</td><td>(19,612)</td><td>(19,843)</td></tr><tr><td>Proceeds and deposits related to asset sales</td><td>3,517</td><td>1,995</td><td>2,564</td></tr><tr><td>Net purchases of time deposits</td><td>(1,104)</td><td>(2,855)</td><td>-</td></tr><tr><td>Net (purchases) sales of marketable securities</td><td>(74)</td><td>(49)</td><td>127</td></tr><tr><td>Repayment of loans by equity affiliates</td><td>339</td><td>338</td><td>336</td></tr><tr><td>Net (purchases) sales of other short-term investments</td><td>(255)</td><td>(732)</td><td>244</td></tr><tr><td>Net Cash Used for Investing Activities</td><td>(27,489)</td><td>(20,915)</td><td>(16,572)</td></tr><tr><td>Financing Activities</td><td></td><td></td><td></td></tr><tr><td>Net borrowings (payments) of short-term obligations</td><td>23</td><td>(212)</td><td>(3,192)</td></tr><tr><td>Proceeds from issuances of long-term debt</td><td>377</td><td>1,250</td><td>5,347</td></tr><tr><td>Repayments of long-term debt and other financing obligations</td><td>(2,769)</td><td>(156)</td><td>(496)</td></tr><tr><td>Cash dividends - common stock</td><td>(6,139)</td><td>(5,674)</td><td>(5,302)</td></tr><tr><td>Distributions to noncontrolling interests</td><td>(71)</td><td>(72)</td><td>(71)</td></tr><tr><td>Net (purchases) sales of treasury shares</td><td>(3,193)</td><td>(306)</td><td>168</td></tr><tr><td>Net Cash Used for Financing Activities</td><td>(11,772)</td><td>(5,170)</td><td>(3,546)</td></tr><tr><td>Effect of Exchange Rate Changes</td><td></td><td></td><td></td></tr><tr><td>on Cash and Cash Equivalents</td><td>(33)</td><td>70</td><td>114</td></tr><tr><td>Net Change in Cash and Cash Equivalents</td><td>1,804</td><td>5,344</td><td>(631)</td></tr><tr><td>Cash and Cash Equivalents at January 1</td><td>14,060</td><td>8,716</td><td>9,347</td></tr><tr><td>Cash and Cash Equivalents at December 31</td><td>$ 15,864</td><td>$ 14,060</td><td>$ 8,716</td></tr></table>

See accompanying Notes to the Consolidated Financial Statements.



<table><tr><td rowspan="2"></td><td colspan="2">2011</td><td colspan="2">2010</td><td colspan="2">2009</td></tr><tr><td>Shares</td><td>Amount</td><td>Shares</td><td>Amount</td><td>Shares</td><td>Amount</td></tr><tr><td>Preferred Stock</td><td>-</td><td>$ -</td><td>-</td><td>$ -</td><td>-</td><td>$ -</td></tr><tr><td>Common Stock</td><td>2,442,677</td><td>$ 1,832</td><td>2,442,677</td><td>$ 1,832</td><td>2,442,677</td><td>$ 1,832</td></tr><tr><td>Capital in Excess of Par</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Balance at January 1</td><td></td><td>$ 14,796</td><td></td><td>$ 14,631</td><td></td><td>$ 14,448</td></tr><tr><td>Treasury stock transactions</td><td></td><td>360</td><td></td><td>165</td><td></td><td>183</td></tr><tr><td>Balance at December 31</td><td></td><td>$ 15,156</td><td></td><td>$ 14,796</td><td></td><td>$ 14,631</td></tr><tr><td>Retained Earnings</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Balance at January 1</td><td></td><td>$ 119,641</td><td></td><td>$ 106,289</td><td></td><td>$ 101,102</td></tr><tr><td>Net income attributable to Chevron Corporation</td><td></td><td>26,895</td><td></td><td>19,024</td><td></td><td>10,483</td></tr><tr><td>Cash dividends on common stock</td><td></td><td>(6,139)</td><td></td><td>(5,674)</td><td></td><td>(5,302)</td></tr><tr><td>Tax benefit from dividends paid on unallocated ESOP shares and other</td><td></td><td>2</td><td></td><td>2</td><td></td><td>6</td></tr><tr><td>Balance at December 31</td><td></td><td>$ 140,399</td><td></td><td>$ 119,641</td><td></td><td>$ 106,289</td></tr><tr><td>Accumulated Other Comprehensive Loss</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Currency translation adjustment</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Balance at January 1</td><td></td><td>$ (105)</td><td></td><td>$ (111)</td><td></td><td>$ (171)</td></tr><tr><td>Change during year</td><td></td><td>17</td><td></td><td>6</td><td></td><td>60</td></tr><tr><td>Balance at December 31</td><td></td><td>$ (88)</td><td></td><td>$ (105)</td><td></td><td>$ (111)</td></tr><tr><td>Pension and other postretirement benefit plans</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Balance at January 1</td><td></td><td>$ (4,475)</td><td></td><td>$ (4,308)</td><td></td><td>$ (3,909)</td></tr><tr><td>Change during year</td><td></td><td>(1,581)</td><td></td><td>(167)</td><td></td><td>(399)</td></tr><tr><td>Balance at December 31</td><td></td><td>$ (6,056)</td><td></td><td>$ (4,475)</td><td></td><td>$ (4,308)</td></tr><tr><td>Unrealized net holding gain on securities</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Balance at January 1</td><td></td><td>$ 11</td><td></td><td>$ 15</td><td></td><td>$ 13</td></tr><tr><td>Change during year</td><td></td><td>(11)</td><td></td><td>(4)</td><td></td><td>2</td></tr><tr><td>Balance at December 31</td><td></td><td>$ -</td><td></td><td>$ 11</td><td></td><td>$ 15</td></tr><tr><td>Net derivatives gain (loss) on hedge transactions</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Balance at January 1</td><td></td><td>$ 103</td><td></td><td>$ 83</td><td></td><td>$ 143</td></tr><tr><td>Change during year</td><td></td><td>19</td><td></td><td>20</td><td></td><td>(60)</td></tr><tr><td>Balance at December 31</td><td></td><td>$ 122</td><td></td><td>$ 103</td><td></td><td>$ 83</td></tr><tr><td>Balance at December 31</td><td></td><td>$ (6,022)</td><td></td><td>$ (4,466)</td><td></td><td>$ (4,321)</td></tr><tr><td>Deferred Compensation and Benefit Plan Trust</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Deferred Compensation</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Balance at January 1</td><td></td><td>$ (71)</td><td></td><td>$ (109)</td><td></td><td>$ (194)</td></tr><tr><td>Net reduction of ESOP debt and other</td><td></td><td>13</td><td></td><td>38</td><td></td><td>85</td></tr><tr><td>Balance at December 31</td><td></td><td>(58)</td><td></td><td>(71)</td><td></td><td>(109)</td></tr><tr><td>Benefit Plan Trust (Common Stock)</td><td>14,168</td><td>(240)</td><td>14,168</td><td>(240)</td><td>14,168</td><td>(249)</td></tr><tr><td>Balance at December 31</td><td>14,168</td><td>$ (298)</td><td>14,168</td><td>$ (311)</td><td>14,168</td><td>$ (349)</td></tr><tr><td>Treasury Stock at Cost</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Balance at January 1</td><td>435,196</td><td>$ (26,411)</td><td>434,955</td><td>$ (26,168)</td><td>438,445</td><td>$ (26,376)</td></tr><tr><td>Purchases</td><td>42,424</td><td>(4,262)</td><td>9,091</td><td>(775)</td><td>85</td><td>(6)</td></tr><tr><td>Issuances - mainly employee benefit plans</td><td>(16,110)</td><td>988</td><td>(8,850)</td><td>532</td><td>(3,575)</td><td>214</td></tr><tr><td>Balance at December 31</td><td>461,510</td><td>$ (29,685)</td><td>435,196</td><td>$ (26,411)</td><td>434,955</td><td>$ (26,168)</td></tr><tr><td>Total Chevron Corporation Stockholders&#x27; Equity at December 31</td><td></td><td>$ 121,382</td><td></td><td>$ 105,081</td><td></td><td>$ 91,914</td></tr><tr><td>Noncontrolling Interests</td><td></td><td>$ 799</td><td></td><td>$ 730</td><td></td><td>$ 647</td></tr><tr><td>Total Equity</td><td></td><td>$ 122,181</td><td></td><td>$ 105,811</td><td></td><td>$ 92,561</td></tr></table>

See accompanying Notes to the Consolidated Financial Statements.



## Note 1

Summary of Significant Accounting Policies

General Upstream operations consist primarily of exploring for, developing and producing crude oil and natural gas; liquefaction, transportation and regasification associated with liquefied natural gas (LNG); transporting crude oil by major international oil export pipelines; processing, transporting, storage and marketing of natural gas; and a gas-to-liquids project. Downstream operations relate primarily to 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 additives for fuels and lubricant oils.

The company’s Consolidated Financial Statements are prepared in accordance with accounting principles generally accepted in the United States of America. These require the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses reported in the financial statements, as well as amounts included in the notes thereto, including discussion and disclosure of contingent liabilities. Although the company uses its best estimates and judgments, actual results could differ from these estimates as future confirming events occur.

Subsidiary and Affiliated Companies The Consolidated Financial Statements include the accounts of controlled subsidiary companies more than 50 percent-owned and any variable-interest entities in which the company is the primary beneficiary. Undivided interests in oil and gas joint ventures and certain other assets are consolidated on a proportionate basis. Investments in and advances to affiliates in which the company has a substantial ownership interest of approximately 20 percent to 50 percent, or for which the company exercises significant influence but not control over policy decisions, are accounted for by the equity method. As part of that accounting, the company recognizes gains and losses that arise from the issuance of stock by an affiliate that results in changes in the company's proportionate share of the dollar amount of the affiliate's equity currently in income.

Investments are assessed for possible impairment when events indicate that the fair value of the investment may be below the company’s carrying value. When such a condition is deemed to be other than temporary, the carrying value of the investment is written down to its fair value, and the amount of the write-down is included in net income. In making the determination as to whether a decline is other than temporary, the company considers such factors as the duration and extent of the decline, the investee’s financial performance, and the company’s ability and intention to retain its investment for a period that will be sufficient to allow for any anticipated recovery in the investment’s market value. The new cost basis of investments in these equity investees is not changed for subsequent recoveries in fair value.

Differences between the company’s carrying value of an equity investment and its underlying equity in the net assets of the affiliate are assigned to the extent practicable to specific assets and liabilities based on the company’s analysis of the various factors giving rise to the difference. When appropriate, the company’s share of the affiliate’s reported earnings is adjusted quarterly to reflect the difference between these allocated values and the affiliate’s historical book values.

Derivatives The majority of the company’s activity in derivative commodity instruments is intended to manage the financial risk posed by physical transactions. For some of this derivative activity, generally limited to large, discrete or infrequently occurring transactions, the company may elect to apply fair value or cash flow hedge accounting. For other similar derivative instruments, generally because of the short-term nature of the contracts or their limited use, the company does not apply hedge accounting, and changes in the fair value of those contracts are reflected in current income. For the company’s commodity trading activity, gains and losses from derivative instruments are reported in current income. The company may enter into interest rate swaps from time to time as part of its overall strategy to manage the interest rate risk on its debt. Interest rate swaps related to a portion of the company’s fixed-rate debt, if any, may be accounted for as fair value hedges. Interest rate swaps related to floating-rate debt, if any, are recorded at fair value on the balance sheet with resulting gains and losses reflected in income. Where Chevron is a party to master netting arrangements, fair value receivable and payable amounts recognized for derivative instruments executed with the same counterparty are generally offset on the balance sheet.

Short-Term Investments All short-term investments are classified as available for sale and are in highly liquid debt securities. Those investments that are part of the company’s cash management portfolio and have original maturities of three months or less are reported as “Cash equivalents.” Bank time deposits with maturities greater than 90 days are reported as “Time deposits.” The balance of short-term investments is reported as “Marketable securities” and is marked-to-market, with any unrealized gains or losses included in “Other comprehensive income.”

Inventories Crude oil, petroleum products and chemicals inventories are generally stated at cost, using a last-in, first-out method. In the aggregate, these costs are below market. “Materials, supplies and other” inventories generally are stated at average cost.



Properties, Plant and Equipment The successful efforts method is used for crude oil and natural gas exploration and production activities. All costs for development wells, related plant and equipment, proved mineral interests in crude oil and natural gas properties, and related asset retirement obligation (ARO) assets are capitalized. Costs of exploratory wells are capitalized pending determination of whether the wells found proved reserves. Costs of wells that are assigned proved reserves remain capitalized. Costs also are capitalized for exploratory wells that have found crude oil and natural gas reserves even if the reserves cannot be classified as proved when the drilling is completed, provided the exploratory well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project. All other exploratory wells and costs are expensed. Refer to Note 19, beginning on page 55, for additional discussion of accounting for suspended exploratory well costs.

Long-lived assets to be held and used, including proved crude oil and natural gas properties, are assessed for possible impairment by comparing their carrying values with their associated undiscounted, future net before-tax cash flows. Events that can trigger assessments for possible impairments include write-downs of proved reserves based on field performance, significant decreases in the market value of an asset, significant change in the extent or manner of use of or a physical change in an asset, and a more-likely-than-not expectation that a long-lived asset or asset group will be sold or otherwise disposed of significantly sooner than the end of its previously estimated useful life. Impaired assets are written down to their estimated fair values, generally their discounted future net before-tax cash flows. For proved crude oil and natural gas properties in the United States, the company generally performs the impairment review on an individual field basis. Outside the United States, reviews are performed on a country, concession, development area or field basis, as appropriate. In Downstream, impairment reviews are performed on the basis of a refinery, a plant, a marketing/lubricants area or distribution area, as appropriate. Impairment amounts are recorded as incremental “Depreciation, depletion and amortization” expense.

Long-lived assets that are held for sale are evaluated for possible impairment by comparing the carrying value of the asset with its fair value less the cost to sell. If the net book value exceeds the fair value less cost to sell, the asset is considered impaired and adjusted to the lower value. Refer to Note 9, beginning on page 42, relating to fair value measurements.

The fair value of a liability for an ARO is recorded as an asset and a liability when there is a legal obligation associated with the retirement of a long-lived asset and the amount can be reasonably estimated. Refer also to Note 25, on page 66, relating to AROs.

Depreciation and depletion of all capitalized costs of proved crude oil and natural gas producing properties, except mineral interests, are expensed using the unit-of-production method, generally by individual field, as the proved developed reserves are produced. Depletion expenses for capitalized costs of proved mineral interests are recognized using the unit-of-production method by individual field as the related proved reserves are produced. Periodic valuation provisions for impairment of capitalized costs of unproved mineral interests are expensed.

The capitalized costs of all other plant and equipment are depreciated or amortized over their estimated useful lives. In general, the declining-balance method is used to depreciate plant and equipment in the United States; the straight-line method is generally used to depreciate international plant and equipment and to amortize all capitalized leased assets.

Gains or losses are not recognized for normal retirements of properties, plant and equipment subject to composite group amortization or depreciation. Gains or losses from abnormal retirements are recorded as expenses, and from sales as “Other income.”

Expenditures for maintenance (including those for planned major maintenance projects), repairs and minor renewals to maintain facilities in operating condition are generally expensed as incurred. Major replacements and renewals are capitalized.

Goodwill Goodwill resulting from a business combination is not subject to amortization. As required by accounting standards for goodwill (ASC 350), the company tests such goodwill at the reporting unit level for impairment on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting unit below its carrying amount.

Environmental Expenditures Environmental expenditures that relate to ongoing operations or to conditions caused by past operations are expensed. Expenditures that create future benefits or contribute to future revenue generation are capitalized.

Liabilities related to future remediation costs are recorded when environmental assessments or cleanups or both are probable and the costs can be reasonably estimated. For the company’s U.S. and Canadian marketing facilities, the accrual is based in part on the probability that a future remediation commitment will be required. For crude oil, natural gas and mineral-producing properties, a liability for an ARO is made in accordance with accounting standards for asset retirement and environmental obligations. Refer to Note 25, on page 66, for a discussion of the company’s AROs.



For federal Superfund sites and analogous sites under state laws, the company records a liability for its designated share of the probable and estimable costs and probable amounts for other potentially responsible parties when mandated by the regulatory agencies because the other parties are not able to pay their respective shares.

The gross amount of environmental liabilities is based on the company’s best estimate of future costs using currently available technology and applying current regulations and the company’s own internal environmental policies. Future amounts are not discounted. Recoveries or reimbursements are recorded as assets when receipt is reasonably assured.

Currency Translation The U.S. dollar is the functional currency for substantially all of the company’s consolidated operations and those of its equity affiliates. For those operations, all gains and losses from currency remeasurement are included in current period income. The cumulative translation effects for those few entities, both consolidated and affiliated, using functional currencies other than the U.S. dollar are included in “Currency translation adjustment” on the Consolidated Statement of Equity.

Revenue Recognition Revenues associated with sales of crude oil, natural gas, coal, petroleum and chemicals products, and all other sources are recorded when title passes to the customer, net of royalties, discounts and allowances, as applicable. Revenues from natural gas production from properties in which Chevron has an interest with other producers are generally recognized on the entitlement method. Excise, value-added and similar taxes assessed by a governmental authority on a revenue-producing transaction between a seller and a customer are presented on a gross basis. The associated amounts are shown as a footnote to the Consolidated Statement of Income, on page 31. Purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another (including buy/sell arrangements) are combined and recorded on a net basis and reported in “Purchased crude oil and products” on the Consolidated Statement of Income.

Stock Options and Other Share-Based Compensation The company issues stock options and other share-based compensation to its employees and accounts for these transactions under the accounting standards for share-based compensation (ASC 718). For equity awards, such as stock options, total compensation cost is based on the grant date fair value, and for liability awards, such as stock appreciation rights, total compensation cost is based on the settlement value. The company recognizes stock-based compensation expense for all awards over the service period required to earn the award, which is the shorter of the vesting period or the time period an employee becomes eligible to retain the award at retirement. Stock options and stock appreciation rights granted under the company’s Long-Term Incentive Plan have graded vesting provisions by which one-third of each award vests on the first, second and third anniversaries of the date of grant. The company amortizes these graded awards on a straight-line basis.

## Note 2

Acquisition of Atlas Energy, Inc.

On February 17, 2011, the company acquired Atlas Energy, Inc. (Atlas), which held one of the premier acreage positions in the Marcellus Shale, concentrated in southwestern Pennsylvania. The aggregate purchase price of Atlas was approximately $4,500, which included $3,009 cash for all the common shares of Atlas, a $403 cash advance to facilitate Atlas' purchase of a 49 percent interest in Laurel Mountain Midstream LLC and about $1,100 of assumed debt. Subsequent to the close of the transaction, the company paid off the assumed debt and made payments of $184 in connection with Atlas' equity awards. As part of the acquisition, Chevron assumed the terms of a carry arrangement whereby Reliance Marcellus, LLC, funds 75 percent of Chevron's drilling costs, up to $1,300.

The acquisition was accounted for as a business combination (ASC 805) which, among other things, requires assets acquired and liabilities assumed to be measured at their acquisition date fair values. Provisional fair value measurements were made in first quarter 2011 for acquired assets and assumed liabilities, and the measurement process was finalized in fourth quarter 2011.

Proforma financial information is not presented as it would not be materially different from the information presented in the Consolidated Statement of Income.

The following table summarizes the measurement of the assets acquired and liabilities assumed:

<table><tr><td>Millions of Dollars</td><td>At February 17, 2011</td></tr><tr><td>Current assets</td><td>$ 155</td></tr><tr><td>Investments and long-term receivables</td><td>456</td></tr><tr><td>Properties</td><td>6,051</td></tr><tr><td>Goodwill</td><td>27</td></tr><tr><td>Other assets</td><td>5</td></tr><tr><td>Total assets acquired</td><td>6,694</td></tr><tr><td>Current liabilities</td><td>(560)</td></tr><tr><td>Long-term debt and capital leases</td><td>(761)</td></tr><tr><td>Deferred income taxes</td><td>(1,915)</td></tr><tr><td>Other liabilities</td><td>(25)</td></tr><tr><td>Total liabilities assumed</td><td>(3,261)</td></tr><tr><td>Net assets acquired</td><td>$ 3,433</td></tr></table>



Properties were measured primarily using an income approach. The fair values of the acquired oil and gas properties were based on significant inputs not observable in the market and thus represent Level 3 measurements. Refer to Note 9, beginning on page 42 for a definition of fair value hierarchy levels. Significant inputs included estimated resource volumes, assumed future production profiles, estimated future commodity prices, a discount rate of 8 percent, and assumptions on the timing and amount of future operating and development costs. All the properties are in the United States and are included in the Upstream segment.

The acquisition date fair value of the consideration transferred was $3,400 in cash. The $27 of goodwill was assigned to the Upstream segment and represents the amount of the consideration transferred in excess of the values assigned to the individual assets acquired and liabilities assumed. Goodwill represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. None of the goodwill is deductible for tax purposes. Goodwill recorded in the acquisition is not subject to amortization, but will be tested periodically for impairment as required by the applicable accounting standard (ASC 350).

## Note 3

## Noncontrolling Interests

The company adopted the accounting standard for noncontrolling interests (ASC 810) in the consolidated financial statements effective January 1, 2009, and retroactive to the earliest period presented. Ownership interests in the company’s subsidiaries held by parties other than the parent are presented separately from the parent’s equity on the Consolidated Balance Sheet. The amount of consolidated net income attributable to the parent and the noncontrolling interests are both presented on the face of the Consolidated Statement of Income. The term “earnings” is defined as “Net Income Attributable to Chevron Corporation.”

Activity for the equity attributable to noncontrolling interests for 2011, 2010 and 2009 is as follows:

<table><tr><td></td><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Balance at January 1</td><td>$ 730</td><td>$ 647</td><td>$ 469</td></tr><tr><td>Net income</td><td>113</td><td>112</td><td>80</td></tr><tr><td>Distributions to noncontrolling interests</td><td>(71)</td><td>(72)</td><td>(71)</td></tr><tr><td>Other changes, net</td><td>27</td><td>43</td><td>169</td></tr><tr><td>Balance at December 31</td><td>$ 799</td><td>$ 730</td><td>$ 647</td></tr></table>

## Note 4

Information Relating to the Consolidated Statement of Cash Flows

<table><tr><td rowspan="2"></td><td colspan="3">Year ended December 31</td></tr><tr><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Net decrease (increase) in operating working capital was composed of the following:</td><td></td><td></td><td></td></tr><tr><td>Increase in accounts and notes receivable</td><td>$ (2,156)</td><td>$ (2,767)</td><td>$ (1,476)</td></tr><tr><td>(Increase) decrease in inventories</td><td>(404)</td><td>15</td><td>1,213</td></tr><tr><td>Increase in prepaid expenses and other current assets</td><td>(853)</td><td>(542)</td><td>(264)</td></tr><tr><td>Increase (decrease) in accounts payable and accrued liabilities</td><td>3,839</td><td>3,049</td><td>(1,121)</td></tr><tr><td>Increase (decrease) in income and other taxes payable</td><td>1,892</td><td>321</td><td>(653)</td></tr><tr><td>Net decrease (increase) in operating working capital</td><td>$ 2,318</td><td>$ 76</td><td>$ (2,301)</td></tr><tr><td>Net cash provided by operating activities includes the following cash payments for interest and income taxes:</td><td></td><td></td><td></td></tr><tr><td>Interest paid on debt (net of capitalized interest)</td><td>$ -</td><td>$ 34</td><td>$ -</td></tr><tr><td>Income taxes</td><td>$ 17,374</td><td>$ 11,749</td><td>$ 7,537</td></tr><tr><td>Net sales of marketable securities consisted of the following gross amounts:</td><td></td><td></td><td></td></tr><tr><td>Marketable securities purchased</td><td>$ (112)</td><td>$ (90)</td><td>$ (30)</td></tr><tr><td>Marketable securities sold</td><td>38</td><td>41</td><td>157</td></tr><tr><td>Net (purchases) sales of marketable securities</td><td>$ (74)</td><td>$ (49)</td><td>$ 127</td></tr><tr><td>Net purchases of time deposits consisted of the following gross amounts:</td><td></td><td></td><td></td></tr><tr><td>Time deposits purchased</td><td>$ (6,439)</td><td>$ (5,060)</td><td>$ -</td></tr><tr><td>Time deposits matured</td><td>5,335</td><td>2,205</td><td>-</td></tr><tr><td>Net purchases of time deposits</td><td>$ (1,104)</td><td>$ (2,855)</td><td>$ -</td></tr></table>

In accordance with accounting standards for cash-flow classifications for stock options (ASC 718), the “Net decrease (increase) in operating working capital” includes reductions of $121, $67 and $25 for excess income tax benefits associated with stock options exercised during 2011, 2010 and 2009, respectively. These amounts are offset by an equal amount in “Net (purchases) sales of treasury shares.”

The “Acquisition of Atlas Energy” reflects the $3,009 of cash paid for all the common shares of Atlas. An “Advance to Atlas Energy” of $403 was made to facilitate the purchase of a 49 percent interest in Laurel Mountain Midstream LLC on the day of closing. The “Net decrease (increase) in operating working capital” includes $184 for payments made in connection with Atlas equity awards subsequent to the acquisition. Refer to Note 2, beginning on page 38 for additional discussion of the Atlas acquisition.



The “Repayments of long-term debt and other financing obligations” includes $761 for repayment of Atlas debt and $271 for payoff of the Atlas revolving credit facility.

The “Net (purchases) sales of treasury shares” represents the cost of common shares acquired less the cost of shares issued for share-based compensation plans. Purchases totaled $4,262, $775 and $6 in 2011, 2010 and 2009, respectively. In 2011 and 2010, the company purchased 42.3 million and 8.8 million common shares for $4,250 and $750 under its ongoing share repurchase program, respectively.

In 2011 and 2010, “Net sales (purchases) of other short-term investments” consist of restricted cash associated with capital-investment projects at the company’s Pascagoula and El Segundo refineries, acquisitions pending tax deferred exchanges, and Upstream abandonment activities that was invested in short-term securities and reclassified from “Cash and cash equivalents” to “Deferred charges and other assets” on the Consolidated Balance Sheet. The company issued $374, $1,250 and $350 in 2011, 2010 and 2009, respectively, of tax exempt bonds as a source of funds for U.S. refinery projects, which is included in “Proceeds from issuance of long-term debt.”

The Consolidated Statement of Cash Flows excludes changes to the Consolidated Balance Sheet that did not affect cash. In 2009, payments related to “Accrued liabilities” were excluded from “Net decrease (increase) in operating working capital” and were reported as “Capital expenditures.” The “Accrued liabilities” were related to upstream operating agreements outside the United States recorded in 2008. Refer also to Note 25, on page 66, for a discussion of revisions to the company’s AROs that also did not involve cash receipts or payments for the three years ending December 31, 2011.
The major components of “Capital expenditures” and the reconciliation of this amount to the reported capital and exploratory expenditures, including equity affiliates, are presented in the following table:

<table><tr><td rowspan="2"></td><td colspan="3">Year ended December 31</td></tr><tr><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Additions to properties, plant and equipment \( ^{\dagger} \)</td><td>25,440</td><td>18,474</td><td>16,107</td></tr><tr><td>Additions to investments</td><td>900</td><td>861</td><td>942</td></tr><tr><td>Current year dry hole expenditures</td><td>332</td><td>414</td><td>468</td></tr><tr><td>Payments for other liabilities and assets, net \( ^{\dagger} \)</td><td>(172)</td><td>(137)</td><td>2,326</td></tr><tr><td>Capital expenditures</td><td>26,500</td><td>19,612</td><td>19,843</td></tr><tr><td>Expensed exploration expenditures</td><td>839</td><td>651</td><td>790</td></tr><tr><td>Assets acquired through capital lease obligations and other financing obligations</td><td>32</td><td>104</td><td>19</td></tr><tr><td>Capital and exploratory expenditures, excluding equity affiliates</td><td>27,371</td><td>20,367</td><td>20,652</td></tr><tr><td>Company’s share of expenditures by equity affiliates</td><td>1,695</td><td>1,388</td><td>1,585</td></tr><tr><td>Capital and exploratory expenditures, including equity affiliates</td><td>29,066</td><td>21,755</td><td>22,237</td></tr></table>

 \( ^{\dagger} \) Excludes noncash additions of 945 in 2011, 2,753 in 2010 and 985 in 2009.
 \( ^{\dagger} $ 2009 includes payments of 2,450 for accruals recorded in 2008.

## Note 5

Summarized Financial Data – Chevron U.S.A. Inc.
Chevron U.S.A. Inc. (CUSA) is a major subsidiary of Chevron Corporation. CUSA and its subsidiaries manage and operate most of Chevron’s U.S. businesses. Assets include those related to the exploration and production of crude oil, natural gas and natural gas liquids and those associated with the refining, marketing, supply and distribution of products derived from petroleum, excluding most of the regulated pipeline operations of Chevron. CUSA also holds the company’s investment in the Chevron Phillips Chemical Company LLC joint venture, which is accounted for using the equity method.



The summarized financial information for CUSA and its consolidated subsidiaries is as follows:

<table><tr><td rowspan="2"></td><td colspan="3">Year ended December 31</td></tr><tr><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Sales and other operating revenues</td><td>$ 187,917</td><td>$ 145,381</td><td>$ 121,553</td></tr><tr><td>Total costs and other deductions</td><td>178,498</td><td>139,984</td><td>120,053</td></tr><tr><td>Net income attributable to CUSA</td><td>6,899</td><td>4,159</td><td>1,141</td></tr></table>

<table><tr><td rowspan="2"></td><td colspan="2">At December 31</td></tr><tr><td>2011</td><td>2010</td></tr><tr><td>Current assets</td><td>$ 34,478</td><td>$ 29,211</td></tr><tr><td>Other assets</td><td>47,556</td><td>35,294</td></tr><tr><td>Current liabilities</td><td>19,082</td><td>18,098</td></tr><tr><td>Other liabilities</td><td>26,153</td><td>16,785</td></tr><tr><td>Total CUSA net equity</td><td>36,799</td><td>29,622</td></tr><tr><td>Memo: Total debt</td><td>$14,763</td><td>$ 8,284</td></tr></table>

## Note 6

Summarized Financial Data – Chevron Transport Corporation Ltd. Chevron Transport Corporation Ltd. (CTC), incorporated in Bermuda, is an indirect, wholly owned subsidiary of Chevron Corporation. CTC is the principal operator of Chevron's international tanker fleet and is engaged in the marine transportation of crude oil and refined petroleum products. Most of CTC's shipping revenue is derived from providing transportation services to other Chevron companies. Chevron Corporation has fully and unconditionally guaranteed this subsidiary's obligations in connection with certain debt securities issued by a third party. Summarized financial information for CTC and its consolidated subsidiaries is as follows:

<table><tr><td rowspan="2"></td><td colspan="3">Year ended December 31</td></tr><tr><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Sales and other operating revenues</td><td>$ 793</td><td>$ 885</td><td>$ 683</td></tr><tr><td>Total costs and other deductions</td><td>974</td><td>1,008</td><td>810</td></tr><tr><td>Net loss attributable to CTC</td><td>(177)</td><td>(116)</td><td>(124)</td></tr></table>

<table><tr><td rowspan="2"></td><td colspan="2">At December 31</td></tr><tr><td>2011</td><td>2010 \( ^{*} \)</td></tr><tr><td>Current assets</td><td>$ 290</td><td>$ 309</td></tr><tr><td>Other assets</td><td>228</td><td>201</td></tr><tr><td>Current liabilities</td><td>114</td><td>101</td></tr><tr><td>Other liabilities</td><td>346</td><td>175</td></tr><tr><td>Total CTC net equity</td><td>58</td><td>234</td></tr></table>

 \( ^{*} $ 2010 current assets and other liabilities conformed with 2011 presentation.

There were no restrictions on CTC’s ability to pay dividends or make loans or advances at December 31, 2011.

## Note 7

Summarized Financial Data – Tengizchevroil LLP
Chevron has a 50 percent equity ownership interest in Tengizchevroil LLP (TCO). Refer to Note 12, on page 47, for a discussion of TCO operations.

Summarized financial information for 100 percent of TCO is presented in the following table:

<table><tr><td rowspan="2"></td><td colspan="3">Year ended December 31</td></tr><tr><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Sales and other operating revenues</td><td>$ 25,278</td><td>$ 17,812</td><td>$ 12,013</td></tr><tr><td>Costs and other deductions</td><td>10,941</td><td>8,394</td><td>6,044</td></tr><tr><td>Net income attributable to TCO</td><td>10,039</td><td>6,593</td><td>4,178</td></tr></table>

<table><tr><td rowspan="2"></td><td colspan="2">At December 31</td></tr><tr><td>2011</td><td>2010</td></tr><tr><td>Current assets</td><td>$ 3,477</td><td>$ 3,376</td></tr><tr><td>Other assets</td><td>11,619</td><td>11,813</td></tr><tr><td>Current liabilities</td><td>2,995</td><td>2,402</td></tr><tr><td>Other liabilities</td><td>3,759</td><td>4,130</td></tr><tr><td>Total TCO net equity</td><td>8,342</td><td>8,657</td></tr></table>

## Note 8

Lease Commitments

Certain noncancelable leases are classified as capital leases, and the leased assets are included as part of “Properties, plant and equipment, at cost” on the Consolidated Balance Sheet. Such leasing arrangements involve crude oil production and processing equipment, service stations, bareboat char- ters, office buildings, and other facilities. Other leases are classified as operating leases and are not capitalized. The payments on such leases are recorded as expense. Details of the capitalized leased assets are as follows:

<table><tr><td rowspan="2"></td><td colspan="2">At December 31</td></tr><tr><td>2011</td><td>2010</td></tr><tr><td>Upstream</td><td>$ 585</td><td>$ 561</td></tr><tr><td>Downstream</td><td>316</td><td>316</td></tr><tr><td>All Other</td><td>-</td><td>169</td></tr><tr><td>Total</td><td>901</td><td>1,046</td></tr><tr><td>Less: Accumulated amortization</td><td>568</td><td>573</td></tr><tr><td>Net capitalized leased assets</td><td>$ 333</td><td>$ 473</td></tr></table>

Rental expenses incurred for operating leases during 2011, 2010 and 2009 were as follows:

<table><tr><td rowspan="2"></td><td colspan="3">Year ended December 31</td></tr><tr><td>2011</td><td>2010*</td><td>2009*</td></tr><tr><td>Minimum rentals</td><td>$ 892</td><td>$ 931</td><td>$ 933</td></tr><tr><td>Contingent rentals</td><td>11</td><td>10</td><td>7</td></tr><tr><td>Total</td><td>903</td><td>941</td><td>940</td></tr><tr><td>Less: Sublease rental income</td><td>39</td><td>41</td><td>41</td></tr><tr><td>Net rental expense</td><td>$ 864</td><td>$ 900</td><td>$ 899</td></tr></table>

 \( ^{*} \) Prior years have been adjusted to exclude cost of certain charters from rental expenses.



Contingent rentals are based on factors other than the passage of time, principally sales volumes at leased service stations. Certain leases include escalation clauses for adjusting rentals to reflect changes in price indices, renewal options ranging up to 25 years, and options to purchase the leased property during or at the end of the initial or renewal lease period for the fair market value or other specified amount at that time.

At December 31, 2011, the estimated future minimum lease payments (net of noncancelable sublease rentals) under operating and capital leases, which at inception had a non-cancelable term of more than one year, were as follows:

<table><tr><td rowspan="2"></td><td colspan="2">At December 31</td></tr><tr><td>Operating Leases</td><td>Capital Leases</td></tr><tr><td>Year: 2012</td><td>$ 693</td><td>$ 70</td></tr><tr><td>2013</td><td>632</td><td>47</td></tr><tr><td>2014</td><td>523</td><td>32</td></tr><tr><td>2015</td><td>475</td><td>21</td></tr><tr><td>2016</td><td>393</td><td>13</td></tr><tr><td>Thereafter</td><td>793</td><td>68</td></tr><tr><td>Total</td><td>$ 3,509</td><td>$ 251</td></tr><tr><td>Less: Amounts representing interest and executory costs</td><td></td><td>(55)</td></tr><tr><td>Net present values</td><td></td><td>196</td></tr><tr><td>Less: Capital lease obligations included in short-term debt</td><td></td><td>(68)</td></tr><tr><td>Long-term capital lease obligations</td><td></td><td>$ 128</td></tr></table>

## Note 9

## Fair Value Measurements

Accounting standards for fair value measurement (ASC 820) establish a framework for measuring fair value and stipulate disclosures about fair value measurements. The standards apply to recurring and nonrecurring fair value measurements of financial and nonfinancial assets and liabilities. Among the required disclosures is the fair value hierarchy of inputs the company uses to value an asset or a liability. The three levels of the fair value hierarchy are described as follows:

Level 1: Quoted prices (unadjusted) in active markets for identical assets and liabilities. For the company, Level 1 inputs include exchange-traded futures contracts for which the parties are willing to transact at the exchange-quoted price and marketable securities that are actively traded.

Level 2: Inputs other than Level 1 that are observable, either directly or indirectly. For the company, Level 2 inputs include quoted prices for similar assets or liabilities, prices obtained through third-party broker quotes and prices that can be corroborated with other observable inputs for substantially the complete term of a contract.

Level 3: Unobservable inputs. The company does not use Level 3 inputs for any of its recurring fair value measurements. Level 3 inputs may be required for the determination of fair value associated with certain nonrecurring measurements of nonfinancial assets and liabilities.

The table below shows the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis at December 31, 2011, and December 31, 2010.

Marketable Securities The company calculates fair value for its marketable securities based on quoted market prices for identical assets and liabilities. The fair values reflect the cash that would have been received if the instruments were sold at December 31, 2011.

Derivatives The company records its derivative instruments – other than any commodity derivative contracts that are designated as normal purchase and normal sale – on the Consolidated Balance Sheet at fair value, with the offsetting amount to the Consolidated Statement of Income. For derivatives with identical or similar provisions as contracts that are publicly traded on a regular basis, the company uses the market values of the publicly traded instruments as an input for fair value calculations.

The company’s derivative instruments principally include futures, swaps, options and forward contracts for crude oil, natural gas and refined products. Derivatives classified as Level 1 include futures, swaps and options contracts traded in active markets such as the New York Mercantile Exchange.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

<table><tr><td rowspan="2"></td><td colspan="8">At December 31, 2011</td><td colspan="2">At December 31, 2010</td></tr><tr><td>Total</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td></td><td></td></tr><tr><td>Marketable securities</td><td>$ 249</td><td>$ 249</td><td>$ -</td><td>$ -</td><td>$ 155</td><td>$ 155</td><td>$ -</td><td>$ -</td><td></td><td></td></tr><tr><td>Derivatives</td><td>208</td><td>104</td><td>104</td><td>-</td><td>122</td><td>11</td><td>111</td><td>-</td><td></td><td></td></tr><tr><td>Total Assets at Fair Value</td><td>$ 457</td><td>$ 353</td><td>$ 104</td><td>$ -</td><td>$ 277</td><td>$ 166</td><td>$ 111</td><td>$ -</td><td></td><td></td></tr><tr><td>Derivatives</td><td>$ 102</td><td>$ 101</td><td>$ 1</td><td>$ -</td><td>$ 171</td><td>$ 75</td><td>$ 96</td><td>$ -</td><td></td><td></td></tr><tr><td>Total Liabilities at Fair Value</td><td>$ 102</td><td>$ 101</td><td>$ 1</td><td>$ -</td><td>$ 171</td><td>$ 75</td><td>$ 96</td><td>$ -</td><td></td><td></td></tr></table>



Derivatives classified as Level 2 include swaps, options, and forward contracts principally with financial institutions and other oil and gas companies, the fair values of which are obtained from third-party broker quotes, industry pricing services and exchanges. The company obtains multiple sources of pricing information for the Level 2 instruments. Since this pricing information is generated from observable market data, it has historically been very consistent. The company does not materially adjust this information. The company incorporates internal review, evaluation and assessment procedures, including a comparison of Level 2 fair values derived from the company’s internally developed forward curves (on a sample basis) with the pricing information to document reasonable, logical and supportable fair value determinations and proper level of classification.

Impairments of “Properties, plant and equipment” The company did not have any material long-lived assets measured at fair value on a nonrecurring basis to report in 2011 or 2010.

Impairments of “Investments and advances” The company did not have any material investments and advances measured at fair value on a nonrecurring basis to report in 2011 or 2010.

Assets and Liabilities Not Required to Be Measured at Fair Value The company holds cash equivalents and bank time deposits in U.S. and non-U.S. portfolios. The instruments classified as cash equivalents are primarily bank time deposits with maturities of 90 days or less and money market funds. “Cash and cash equivalents” had carrying/fair values of $15,864 and $14,060 at December 31, 2011, and December 31, 2010, respectively. The instruments held in “Time deposits” are bank time deposits with maturities greater than 90 days, and had carrying/fair values of $3,958 and $2,855 at December 31, 2011, and December 31, 2010, respectively. The fair values of cash, cash equivalents and bank time deposits reflect the cash that would have been received if the instruments were settled at December 31, 2011.

“Cash and cash equivalents” do not include investments with a carrying/fair value of $1,240 and $855 at December 31, 2011, and December 31, 2010, respectively. At December 31, 2011, these investments include restricted funds related to various capital-investment projects, acquisitions pending tax deferred exchanges, and Upstream abandonment activities which are reported in “Deferred charges and other assets” on the Consolidated Balance Sheet. Long-term debt of $4,101 and $5,636 at December 31, 2011, and December 31, 2010, had estimated fair values of $4,928 and $6,311, respectively.

The carrying values of short-term financial assets and liabilities on the Consolidated Balance Sheet approximate their fair values. Fair value remeasurements of other financial instruments at December 31, 2011 and 2010 were not material.

The fair value hierarchy for assets and liabilities measured at fair value on a nonrecurring basis at December 31, 2011, is as follows: Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

<table><tr><td rowspan="2"></td><td colspan="12">At December 31</td></tr><tr><td>Total</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Loss Year 2011</td><td>Before-Tax Loss Year 2011</td><td>Total</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Before-Tax Loss Year 2010</td><td></td></tr><tr><td>Properties, plant and equipment, net (held and used)</td><td>$ 67</td><td>$ -</td><td>$ -</td><td>$ 67</td><td>$ 81</td><td>$ 57</td><td>$ -</td><td>$ -</td><td>$ -</td><td>$ 57</td><td>$ 85</td><td></td></tr><tr><td>Properties, plant and equipment, net (held for sale)</td><td>167</td><td>-</td><td>167</td><td>-</td><td>54</td><td>13</td><td>-</td><td>-</td><td>-</td><td>13</td><td>36</td><td></td></tr><tr><td>Investments and advances</td><td>-</td><td>-</td><td>-</td><td>-</td><td>108</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td><td>15</td><td></td></tr><tr><td>Total Nonrecurring Assets at Fair Value</td><td>$ 234</td><td>$ -</td><td>$ 167</td><td>$ 67</td><td>$ 243</td><td>$ 70</td><td>$ -</td><td>$ -</td><td>$ -</td><td>$ 70</td><td>$ 136</td><td></td></tr></table>



## Note 10

Financial and Derivative Instruments

Derivative Commodity Instruments Chevron is exposed to market risks related to price volatility of crude oil, refined products, natural gas, natural gas liquids, liquefied natural gas and refinery feedstocks.

The company uses derivative commodity instruments to manage these exposures on a portion of its activity, including firm commitments and anticipated transactions for the purchase, sale and storage of crude oil, refined products, natural gas, natural gas liquids and feedstock for company refineries. From time to time, the company also uses derivative commodity instruments for limited trading purposes.

The company’s derivative commodity instruments principally include crude oil, natural gas and refined product futures, swaps, options, and forward contracts. None of the company’s derivative instruments is designated as a hedging instrument, although certain of the company’s affiliates make such designation. The company’s derivatives are not material to the company’s financial position, results of operations or liquidity. The company believes it has no material market or credit risks to its operations, financial position or liquidity as a result of its commodity derivative activities.

The company uses International Swaps and Derivatives Association agreements to govern derivative contracts with certain counterparties to mitigate credit risk. Depending on the nature of the derivative transactions, bilateral collateral arrangements may also be required. When the company is engaged in more than one outstanding derivative transaction with the same counterparty and also has a legally enforceable netting agreement with that counterparty, the net mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and is a reasonable measure of the company's credit risk exposure. The company also uses other netting agreements with certain counterparties with which it conducts significant transactions to mitigate credit risk.
Derivative instruments measured at fair value at December 31, 2011, December 31, 2010, and December 31, 2009, and their classification on the Consolidated Balance Sheet and Consolidated Statement of Income are as follows:

Consolidated Balance Sheet: Fair Value of Derivatives Not Designated as Hedging Instruments

<table><tr><td>Type of Contract</td><td>Balance Sheet Classification</td><td>At December 31 2011</td><td>At December 31 2010</td></tr><tr><td>Commodity</td><td>Accounts and notes receivable, net</td><td>$ 133</td><td>$ 58</td></tr><tr><td>Commodity</td><td>Long-term receivables, net</td><td>75</td><td>64</td></tr><tr><td>Total Assets at Fair Value</td><td></td><td>$ 208</td><td>$ 122</td></tr><tr><td>Commodity</td><td>Accounts payable</td><td>$ 36</td><td>$ 131</td></tr><tr><td>Commodity</td><td>Deferred credits and other noncurrent obligations</td><td>66</td><td>40</td></tr><tr><td>Total Liabilities at Fair Value</td><td></td><td>$ 102</td><td>$ 171</td></tr></table>

Consolidated Statement of Income: The Effect of Derivatives Not Designated as Hedging Instruments

<table><tr><td rowspan="2">Type of Derivative Contract</td><td rowspan="2">Statement of Income Classification</td><td colspan="3">Gain/(Loss) Year ended December 31</td></tr><tr><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Foreign Exchange</td><td>Other income</td><td>$ -</td><td>$ -</td><td>$ 26</td></tr><tr><td>Commodity</td><td>Sales and other operating revenues</td><td>(255)</td><td>(98)</td><td>(94)</td></tr><tr><td>Commodity</td><td>Purchased crude oil and products</td><td>15</td><td>(36)</td><td>(353)</td></tr><tr><td>Commodity</td><td>Other income</td><td>(2)</td><td>(1)</td><td>-</td></tr><tr><td></td><td></td><td>$ (242)</td><td>$ (135)</td><td>$ (421)</td></tr></table>

Foreign Currency The company may enter into currency derivative contracts to manage some of its foreign currency exposures. These exposures include revenue and anticipated purchase transactions, including foreign currency capital expenditures and lease commitments. The currency derivative contracts, if any, are recorded at fair value on the balance sheet with resulting gains and losses reflected in income. There were no open currency derivative contracts at December 31, 2011 or 2010.

Interest Rates The company may enter into interest rate swaps from time to time as part of its overall strategy to manage the interest rate risk on its debt. Interest rate swaps related to a portion of the company’s fixed-rate debt, if any, may be accounted for as fair value hedges. Interest rate swaps related to floating-rate debt, if any, are recorded at fair value on the balance sheet with resulting gains and losses reflected in income. At year-end 2011 and 2010, the company had no interest rate swaps.



Concentrations of Credit Risk The company’s financial instruments that are exposed to concentrations of credit risk consist primarily of its cash equivalents, time deposits, marketable securities, derivative financial instruments and trade receivables. The company’s short-term investments are placed with a wide array of financial institutions with high credit ratings. Company investment policies limit the company’s exposure both to credit risk and to concentrations of credit risk. Similar policies on diversification and creditworthiness are applied to the company’s counterparties in derivative instruments.

The trade receivable balances, reflecting the company’s diversified sources of revenue, are dispersed among the company’s broad customer base worldwide. As a result, the company believes concentrations of credit risk are limited. The company routinely assesses the financial strength of its customers. When the financial strength of a customer is not considered sufficient, requiring Letters of Credit is a principal method used to support sales to customers.

## Note 11

## Operating Segments and Geographic Data

Although each subsidiary of Chevron is responsible for its own affairs, Chevron Corporation manages its investments in these subsidiaries and their affiliates. The investments are grouped into two business segments, Upstream and Downstream, representing the company's "reportable segments" and "operating segments" as defined in accounting standards for segment reporting (ASC 280). Upstream operations consist primarily of exploring for, developing and producing crude oil and natural gas; liquefaction, transportation and regasification associated with liquefied natural gas (LNG); transporting crude oil by major international oil export pipelines; processing, transporting, storage and marketing of natural gas; and a gas-to-liquids project. Downstream operations consist primarily of refining of crude oil into petroleum products; marketing of crude oil and refined products; transporting of crude oil and refined products by pipeline, marine vessel, motor equipment and rail car; and manufacturing and marketing of commodity petrochemicals, plastics for industrial uses, and fuel and lubricant additives. All Other activities of the company include mining operations, power generation businesses, worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, energy services, alternative fuels and technology.
The segments are separately managed for investment purposes under a structure that includes “segment managers” who report to the company’s “chief operating decision maker” (CODM) (terms as defined in ASC 280). The CODM is the company’s Executive Committee (EXCOM), a committee of senior officers that includes the Chief Executive Officer, and EXCOM reports to the Board of Directors of Chevron Corporation.

The operating segments represent components of the company, as described in accounting standards for segment reporting (ASC 280), that engage in activities (a) from which revenues are earned and expenses are incurred; (b) whose operating results are regularly reviewed by the CODM, which makes decisions about resources to be allocated to the segments and assesses their performance; and (c) for which discrete financial information is available.

Segment managers for the reportable segments are directly accountable to and maintain regular contact with the company’s CODM to discuss the segment’s operating activities and financial performance. The CODM approves annual capital and exploratory budgets at the reportable segment level, as well as reviews capital and exploratory funding for major projects and approves major changes to the annual capital and exploratory budgets. However, business-unit managers within the operating segments are directly responsible for decisions relating to project implementation and all other matters connected with daily operations. Company officers who are members of the EXCOM also have individual management responsibilities and participate in other committees for purposes other than acting as the CODM.

The company’s primary country of operation is the United States of America, its country of domicile. Other components of the company’s operations are reported as “International” (outside the United States).

Segment Earnings The company evaluates the performance of its operating segments on an after-tax basis, without considering the effects of debt financing interest expense or investment interest income, both of which are managed by the company on a worldwide basis. Corporate administrative costs and assets are not allocated to the operating segments. However, operating segments are billed for the direct use of corporate services. Nonbillable costs remain at the corporate level in



Note 11 Operating Segments and Geographic Data - Continued

“All Other.” Earnings by major operating area are presented in the following table:

<table><tr><td rowspan="2"></td><td colspan="3">Year ended December 31</td></tr><tr><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Segment Earnings</td><td></td><td></td><td></td></tr><tr><td>Upstream</td><td></td><td></td><td></td></tr><tr><td>United States</td><td>$ 6,512</td><td>$ 4,122</td><td>$ 2,262</td></tr><tr><td>International</td><td>18,274</td><td>13,555</td><td>8,670</td></tr><tr><td>Total Upstream</td><td>24,786</td><td>17,677</td><td>10,932</td></tr><tr><td>Downstream</td><td></td><td></td><td></td></tr><tr><td>United States</td><td>1,506</td><td>1,339</td><td>(121)</td></tr><tr><td>International</td><td>2,085</td><td>1,139</td><td>594</td></tr><tr><td>Total Downstream</td><td>3,591</td><td>2,478</td><td>473</td></tr><tr><td>Total Segment Earnings</td><td>28,377</td><td>20,155</td><td>11,405</td></tr><tr><td>All Other</td><td></td><td></td><td></td></tr><tr><td>Interest expense</td><td>-</td><td>(41)</td><td>(22)</td></tr><tr><td>Interest income</td><td>78</td><td>70</td><td>46</td></tr><tr><td>Other</td><td>(1,560)</td><td>(1,160)</td><td>(946)</td></tr><tr><td>Net Income Attributable to Chevron Corporation</td><td>$ 26,895</td><td>$ 19,024</td><td>$ 10,483</td></tr></table>

Segment Assets Segment assets do not include intercompany investments or intercompany receivables. Segment assets at year-end 2011 and 2010 are as follows:

<table><tr><td rowspan="2"></td><td colspan="2">At December 31</td></tr><tr><td>2011</td><td>2010</td></tr><tr><td>Upstream</td><td></td><td></td></tr><tr><td>United States</td><td>$ 37,108</td><td>$ 26,319</td></tr><tr><td>International</td><td>98,540</td><td>89,306</td></tr><tr><td>Goodwill</td><td>4,642</td><td>4,617</td></tr><tr><td>Total Upstream</td><td>140,290</td><td>120,242</td></tr><tr><td>Downstream</td><td></td><td></td></tr><tr><td>United States</td><td>22,182</td><td>21,406</td></tr><tr><td>International</td><td>20,517</td><td>20,559</td></tr><tr><td>Total Downstream</td><td>42,699</td><td>41,965</td></tr><tr><td>Total Segment Assets</td><td>182,989</td><td>162,207</td></tr><tr><td>All Other*</td><td></td><td></td></tr><tr><td>United States</td><td>8,824</td><td>11,125</td></tr><tr><td>International</td><td>17,661</td><td>11,437</td></tr><tr><td>Total All Other</td><td>26,485</td><td>22,562</td></tr><tr><td>Total Assets - United States</td><td>68,114</td><td>58,850</td></tr><tr><td>Total Assets - International</td><td>136,718</td><td>121,302</td></tr><tr><td>Goodwill</td><td>4,642</td><td>4,617</td></tr><tr><td>Total Assets</td><td>$ 209,474</td><td>$ 184,769</td></tr></table>

*All Other* assets consist primarily of worldwide cash, cash equivalents, time deposits and marketable securities, real estate, energy services, information systems, mining operations, power generation businesses, alternative fuels and technology companies, and assets of the corporate administrative functions.

Segment Sales and Other Operating Revenues Operating segment sales and other operating revenues, including internal transfers, for the years 2011, 2010 and 2009, are presented in the table that follows. Products are transferred between operating segments at internal product values that approximate market prices.
Revenues for the upstream segment are derived primarily from the production and sale of crude oil and natural gas, as well as the sale of third-party production of natural gas. Revenues for the downstream segment are derived from the refining and marketing of petroleum products such as gasoline, jet fuel, gas oils, lubricants, residual fuel oils and other products derived from crude oil. This segment also generates revenues from the manufacture and sale of additives for fuels and lubricant oils and the transportation and trading of refined products, crude oil and natural gas liquids. "All Other" activities include revenues from mining operations, power generation businesses, insurance operations, real estate activities, energy services, alternative fuels and technology companies.

Other than the United States, no single country accounted for 10 percent or more of the company’s total sales and other operating revenues in 2011, 2010 and 2009.

<table><tr><td rowspan="2"></td><td colspan="3">Year ended December 31</td></tr><tr><td>2011</td><td>2010</td><td>2009*</td></tr><tr><td>Upstream</td><td></td><td></td><td></td></tr><tr><td>United States</td><td>$ 9,623</td><td>$ 10,316</td><td>$ 9,225</td></tr><tr><td>Intersegment</td><td>18,115</td><td>13,839</td><td>10,297</td></tr><tr><td>Total United States</td><td>27,738</td><td>24,155</td><td>19,522</td></tr><tr><td>International</td><td>20,086</td><td>17,300</td><td>13,463</td></tr><tr><td>Intersegment</td><td>35,012</td><td>23,834</td><td>18,477</td></tr><tr><td>Total International</td><td>55,098</td><td>41,134</td><td>31,940</td></tr><tr><td>Total Upstream</td><td>82,836</td><td>65,289</td><td>51,462</td></tr><tr><td>Downstream</td><td></td><td></td><td></td></tr><tr><td>United States</td><td>86,793</td><td>70,436</td><td>58,056</td></tr><tr><td>Excise and similar taxes</td><td>4,199</td><td>4,484</td><td>4,573</td></tr><tr><td>Intersegment</td><td>86</td><td>115</td><td>98</td></tr><tr><td>Total United States</td><td>91,078</td><td>75,035</td><td>62,727</td></tr><tr><td>International</td><td>119,254</td><td>90,922</td><td>77,845</td></tr><tr><td>Excise and similar taxes</td><td>3,886</td><td>4,107</td><td>3,536</td></tr><tr><td>Intersegment</td><td>81</td><td>93</td><td>87</td></tr><tr><td>Total International</td><td>123,221</td><td>95,122</td><td>81,468</td></tr><tr><td>Total Downstream</td><td>214,299</td><td>170,157</td><td>144,195</td></tr><tr><td>All Other</td><td></td><td></td><td></td></tr><tr><td>United States</td><td>526</td><td>610</td><td>665</td></tr><tr><td>Intersegment</td><td>1,072</td><td>947</td><td>964</td></tr><tr><td>Total United States</td><td>1,598</td><td>1,557</td><td>1,629</td></tr><tr><td>International</td><td>4</td><td>23</td><td>39</td></tr><tr><td>Intersegment</td><td>42</td><td>39</td><td>33</td></tr><tr><td>Total International</td><td>46</td><td>62</td><td>72</td></tr><tr><td>Total All Other</td><td>1,644</td><td>1,619</td><td>1,701</td></tr><tr><td>Segment Sales and Other Operating Revenues</td><td></td><td></td><td></td></tr><tr><td>United States</td><td>120,414</td><td>100,747</td><td>83,878</td></tr><tr><td>International</td><td>178,365</td><td>136,318</td><td>113,480</td></tr><tr><td>Total Segment Sales and Other Operating Revenues</td><td>298,779</td><td>237,065</td><td>197,358</td></tr><tr><td>Elimination of intersegment sales</td><td>(54,408)</td><td>(38,867)</td><td>(29,956)</td></tr><tr><td>Total Sales and Other Operating Revenues</td><td>$ 244,371</td><td>$ 198,198</td><td>$ 167,402</td></tr></table>

*2009 conformed with 2010 and 2011 presentation.



Segment Income Taxes Segment income tax expense for the years 2011, 2010 and 2009 is as follows:

<table><tr><td rowspan="2"></td><td colspan="3">Year ended December 31</td></tr><tr><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Upstream</td><td></td><td></td><td></td></tr><tr><td>United States</td><td>$ 3,701</td><td>$ 2,285</td><td>$ 1,251</td></tr><tr><td>International</td><td>16,743</td><td>10,480</td><td>7,451</td></tr><tr><td>Total Upstream</td><td>20,444</td><td>12,765</td><td>8,702</td></tr><tr><td>Downstream</td><td></td><td></td><td></td></tr><tr><td>United States</td><td>785</td><td>680</td><td>(83)</td></tr><tr><td>International</td><td>416</td><td>462</td><td>463</td></tr><tr><td>Total Downstream</td><td>1,201</td><td>1,142</td><td>380</td></tr><tr><td>All Other</td><td>(1,019)</td><td>(988)</td><td>(1,117)</td></tr><tr><td>Total Income Tax Expense</td><td>$ 20,626</td><td>$ 12,919</td><td>$ 7,965</td></tr></table>

Other Segment Information Additional information for the segmentation of major equity affiliates is contained in Note 12, beginning on page 47. Information related to properties, plant and equipment by segment is contained in Note 13, on page 49.

## Note 12

## Investments and Advances

Equity in earnings, together with investments in and advances to companies accounted for using the equity method and other investments accounted for at or below cost, is shown in the following table. For certain equity affiliates, Chevron pays its share of some income taxes directly. For such affiliates, the equity in earnings does not include these taxes, which are reported on the Consolidated Statement of Income as “Income tax expense.”

<table><tr><td rowspan="2"></td><td colspan="2">Investments and Advances</td><td colspan="2">Equity in Earnings</td></tr><tr><td colspan="2">At December 31</td><td colspan="2">Year ended December 31</td></tr><tr><td></td><td>2011</td><td>2010</td><td>2011</td><td>2010</td></tr><tr><td>Upstream</td><td></td><td></td><td></td><td></td></tr><tr><td>Tengizchevroil</td><td>$ 5,306</td><td>$ 5,789</td><td>$ 5,097</td><td>$ 3,398</td><td>$ 2,216</td></tr><tr><td>Petropiar</td><td>909</td><td>973</td><td>116</td><td>262</td><td>122</td></tr><tr><td>Caspian Pipeline Consortium</td><td>1,094</td><td>974</td><td>122</td><td>124</td><td>105</td></tr><tr><td>Petrocosan</td><td>1,032</td><td>937</td><td>247</td><td>222</td><td>171</td></tr><tr><td>Angola LNG Limited</td><td>2,921</td><td>2,481</td><td>(42)</td><td>(21)</td><td>(12)</td></tr><tr><td>Other</td><td>2,420</td><td>1,922</td><td>166</td><td>319</td><td>287</td></tr><tr><td>Total Upstream</td><td>13,682</td><td>13,076</td><td>5,706</td><td>4,304</td><td>2,889</td></tr><tr><td>Downstream</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>GS Caltex Corporation</td><td>2,572</td><td>2,496</td><td>248</td><td>158</td><td>(191)</td></tr><tr><td>Chevron Phillips Chemical</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Company LLC</td><td>2,909</td><td>2,419</td><td>985</td><td>704</td><td>328</td></tr><tr><td>Star Petroleum Refining</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Company Ltd.</td><td>1,022</td><td>947</td><td>75</td><td>122</td><td>(4)</td></tr><tr><td>Caltex Australia Ltd.</td><td>819</td><td>767</td><td>117</td><td>101</td><td>11</td></tr><tr><td>Colonial Pipeline Company</td><td>-</td><td>-</td><td>-</td><td>43</td><td>51</td></tr><tr><td>Other</td><td>630</td><td>602</td><td>183</td><td>151</td><td>149</td></tr><tr><td>Total Downstream</td><td>7,952</td><td>7,231</td><td>1,608</td><td>1,279</td><td>344</td></tr><tr><td>All Other</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Other</td><td>516</td><td>509</td><td>49</td><td>54</td><td>83</td></tr><tr><td>Total equity method</td><td>$ 22,150</td><td>$ 20,816</td><td>$ 7,363</td><td>$ 5,637</td><td>$ 3,316</td></tr><tr><td>Other at or below cost</td><td>718</td><td>704</td><td></td><td></td><td></td></tr><tr><td>Total investments and advances</td><td>$ 22,868</td><td>$ 21,520</td><td></td><td></td><td></td></tr><tr><td>Total United States</td><td>$ 4,847</td><td>$ 3,769</td><td>$ 1,119</td><td>$ 846</td><td>$ 511</td></tr><tr><td>Total International</td><td>$ 18,021</td><td>$ 17,751</td><td>$ 6,244</td><td>$ 4,791</td><td>$ 2,805</td></tr></table>

Descriptions of major affiliates, including significant differences between the company’s carrying value of its investments and its underlying equity in the net assets of the affiliates, are as follows:

Tengizchevroil Chevron has a 50 percent equity ownership interest in Tengizchevroil (TCO), a joint venture formed in 1993 to develop the Tengiz and Korolev crude oil fields in Kazakhstan over a 40-year period. At December 31, 2011, the company’s carrying value of its investment in TCO was about $180 higher than the amount of underlying equity in TCO’s net assets. This difference results from Chevron acquiring a portion of its interest in TCO at a value greater than the underlying book value for that portion of TCO’s net assets. See Note 7, on page 41, for summarized financial information for 100 percent of TCO.



Petropolitan Chevron has a 30 percent interest in Petropolitan, a joint stock company formed in 2008 to operate the Hamaca heavy-oil production and upgrading project. The project, located in Venezuela’s Orinoco Belt, has a 25-year contract term. Prior to the formation of Petropolitan, Chevron had a 30 percent interest in the Hamaca project. At December 31, 2011, the company’s carrying value of its investment in Petropolitan was approximately $180 less than the amount of underlying equity in Petropolitan’s net assets. The difference represents the excess of Chevron’s underlying equity in Petropolitan’s net assets over the net book value of the assets contributed to the venture.

Caspian Pipeline Consortium Chevron has a 15 percent interest in the Caspian Pipeline Consortium, a variable interest entity, which provides the critical export route for crude oil from both TCO and Karachaganak. The company joined the consortium in 1997 and has investments and advances totaling $1,094 which includes long-term loans of $1,111 at year-end 2011. The loans were provided to fund 30 percent of the initial pipeline construction. The company is not the primary beneficiary of the consortium because it does not direct activities of the consortium and only receives its proportionate share of the financial returns.

Petroborocan Chevron has a 39 percent interest in Petroborocan, a joint stock company formed in 2006 to operate the Boscan Field in Venezuela until 2026. Chevron previously operated the field under an operating service agreement. At December 31, 2011, the company’s carrying value of its investment in Petroborocan was approximately $220 higher than the amount of underlying equity in Petroborocan’s net assets. The difference reflects the excess of the net book value of the assets contributed by Chevron over its underlying equity in Petroborocan’s net assets.

Angola LNG Ltd. Chevron has a 36 percent interest in Angola LNG Ltd., which will process and liquefy natural gas produced in Angola for delivery to international markets.
GS Caltex Corporation Chevron owns 50 percent of GS Caltex Corporation, a joint venture with GS Holdings. The joint venture imports, refines and markets petroleum products and petrochemicals, predominantly in South Korea.

Chevron Phillips Chemical Company LLC Chevron owns 50 percent of Chevron Phillips Chemical Company LLC. The other half is owned by ConocoPhillips Corporation.

Star Petroleum Refining Company Ltd. Chevron has a 64 percent equity ownership interest in Star Petroleum Refining Company Ltd. (SPRC), which owns the Star Refinery in Thailand. PTT Public Company Limited owns the remaining 36 percent of SPRC.

Caltex Australia Ltd. Chevron has a 50 percent equity ownership interest in Caltex Australia Ltd. (CAL). The remaining 50 percent of CAL is publicly owned. At December 31, 2011, the fair value of Chevron’s share of CAL common stock was approximately $1,600.

Other Information “Sales and other operating revenues” on the Consolidated Statement of Income includes $20,164, $13,672 and $10,391 with affiliated companies for 2011, 2010 and 2009, respectively. “Purchased crude oil and products” includes $7,489, $5,559 and $4,631 with affiliated companies for 2011, 2010 and 2009, respectively.

“Accounts and notes receivable” on the Consolidated Balance Sheet includes $1,968 and $1,718 due from affiliated companies at December 31, 2011 and 2010, respectively. “Accounts payable” includes $519 and $377 due to affiliated companies at December 31, 2011 and 2010, respectively.

The following table provides summarized financial information on a 100 percent basis for all equity affiliates as well as Chevron’s total share, which includes Chevron loans to affiliates of $957, $1,543 and $2,422 at December 31, 2011, 2010 and 2009, respectively.

<table><tr><td rowspan="2">Year ended December 31</td><td colspan="4">Affiliates</td><td colspan="2">Chevron Share</td></tr><tr><td>2011</td><td>2010</td><td>2009</td><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Total revenues</td><td>$ 140,107</td><td>$107,505</td><td>$ 81,995</td><td>$ 68,632</td><td>$ 52,088</td><td>$ 39,280</td></tr><tr><td>Income before income tax expense</td><td>23,054</td><td>18,468</td><td>11,083</td><td>10,555</td><td>7,966</td><td>4,511</td></tr><tr><td>Net income attributable to affiliates</td><td>16,663</td><td>12,831</td><td>8,261</td><td>7,413</td><td>5,683</td><td>3,285</td></tr><tr><td>At December 31</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Current assets</td><td>$ 35,573</td><td>$ 30,335</td><td>$ 27,111</td><td>$ 14,695</td><td>$ 12,845</td><td>$ 11,009</td></tr><tr><td>Noncurrent assets</td><td>61,855</td><td>57,491</td><td>55,363</td><td>22,422</td><td>21,401</td><td>21,361</td></tr><tr><td>Current liabilities</td><td>24,671</td><td>20,428</td><td>17,450</td><td>11,040</td><td>9,363</td><td>7,833</td></tr><tr><td>Noncurrent liabilities</td><td>19,267</td><td>19,749</td><td>21,531</td><td>4,491</td><td>4,459</td><td>5,106</td></tr><tr><td>Total affiliates’ net equity</td><td>$ 53,490</td><td>$ 47,649</td><td>$ 43,493</td><td>$ 21,586</td><td>$ 20,424</td><td>$ 19,431</td></tr></table>



## Note 13

Properties, Plant and Equipment \( ^{1} \) 

<table><tr><td rowspan="3"></td><td colspan="6">At December 31</td><td colspan="4">Year ended December 31</td></tr><tr><td colspan="3">Gross Investment at Cost</td><td colspan="3">Net Investment</td><td colspan="2">Additions at Cost \( ^{2,3} \)</td><td colspan="2">Depreciation Expense \( ^{4} \)</td></tr><tr><td>2011</td><td>2010</td><td>2009</td><td>2011</td><td>2010</td><td>2009</td><td>2011</td><td>2010</td><td>2010</td><td>2009</td></tr><tr><td>Upstream</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>United States</td><td>$ 74,369</td><td>$ 62,523</td><td>$ 58,328</td><td>$ 33,461</td><td>$ 23,277</td><td>$ 22,273</td><td>$ 14,404</td><td>$ 4,934</td><td>$ 3,518</td><td>$ 3,870</td></tr><tr><td>International</td><td>125,795</td><td>110,578</td><td>96,557</td><td>72,543</td><td>64,388</td><td>57,450</td><td>15,722</td><td>14,381</td><td>10,803</td><td>7,590</td></tr><tr><td>Total Upstream</td><td>200,164</td><td>173,101</td><td>154,885</td><td>106,004</td><td>87,665</td><td>79,723</td><td>30,126</td><td>19,315</td><td>14,231</td><td>11,460</td></tr><tr><td>Downstream</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>United States</td><td>20,699</td><td>19,820</td><td>18,962</td><td>10,723</td><td>10,379</td><td>10,032</td><td>1,226</td><td>1,199</td><td>1,874</td><td>776</td></tr><tr><td>International</td><td>7,422</td><td>9,697</td><td>9,852</td><td>2,995</td><td>3,948</td><td>4,154</td><td>443</td><td>361</td><td>456</td><td>332</td></tr><tr><td>Total Downstream</td><td>28,121</td><td>29,517</td><td>28,814</td><td>13,718</td><td>14,327</td><td>14,186</td><td>1,669</td><td>1,560</td><td>2,330</td><td>1,108</td></tr><tr><td>All Other \( ^{5} \)</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>United States</td><td>5,117</td><td>4,722</td><td>4,569</td><td>2,872</td><td>2,496</td><td>2,548</td><td>591</td><td>259</td><td>354</td><td>338</td></tr><tr><td>International</td><td>30</td><td>27</td><td>20</td><td>14</td><td>16</td><td>11</td><td>5</td><td>11</td><td>3</td><td>5</td></tr><tr><td>Total All Other</td><td>5,147</td><td>4,749</td><td>4,589</td><td>2,886</td><td>2,512</td><td>2,559</td><td>596</td><td>270</td><td>357</td><td>343</td></tr><tr><td>Total United States</td><td>100,185</td><td>87,065</td><td>81,859</td><td>47,056</td><td>36,152</td><td>34,853</td><td>16,221</td><td>6,392</td><td>5,746</td><td>4,984</td></tr><tr><td>Total International</td><td>133,247</td><td>120,302</td><td>106,429</td><td>75,552</td><td>68,352</td><td>61,615</td><td>16,170</td><td>14,753</td><td>11,262</td><td>7,927</td></tr><tr><td>Total</td><td>$ 233,432</td><td>$ 207,367</td><td>$ 188,288</td><td>$ 122,608</td><td>$ 104,504</td><td>$ 96,468</td><td>$ 32,391</td><td>$ 21,145</td><td>$ 17,008</td><td>$ 12,911</td></tr></table>

 \( ^{1} \)  Other than the United States, Nigeria and Australia, no other country accounted for 10 percent or more of the company’s net properties, plant and equipment (PP&E) in 2011. Nigeria had PP&E of $15,601, $13,896 and $12,463 for 2011, 2010 and 2009, respectively. Australia had $12,423 in 2011.

 \( ^{2} \)  Net of dry hole expense related to prior years’ expenditures of $45, $82 and $84 in 2011, 2010 and 2009, respectively.

 \( ^{3} \)  Includes properties acquired with the acquisition of Atlas Energy, Inc. in 2011.

 \( ^{4} \)  Depreciation expense includes accretion expense of $628, $513 and $463 in 2011, 2010 and 2009, respectively.

 \( ^{5} \)  Primarily mining operations, power generation businesses, real estate assets and management information systems.

## Note 14

## Litigation

MTBE Chevron and many other companies in the petroleum industry have used methyl tertiary butyl ether (MTBE) as a gasoline additive. Chevron is a party to eight pending lawsuits and claims, the majority of which involve numerous other petroleum marketers and refiners. Resolution of these lawsuits and claims may ultimately require the company to correct or ameliorate the alleged effects on the environment of prior release of MTBE by the company or other parties. Additional lawsuits and claims related to the use of MTBE, including personal-injury claims, may be filed in the future. The company’s ultimate exposure related to pending lawsuits and claims is not determinable, but could be material to net income in any one period. The company no longer uses MTBE in the manufacture of gasoline in the United States.

Ecuador Chevron is a defendant in a civil lawsuit before the Superior Court of Nueva Loja in Lago Agrio, Ecuador, brought in May 2003 by plaintiffs who claim to be representatives of certain residents of an area where an oil production consortium formerly had operations. The lawsuit alleges damage to the environment from the oil exploration and production operations and seeks unspecified damages to fund environmental remediation and restoration of the alleged environmental harm, plus a health monitoring program. Until 1992, Texaco Petroleum Company (Texpet), a subsidiary of Texaco Inc., was a minority member of this consortium with Petroecuador, the Ecuadorian state-owned oil company, as the majority partner; since 1990, the operations have been conducted solely by Petroecuador. At the conclusion of the consortium and following an independent third-party environmental audit of the concession area, Texpet entered into a formal agreement with the Republic of Ecuador and Petroecuador for Texpet to remediate specific sites assigned by the government in proportion to Texpet's ownership share of the consortium. Pursuant to that agreement, Texpet conducted a three-year remediation program at a cost of $40. After certifying that the sites were properly remediated, the government granted Texpet and all related corporate entities a full release from any and all environmental liability arising from the consortium operations.

Based on the history described above, Chevron believes that this lawsuit lacks legal or factual merit. As to matters of law, the company believes first, that the court lacks jurisdiction over Chevron; second, that the law under which plaintiffs bring the action, enacted in 1999, cannot be applied retroactively; third, that the claims are barred by the statute of limitations in Ecuador; and, fourth, that the lawsuit is also barred by the releases from liability previously given to Texpet by the Republic of Ecuador and Petroecuador and by the pertinent provincial and municipal governments. With regard to the facts, the company believes that the evidence confirms that Texpet’s remediation was properly conducted and that the



remaining environmental damage reflects Petroecuador’s failure to timely fulfill its legal obligations and Petroecuador’s further conduct since assuming full control over the operations.

In 2008, a mining engineer appointed by the court to identify and determine the cause of environmental damage, and to specify steps needed to remediate it, issued a report recommending that the court assess $18,900, which would, according to the engineer, provide financial compensation for purported damages, including wrongful death claims, and pay for, among other items, environmental remediation, health care systems and additional infrastructure for Petroecuador. The engineer's report also asserted that an additional $8,400 could be assessed against Chevron for unjust enrichment. In 2009, following the disclosure by Chevron of evidence that the judge participated in meetings in which businesspeople and individuals holding themselves out as government officials discussed the case and its likely outcome, the judge presiding over the case was recused. In 2010, Chevron moved to strike the mining engineer's report and to dismiss the case based on evidence obtained through discovery in the United States indicating that the report was prepared by consultants for the plaintiffs before being presented as the mining engineer's independent and impartial work and showing further evidence of misconduct. In August 2010, the judge issued an order stating that he was not bound by the mining engineer's report and requiring the parties to provide their positions on damages within 45 days. Chevron subsequently petitioned for recusal of the judge, claiming that he had disregarded evidence of fraud and misconduct and that he had failed to rule on a number of motions within the statutory time requirement.

In September 2010, Chevron submitted its position on damages, asserting that no amount should be assessed against it. The plaintiffs’ submission, which relied in part on the mining engineer’s report, took the position that damages are between approximately $16,000 and $76,000 and that unjust enrichment should be assessed in an amount between approximately $5,000 and $38,000. The next day, the judge issued an order closing the evidentiary phase of the case and notifying the parties that he had requested the case file so that he could prepare a judgment. Chevron petitioned to have that order declared a nullity in light of Chevron’s prior recusal petition, and because procedural and evidentiary matters remained unresolved. In October 2010, Chevron’s motion to recuse the judge was granted. A new judge took charge of the case and revoked the prior judge’s order closing the evidentiary phase of the case. On December 17, 2010, the judge issued an order closing the evidentiary phase of the case and notifying the parties that he had requested the case file so that he could prepare a judgment.

On February 14, 2011, the provincial court in Lago Agrio rendered an adverse judgment in the case. The court rejected Chevron’s defenses to the extent the court addressed them in its opinion. The judgment assessed approximately $8,600 in damages and approximately $900 as an award for the plaintiffs’ representatives. It also assessed an additional amount of approximately $8,600 in punitive damages unless the company issued a public apology within 15 days of the judgment, which Chevron did not do. On February 17, 2011, the plaintiffs appealed the judgment, seeking increased damages, and on March 11, 2011, Chevron appealed the judgment seeking to have the judgment nullified. On January 3, 2012, an appellate panel in the provincial court affirmed the February 14, 2011, decision and ordered that Chevron pay additional attorneys’ fees in the amount of “.10% of the values that are derived from the decisional act of this judgment.” The plaintiffs filed a petition to clarify and amplify the appellate decision on January 6, 2012, and the court issued a ruling in response on January 13, 2012, purporting to clarify and amplify its January 3, 2012 ruling, which included clarification that the deadline for the company to issue a public apology to avoid the additional amount of approximately $8,600 in punitive damages was within 15 days of the clarification ruling, or February 3, 2012. Chevron did not issue an apology because doing so might be mischaracterized as an admission of liability and would be contrary to facts and evidence submitted at trial. On January 20, 2012, Chevron appealed (called a petition for cassation) the appellate panel’s decision to Ecuador’s National Court of Justice. As part of the appeal, Chevron requested the suspension of any requirement that Chevron post a bond to prevent enforcement under Ecuadorian law of the judgment during the cassation appeal. On February 17, 2012, the appellate panel of the provincial court admitted Chevron’s cassation appeal in a procedural step necessary for the National Court of Justice to hear the appeal. The provincial court appellate panel denied Chevron’s request for suspension of the requirement that Chevron post a bond and stated that it would not comply with the first Interim Award of the international arbitration tribunal discussed below. Chevron continues to believe the provincial court’s judgment is illegitimate and unenforceable in Ecuador, the United States and other countries. The company also believes the judgment is the product of fraud, and contrary to the legitimate scientific evidence. Chevron cannot predict the timing or ultimate outcome of the appeals process in Ecuador. Chevron will continue a vigorous defense of any imposition of liability. Chevron has no assets in Ecuador and the Lago Agrio plaintiffs’ lawyers have stated in press releases and through other media that they will seek to enforce the Ecuadorian judgment in various countries and otherwise disrupt Chevron’s operations. Chevron expects to contest and defend against any such actions.



Chevron and Texpet filed an arbitration claim in September 2009 against the Republic of Ecuador before an arbitral tribunal presiding in the Permanent Court of Arbitration in The Hague under the Rules of the United Nations Commission on International Trade Law. The claim alleges violations of the Republic of Ecuador’s obligations under the United States–Ecuador Bilateral Investment Treaty (BIT) and breaches of the settlement and release agreements between the Republic of Ecuador and Texpet (described above), which are investment agreements protected by the BIT. Through the arbitration, Chevron and Texpet are seeking relief against the Republic of Ecuador, including a declaration that any judgment against Chevron in the Lago Agrio litigation constitutes a violation of Ecuador’s obligations under the BIT. On February 9, 2011, the Tribunal issued an Order for Interim Measures requiring the Republic of Ecuador to take all measures at its disposal to suspend or cause to be suspended the enforcement or recognition within and without Ecuador of any judgment against Chevron in the Lago Agrio case pending further order of the Tribunal. On January 25, 2012, the Tribunal converted the Order for Interim Measures into an Interim Award. Chevron filed a renewed application for further interim measures on January 4, 2012, and the Republic of Ecuador opposed Chevron’s application and requested that the existing Order for Interim Measures be vacated on January 9, 2012. On February 16, 2012, the Tribunal issued a second Interim Award mandating that the Republic of Ecuador take all measures necessary (whether by its judicial, legislative or executive branches) to suspend or cause to be suspended the enforcement and recognition within and without Ecuador of the judgment against Chevron and, in particular, to preclude any certification by the Republic of Ecuador that would cause the judgment to be enforceable against Chevron. Chevron expects to continue seeking permanent injunctive relief and monetary relief before the Tribunal.

Through a series of recent U.S. court proceedings initiated by Chevron to obtain discovery relating to the Lago Agrio litigation and the BIT arbitration, Chevron has obtained evidence that it believes shows a pattern of fraud, collusion, corruption, and other misconduct on the part of several lawyers, consultants and others acting for the Lago Agrio plaintiffs. In February 2011, Chevron filed a civil lawsuit in the Federal District Court for the Southern District of New York against the Lago Agrio plaintiffs and several of their lawyers, consultants and supporters, alleging violations of the Racketeer Influenced and Corrupt Organizations Act and other state laws. Through the civil lawsuit, Chevron is seeking relief that includes an award of damages and a declaration that any judgment against Chevron in the Lago Agrio litigation is the result of fraud and other unlawful conduct and is therefore unenforceable. On March 7, 2011, the Federal District Court issued a preliminary injunction prohibiting the Lago Agrio plaintiffs and persons acting in concert with them from taking any action in furtherance of recognition or enforcement of any judgment against Chevron in the Lago Agrio case pending resolution of Chevron’s civil lawsuit by the Federal District Court. On May 31, 2011, the Federal District Court severed claims one through eight of Chevron’s complaint from the ninth claim for declaratory relief and imposed a discovery stay on claims one through eight pending a trial on the ninth claim for declaratory relief. On September 19, 2011, the U.S. Court of Appeals for the Second Circuit vacated the preliminary injunction, stayed the trial on Chevron’s ninth claim, a claim for declaratory relief, that had been set for November 14, 2011, and denied the defendants’ mandamus petition to recuse the judge hearing the lawsuit. The Second Circuit issued its opinion on January 26, 2012 ordering the dismissal of Chevron’s ninth claim for declaratory relief. On February 16, 2012, the Federal District Court lifted the stay on claims one through eight.

The ultimate outcome of the foregoing matters, including any financial effect on Chevron, remains uncertain. Management does not believe an estimate of a reasonably possible loss (or a range of loss) can be made in this case. Due to the defects associated with the Ecuadorian judgment, the 2008 engineer’s report on alleged damages and the September 2010 plaintiffs’ submission on alleged damages, management does not believe these documents have any utility in calculating a reasonably possible loss (or a range of loss). Moreover, the highly uncertain legal environment surrounding the case provides no basis for management to estimate a reasonably possible loss (or a range of loss).

## Note 15

Taxes

Income Taxes

<table><tr><td rowspan="2"></td><td colspan="3">Year ended December 31</td></tr><tr><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Taxes on income</td><td></td><td></td><td></td></tr><tr><td>U.S. Federal</td><td></td><td></td><td></td></tr><tr><td>Current</td><td>$ 1,893</td><td>$ 1,501</td><td>$ 128</td></tr><tr><td>Deferred</td><td>877</td><td>162</td><td>(147)</td></tr><tr><td>State and local</td><td></td><td></td><td></td></tr><tr><td>Current</td><td>596</td><td>376</td><td>216</td></tr><tr><td>Deferred</td><td>41</td><td>20</td><td>14</td></tr><tr><td>Total United States</td><td>3,407</td><td>2,059</td><td>211</td></tr><tr><td>International</td><td></td><td></td><td></td></tr><tr><td>Current</td><td>16,548</td><td>10,483</td><td>7,154</td></tr><tr><td>Deferred</td><td>671</td><td>377</td><td>600</td></tr><tr><td>Total International</td><td>17,219</td><td>10,860</td><td>7,754</td></tr><tr><td>Total taxes on income</td><td>$ 20,626</td><td>$ 12,919</td><td>$ 7,965</td></tr></table>

In 2011, before-tax income for U.S. operations, including related corporate and other charges, was $10,222, compared



with before-tax income of $6,528 and $1,310 in 2010 and 2009, respectively. For international operations, before-tax income was $37,412, $25,527 and $17,218 in 2011, 2010 and 2009, respectively. U.S. federal income tax expense was reduced by $191, $162 and $204 in 2011, 2010 and 2009, respectively, for business tax credits.

The reconciliation between the U.S. statutory federal income tax rate and the company’s effective income tax rate is detailed in the following table:

<table><tr><td rowspan="2"></td><td colspan="3">Year ended December 31</td></tr><tr><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>U.S. statutory federal income tax rate</td><td>35.0%</td><td>35.0%</td><td>35.0%</td></tr><tr><td>Effect of income taxes from international operations at rates different from the U.S. statutory rate</td><td>7.5</td><td>5.2</td><td>10.4</td></tr><tr><td>State and local taxes on income, net of U.S. federal income tax benefit</td><td>0.9</td><td>0.8</td><td>0.9</td></tr><tr><td>Prior year tax adjustments</td><td>(0.1)</td><td>(0.6)</td><td>(0.3)</td></tr><tr><td>Tax credits</td><td>(0.4)</td><td>(0.5)</td><td>(1.1)</td></tr><tr><td>Effects of changes in tax rates</td><td>0.5</td><td>—</td><td>0.1</td></tr><tr><td>Other</td><td>(0.1)</td><td>0.4</td><td>(2.0)</td></tr><tr><td>Effective tax rate</td><td>43.3%</td><td>40.3%</td><td>43.0%</td></tr></table>

The company’s effective tax rate increased from 40.3 percent in 2010 to 43.3 percent in 2011. This increase primarily reflected higher effective tax rates in international upstream jurisdictions. The higher international upstream effective tax rates were driven primarily by lower utilization of non-U.S. tax credits in 2011 and the effect of changes in income tax rates between periods, which were partially offset by foreign currency remeasurement impacts between periods.

The company records its deferred taxes on a tax-jurisdiction basis and classifies those net amounts as current or noncurrent based on the balance sheet classification of the related assets or liabilities. The reported deferred tax balances are composed of the following:

<table><tr><td rowspan="2"></td><td colspan="2">At December 31</td></tr><tr><td>2011</td><td>2010</td></tr><tr><td>Deferred tax liabilities</td><td></td><td></td></tr><tr><td>Properties, plant and equipment</td><td>$ 23,597</td><td>$ 19,855</td></tr><tr><td>Investments and other</td><td>2,271</td><td>2,401</td></tr><tr><td>Total deferred tax liabilities</td><td>25,868</td><td>22,256</td></tr><tr><td>Deferred tax assets</td><td></td><td></td></tr><tr><td>Foreign tax credits</td><td>(8,476)</td><td>(6,669)</td></tr><tr><td>Abandonment/environmental reserves</td><td>(5,387)</td><td>(5,004)</td></tr><tr><td>Employee benefits</td><td>(4,773)</td><td>(3,627)</td></tr><tr><td>Deferred credits</td><td>(1,548)</td><td>(2,176)</td></tr><tr><td>Tax loss carryforwards</td><td>(828)</td><td>(882)</td></tr><tr><td>Other accrued liabilities</td><td>(531)</td><td>(486)</td></tr><tr><td>Inventory</td><td>(360)</td><td>(483)</td></tr><tr><td>Miscellaneous</td><td>(1,595)</td><td>(1,676)</td></tr><tr><td>Total deferred tax assets</td><td>(23,498)</td><td>(21,003)</td></tr><tr><td>Deferred tax assets valuation allowance</td><td>11,096</td><td>9,185</td></tr><tr><td>Total deferred taxes, net</td><td>$ 13,466</td><td>$ 10,438</td></tr></table>

Deferred tax liabilities at the end of 2011 increased by approximately $3,600 from year-end 2010. The increase was related to increased temporary differences for property, plant and equipment.

Deferred tax assets increased by approximately $2,500 in 2011. Increases primarily related to additional foreign tax credits arising from earnings in high-tax-rate international jurisdictions (which were substantially offset by valuation allowances) and to increased temporary differences for employee benefits. These effects were partially offset by reductions in deferred credits resulting primarily from the usage of tax benefits in international tax jurisdictions.

The overall valuation allowance relates to deferred tax assets for foreign tax credit carryforwards, tax loss carryforwards and temporary differences. It reduces the deferred tax assets to amounts that are, in management’s assessment, more likely than not to be realized. At the end of 2011, tax loss carryforwards were approximately $2,160, primarily related to various international tax jurisdictions. Whereas some of these tax loss carryforwards do not have an expiration date, others expire at various times from 2012 through 2036. Foreign tax credit carryforwards of $8,476 will expire between 2012 and 2021.

At December 31, 2011 and 2010, deferred taxes were classified on the Consolidated Balance Sheet as follows:

<table><tr><td rowspan="2"></td><td colspan="2">At December 31</td></tr><tr><td>2011</td><td>2010</td></tr><tr><td>Prepaid expenses and other current assets</td><td>$ (1,149)</td><td>$ (1,624)</td></tr><tr><td>Deferred charges and other assets</td><td>(1,224)</td><td>(851)</td></tr><tr><td>Federal and other taxes on income</td><td>295</td><td>216</td></tr><tr><td>Noncurrent deferred income taxes</td><td>15,544</td><td>12,697</td></tr><tr><td>Total deferred income taxes, net</td><td>$ 13,466</td><td>$ 10,438</td></tr></table>

Income taxes are not accrued for unremitted earnings of international operations that have been or are intended to be reinvested indefinitely. Undistributed earnings of international consolidated subsidiaries and affiliates for which no deferred income tax provision has been made for possible future remittances totaled $24,376 at December 31, 2011. This amount represents earnings reinvested as part of the company’s ongoing international business. It is not practicable to estimate the amount of taxes that might be payable on the possible remittance of earnings that are intended to be reinvested indefinitely. At the end of 2011, deferred income taxes were recorded for the undistributed earnings of certain international operations where indefinite reinvestment of the earnings is not planned. The company does not anticipate incurring significant additional taxes on remittances of earnings that are not indefinitely reinvested.



Uncertain Income Tax Positions Under accounting standards for uncertainty in income taxes (ASC 740-10), a company recognizes a tax benefit in the financial statements for an uncertain tax position only if management’s assessment is that the position is “more likely than not” (i.e., a likelihood greater than 50 percent) to be allowed by the tax jurisdiction based solely on the technical merits of the position. The term “tax position” in the accounting standards for income taxes refers to a position in a previously filed tax return or a position expected to be taken in a future tax return that is reflected in measuring current or deferred income tax assets and liabilities for interim or annual periods.

The following table indicates the changes to the company’s unrecognized tax benefits for the years ended December 31, 2011, 2010 and 2009. The term “unrecognized tax benefits” in the accounting standards for income taxes refers to the differences between a tax position taken or expected to be taken in a tax return and the benefit measured and recognized in the financial statements. Interest and penalties are not included.

<table><tr><td></td><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Balance at January 1</td><td>$ 3,507</td><td>$ 3,195</td><td>$ 2,696</td></tr><tr><td>Foreign currency effects</td><td>(2)</td><td>17</td><td>(1)</td></tr><tr><td>Additions based on tax positions taken in current year</td><td>469</td><td>334</td><td>459</td></tr><tr><td>Reductions based on tax positions taken in current year</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Additions/reductions resulting from current-year asset acquisitions/sales</td><td>(41)</td><td>-</td><td>-</td></tr><tr><td>Additions for tax positions taken in prior years</td><td>236</td><td>270</td><td>533</td></tr><tr><td>Reductions for tax positions taken in prior years</td><td>(366)</td><td>(165)</td><td>(182)</td></tr><tr><td>Settlements with taxing authorities in current year</td><td>(318)</td><td>(136)</td><td>(300)</td></tr><tr><td>Reductions as a result of a lapse of the applicable statute of limitations</td><td>(4)</td><td>(8)</td><td>(10)</td></tr><tr><td>Balance at December 31</td><td>$ 3,481</td><td>$ 3,507</td><td>$ 3,195</td></tr></table>

Approximately 80 percent of the $3,481 of unrecognized tax benefits at December 31, 2011, would have an impact on the effective tax rate if subsequently recognized. Certain of these unrecognized tax benefits relate to tax carryforwards that may require a full valuation allowance at the time of any such recognition.

Tax positions for Chevron and its subsidiaries and affiliates are subject to income tax audits by many tax jurisdictions throughout the world. For the company’s major tax jurisdictions, examinations of tax returns for certain prior tax years had not been completed as of December 31, 2011. For these jurisdictions, the latest years for which income tax examinations had been finalized were as follows: United States – 2007, Nigeria – 2000, Angola – 2001, Saudi Arabia – 2003 and Kazakhstan – 2005.

The company engages in ongoing discussions with tax authorities regarding the resolution of tax matters in the various jurisdictions. Both the outcome of these tax matters and the timing of resolution and/or closure of the tax audits are highly uncertain. However, it is reasonably possible that developments on tax matters in certain tax jurisdictions may result in significant increases or decreases in the company’s total unrecognized tax benefits within the next 12 months. Given the number of years that still remain subject to examination and the number of matters being examined in the various tax jurisdictions, the company is unable to estimate the range of possible adjustments to the balance of unrecognized tax benefits.

On the Consolidated Statement of Income, the company reports interest and penalties related to liabilities for uncertain tax positions as “Income tax expense.” As of December 31, 2011, accruals of $118 for anticipated interest and penalty obligations were included on the Consolidated Balance Sheet, compared with accruals of $225 as of year-end 2010. Income tax expense (benefit) associated with interest and penalties was $(64), $40 and $(20) in 2011, 2010 and 2009, respectively.

## Taxes Other Than on Income

<table><tr><td rowspan="2"></td><td colspan="3">Year ended December 31</td></tr><tr><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>United States</td><td></td><td></td><td></td></tr><tr><td>Excise and similar taxes on products and merchandise</td><td>$ 4,199</td><td>$ 4,484</td><td>$ 4,573</td></tr><tr><td>Import duties and other levies</td><td>4</td><td>-</td><td>(4)</td></tr><tr><td>Property and other miscellaneous taxes</td><td>726</td><td>567</td><td>584</td></tr><tr><td>Payroll taxes</td><td>236</td><td>219</td><td>223</td></tr><tr><td>Taxes on production</td><td>308</td><td>271</td><td>135</td></tr><tr><td>Total United States</td><td>5,473</td><td>5,541</td><td>5,511</td></tr><tr><td>International</td><td></td><td></td><td></td></tr><tr><td>Excise and similar taxes on products and merchandise</td><td>3,886</td><td>4,107</td><td>3,536</td></tr><tr><td>Import duties and other levies</td><td>3,511</td><td>6,183</td><td>6,550</td></tr><tr><td>Property and other miscellaneous taxes</td><td>2,354</td><td>2,000</td><td>1,740</td></tr><tr><td>Payroll taxes</td><td>148</td><td>133</td><td>134</td></tr><tr><td>Taxes on production</td><td>256</td><td>227</td><td>120</td></tr><tr><td>Total International</td><td>10,155</td><td>12,650</td><td>12,080</td></tr><tr><td>Total taxes other than on income</td><td>$ 15,628</td><td>$ 18,191</td><td>$ 17,591</td></tr></table>



## Note 16

Short-Term Debt

<table><tr><td rowspan="2"></td><td colspan="2">At December 31</td></tr><tr><td>2011</td><td>2010</td></tr><tr><td>Commercial paper*</td><td>$ 2,498</td><td>$ 2,471</td></tr><tr><td>Notes payable to banks and others with originating terms of one year or less</td><td>40</td><td>43</td></tr><tr><td>Current maturities of long-term debt</td><td>17</td><td>33</td></tr><tr><td>Current maturities of long-term capital leases</td><td>54</td><td>81</td></tr><tr><td>Redeemable long-term obligations</td><td></td><td></td></tr><tr><td>Long-term debt</td><td>3,317</td><td>2,943</td></tr><tr><td>Capital leases</td><td>14</td><td>16</td></tr><tr><td>Subtotal</td><td>5,940</td><td>5,587</td></tr><tr><td>Reclassified to long-term debt</td><td>(5,600)</td><td>(5,400)</td></tr><tr><td>Total short-term debt</td><td>$ 340</td><td>$ 187</td></tr></table>

*Weighted-average interest rates at December 31, 2011 and 2010, were 0.04 percent and 0.16 percent, respectively.

Redeemable long-term obligations consist primarily of tax-exempt variable-rate put bonds that are included as current liabilities because they become redeemable at the option of the bondholders during the year following the balance sheet date. In 2011, $374 of tax-exempt bonds related to projects at the Pascagoula, Mississippi, refinery were issued.

The company may periodically enter into interest rate swaps on a portion of its short-term debt. At December 31, 2011, the company had no interest rate swaps on short-term debt.

At December 31, 2011, the company had $6,000 in committed credit facilities with various major banks, expiring in December 2016, that enable the refinancing of short-term obligations on a long-term basis. These facilities support commercial paper borrowing and can also be used for general corporate purposes. The company's practice has been to continually replace expiring commitments with new commitments on substantially the same terms, maintaining levels management believes appropriate. Any borrowings under the facilities would be unsecured indebtedness at interest rates based on the London Interbank Offered Rate or an average of base lending rates published by specified banks and on terms reflecting the company's strong credit rating. No borrowings were outstanding under these facilities at December 31, 2011.

At December 31, 2011 and 2010, the company classified $5,600 and $5,400, respectively, of short-term debt as long-term. Settlement of these obligations is not expected to require the use of working capital within one year, as the company has both the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis.

## Note 17

Long-Term Debt

Total long-term debt, excluding capital leases, at December 31, 2011, was $9,684. The company's long-term debt outstanding at year-end 2011 and 2010 was as follows:

<table><tr><td rowspan="2"></td><td colspan="2">At December 31</td></tr><tr><td>2011</td><td>2010</td></tr><tr><td>3.95% notes due 2014</td><td>$ 1,998</td><td>$ 1,998</td></tr><tr><td>3.45% notes due 2012</td><td>-</td><td>1,500</td></tr><tr><td>4.95% notes due 2019</td><td>1,500</td><td>1,500</td></tr><tr><td>8.625% debentures due 2032</td><td>147</td><td>147</td></tr><tr><td>8.625% debentures due 2031</td><td>107</td><td>107</td></tr><tr><td>7.5% debentures due 2043</td><td>83</td><td>83</td></tr><tr><td>8% debentures due 2032</td><td>74</td><td>74</td></tr><tr><td>7.327% amortizing notes due 2014 \( ^{1} \)</td><td>59</td><td>72</td></tr><tr><td>9.75% debentures due 2020</td><td>54</td><td>54</td></tr><tr><td>8.875% debentures due 2021</td><td>40</td><td>40</td></tr><tr><td>Medium-term notes, maturing from 2021 to 2038 (6.02%) \( ^{2} \)</td><td>38</td><td>38</td></tr><tr><td>Fixed interest rate notes, maturing 2011 (9.378%) \( ^{2} \)</td><td>-</td><td>19</td></tr><tr><td>Other long-term debt (8.07%) \( ^{2} \)</td><td>1</td><td>4</td></tr><tr><td>Total including debt due within one year</td><td>4,101</td><td>5,636</td></tr><tr><td>Debt due within one year</td><td>(17)</td><td>(33)</td></tr><tr><td>Reclassified from short-term debt</td><td>5,600</td><td>5,400</td></tr><tr><td>Total long-term debt</td><td>$ 9,684</td><td>$ 11,003</td></tr></table>

 \( ^{1} \)  Guarantee of ESOP debt.

 \( ^{2} \)  Weighted-average interest rate at December 31, 2011 and 2010.

In March 2010, the company filed with the SEC an automatic registration statement that expires on February 28, 2013. This registration statement is for an unspecified amount of non-convertible debt securities issued or guaranteed by the company.

Long-term debt of $4,101 matures as follows: 2012 – $17; 2013 – $20; 2014 – $2,021; 2015 – $0; 2016 – $0; and after 2016 – $2,043.

In September 2011, $1,500 of Chevron Corp. bonds were redeemed early. In June 2010, $30 of Texaco Capital Inc. bonds matured.

See Note 9, beginning on page 42, for information concerning the fair value of the company’s long-term debt.



## Note 18

New Accounting Standards

Fair Value Measurement (Topic 820), Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS (ASU 2011-04) In May 2011, the FASB issued ASU 2011-04, which becomes effective for the company on January 1, 2012. The amendments in ASU 2011-04 result in common fair value measurement and disclosure requirements in U.S. GAAP and IFRS. As a result of these amendments, the requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements were changed. The company does not anticipate changes to its existing classification and measurement of fair value when the amended standard becomes effective. However, the company’s disclosures on certain items not required to be measured at fair value are expected to be expanded when the amended standard becomes effective.

Comprehensive Income (Topic 220) Presentation of Comprehensive Income (ASU 2011-05) The FASB issued ASU 2011-05 in June 2011. This standard becomes effective for the company on January 1, 2012. ASU 2011-05 changes the presentation requirements for comprehensive income. Adoption of the standard is not expected to have a significant impact on the company’s current financial statement presentation.

Intangibles—Goodwill and Other (Topic 350) Testing Goodwill for Impairment (ASU 2011-08) In September 2011, the FASB issued ASU 2011-08, which becomes effective for the company on January 1, 2012. The standard simplifies how companies test goodwill for impairment. The company does not anticipate any impact to its results of operations, financial position or liquidity when the guidance becomes effective.

## Note 19

Accounting for Suspended Exploratory Wells

Accounting standards for the costs of exploratory wells (ASC 932) provide that exploratory well costs continue to be capitalized after the completion of drilling when (a) the well has found a sufficient quantity of reserves to justify completion as a producing well and (b) the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met or if an enterprise obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well would be assumed to be impaired, and its costs, net of any salvage value, would be charged to expense. (Note that an entity is not required to complete the exploratory well as a producing well.) The accounting standards provide a number of indicators that can assist an entity in demonstrating that sufficient progress is being made in assessing the reserves and economic viability of the project. The following table indicates the changes to the company’s suspended exploratory well costs for the three years ended December 31, 2011:

<table><tr><td></td><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Beginning balance at January 1</td><td>$ 2,718</td><td>$ 2,435</td><td>$ 2,118</td></tr><tr><td>Additions to capitalized exploratory well costs pending the determination of proved reserves</td><td>652</td><td>482</td><td>663</td></tr><tr><td>Reclassifications to wells, facilities and equipment based on the determination of proved reserves</td><td>(828)</td><td>(129)</td><td>(174)</td></tr><tr><td>Capitalized exploratory well costs charged to expense</td><td>(45)</td><td>(70)</td><td>(172)</td></tr><tr><td>Other reductions*</td><td>(63)</td><td>-</td><td>-</td></tr><tr><td>Ending balance at December 31</td><td>$ 2,434</td><td>$ 2,718</td><td>$ 2,435</td></tr></table>

 \( ^{*} \) Represents property sales.

The following table provides an aging of capitalized well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling.

<table><tr><td rowspan="2"></td><td colspan="3">At December 31</td></tr><tr><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Exploratory well costs capitalized for a period of one year or less</td><td>$ 557</td><td>$ 419</td><td>$ 564</td></tr><tr><td>Exploratory well costs capitalized for a period greater than one year</td><td>1,877</td><td>2,299</td><td>1,871</td></tr><tr><td>Balance at December 31</td><td>$ 2,434</td><td>$ 2,718</td><td>$ 2,435</td></tr><tr><td>Number of projects with exploratory well costs that have been capitalized for a period greater than one year*</td><td>47</td><td>53</td><td>46</td></tr></table>

 \( ^{*} \) Certain projects have multiple wells or fields or both.

Of the $1,877 of exploratory well costs capitalized for more than one year at December 31, 2011, $939 (26 projects) is related to projects that had drilling activities under way or firmly planned for the near future. The $938 balance is related to 21 projects in areas requiring a major capital expenditure before production could begin and for which additional drilling efforts were not under way or firmly planned for the near future. Additional drilling was not deemed necessary because the presence of hydrocarbons had already been established, and other activities were in process to enable a future decision on project development.

The projects for the $938 referenced above had the following activities associated with assessing the reserves and the projects’ economic viability: (a) $322 (six projects) – development alternatives under review; (b) $283 (five projects) – development concept under review by government; (c) $208 (seven projects) – undergoing front-end engineering and design with final investment decision expected within three years; (d) $111 (one project) – project sanction approved and



construction is in progress, with initial recognition of proved reserves expected upon reaching “economic producibility” per SEC guidelines; (e) $14 – miscellaneous activities for two projects with smaller amounts suspended. While progress was being made on all 47 projects, the decision on the recognition of proved reserves under SEC rules in some cases may not occur for several years because of the complexity, scale and negotiations connected with the projects. The majority of these decisions are expected to occur in the next three years.

The $1,877 of suspended well costs capitalized for a period greater than one year as of December 31, 2011, represents 161 exploratory wells in 47 projects. The tables below contain the aging of these costs on a well and project basis:

<table><tr><td>Aging based on drilling completion date of individual wells:</td><td>Amount</td><td>Number of wells</td></tr><tr><td>1997-2000</td><td>$ 49</td><td>16</td></tr><tr><td>2001-2005</td><td>396</td><td>47</td></tr><tr><td>2006-2010</td><td>1,432</td><td>98</td></tr><tr><td>Total</td><td>$ 1,877</td><td>161</td></tr></table>

<table><tr><td>Aging based on drilling completion date of last suspended well in project:</td><td>Amount</td><td>Number of projects</td></tr><tr><td>1999</td><td>$ 8</td><td>1</td></tr><tr><td>2003-2006</td><td>345</td><td>10</td></tr><tr><td>2007-2011</td><td>1,524</td><td>36</td></tr><tr><td>Total</td><td>$ 1,877</td><td>47</td></tr></table>

## Note 20

## Stock Options and Other Share-Based Compensation

Compensation expense for stock options for 2011, 2010 and 2009 was $265 ($172 after tax), $229 ($149 after tax) and $182 ($119 after tax), respectively. In addition, compensation expense for stock appreciation rights, restricted stock, performance units and restricted stock units was $214 ($139 after tax), $194 ($126 after tax) and $170 ($110 after tax) for 2011, 2010 and 2009, respectively. No significant stock-based compensation cost was capitalized at December 31, 2011 and 2010.

Cash received in payment for option exercises under all share-based payment arrangements for 2011, 2010 and 2009 was $948, $385 and $147, respectively. Actual tax benefits realized for the tax deductions from option exercises were $121, $66 and $25 for 2011, 2010 and 2009, respectively.
Cash paid to settle performance units and stock appreciation rights was $151, $140 and $89 for 2011, 2010 and 2009, respectively.

Chevron Long-Term Incentive Plan (LTIP) Awards under the LTIP may take the form of, but are not limited to, stock options, restricted stock, restricted stock units, stock appreciation rights, performance units and nonstock grants. From April 2004 through January 2014, no more than 160 million shares may be issued under the LTIP, and no more than 64 million of those shares may be in a form other than a stock option, stock appreciation right or award requiring full payment for shares by the award recipient. For the major types of awards outstanding as of December 31, 2011, the contractual terms vary between three years for the performance units and 10 years for the stock options and stock appreciation rights.

Texaco Stock Incentive Plan (Texaco SIP) On the closing of the acquisition of Texaco in October 2001, outstanding options granted under the Texaco SIP were converted to Chevron options. These options, which had 10-year contractual lives extending into 2011, retained a provision for being restored. This provision enabled a participant who exercised a stock option to receive new options equal to the number of shares exchanged or who had shares withheld to satisfy tax withholding obligations to receive new options equal to the number of shares exchanged or withheld. The restored options were fully exercisable six months after the date of grant, and the exercise price was the market value of the common stock on the day the restored option was granted. Beginning in 2007, restored options were issued under the LTIP. No further awards may be granted under the former Texaco plans.

Unocal Share-Based Plans (Unocal Plans) When Chevron acquired Unocal in August 2005, outstanding stock options and stock appreciation rights granted under various Unocal Plans were exchanged for fully vested Chevron options and appreciation rights. These awards retained the same provisions as the original Unocal Plans. Unexercised awards began expiring in early 2010 and will continue to expire through early 2015.



The fair market values of stock options and stock appreciation rights granted in 2011, 2010 and 2009 were measured on the date of grant using the Black-Scholes option-pricing model, with the following weighted-average assumptions:

<table><tr><td rowspan="2"></td><td colspan="3">Year ended December 31</td></tr><tr><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Stock Options</td><td></td><td></td><td></td></tr><tr><td>Expected term in years \( ^{1} \)</td><td>6.2</td><td>6.1</td><td>6.0</td></tr><tr><td>Volatility \( ^{2} \)</td><td>31.0%</td><td>30.8%</td><td>30.2%</td></tr><tr><td>Risk-free interest rate based on zero coupon U.S. treasury note</td><td>2.6%</td><td>2.9%</td><td>2.1%</td></tr><tr><td>Dividend yield</td><td>3.6%</td><td>3.9%</td><td>3.2%</td></tr><tr><td>Weighted-average fair value per option granted</td><td></td><td></td><td></td></tr><tr><td></td><td></td><td></td><td></td></tr><tr><td>Restored Options</td><td></td><td></td><td></td></tr><tr><td>Expected term in years \( ^{1} \)</td><td>1.2</td><td>1.2</td><td>1.2</td></tr><tr><td>Volatility \( ^{2} \)</td><td>20.6%</td><td>38.9%</td><td>45.0%</td></tr><tr><td>Risk-free interest rate based on zero coupon U.S. treasury note</td><td>0.7%</td><td>0.6%</td><td>1.1%</td></tr><tr><td>Dividend yield</td><td>3.4%</td><td>3.8%</td><td>3.5%</td></tr><tr><td>Weighted-average fair value per option granted</td><td></td><td></td><td></td></tr><tr><td></td><td></td><td></td><td></td></tr></table>

 \( ^{1} \)  Expected term is based on historical exercise and postvesting cancellation data.

 \( ^{2} \)  Volatility rate is based on historical stock prices over an appropriate period, generally equal to the expected term.

A summary of option activity during 2011 is presented below:

<table><tr><td></td><td>Shares (Thousands)</td><td>Weighted-Average Exercise Price</td><td>Weighted-Average Remaining Contractual Term</td><td>Aggregate Intrinsic Value</td></tr><tr><td>Outstanding at</td><td></td><td></td><td></td><td></td></tr><tr><td>January 1, 2011</td><td>74,852</td><td>$ 67.04</td><td></td><td></td></tr><tr><td>Granted</td><td>14,260</td><td>$ 94.46</td><td></td><td></td></tr><tr><td>Exercised</td><td>(15,844)</td><td>$ 60.20</td><td></td><td></td></tr><tr><td>Restored</td><td>33</td><td>$103.96</td><td></td><td></td></tr><tr><td>Forfeited</td><td>(953)</td><td>$ 85.79</td><td></td><td></td></tr><tr><td>Outstanding at</td><td></td><td></td><td></td><td></td></tr><tr><td>December 31, 2011</td><td>72,348</td><td>$ 73.71</td><td>6.4 yrs</td><td>$ 2,365</td></tr><tr><td>Exercisable at</td><td></td><td></td><td></td><td></td></tr><tr><td>December 31, 2011</td><td>45,494</td><td>$ 67.84</td><td>5.3 yrs</td><td>$ 1,755</td></tr></table>

The total intrinsic value (i.e., the difference between the exercise price and the market price) of options exercised during 2011, 2010 and 2009 was $668, $259 and $91, respectively. During this period, the company continued its practice of issuing treasury shares upon exercise of these awards.
As of December 31, 2011, there was $265 of total unrecognized before-tax compensation cost related to non-vested share-based compensation arrangements granted or restored under the plans. That cost is expected to be recognized over a weighted-average period of 1.7 years.

At January 1, 2011, the number of LTIP performance units outstanding was equivalent to 2,727,874 shares. During 2011, 1,011,200 units were granted, 810,071 units vested with cash proceeds distributed to recipients and 47,167 units were forfeited. At December 31, 2011, units outstanding were 2,881,836, and the fair value of the liability recorded for these instruments was $294. In addition, outstanding stock appreciation rights and other awards that were granted under various LTIP and former Texaco and Unocal programs totaled approximately 2.2 million equivalent shares as of December 31, 2011. A liability of $62 was recorded for these awards.

## Note 21

## Employee Benefit Plans

The company has defined benefit pension plans for many employees. The company typically prefunds defined benefit plans as required by local regulations or in certain situations where prefunding provides economic advantages. In the United States, all qualified plans are subject to the Employee Retirement Income Security Act (ERISA) minimum funding standard. The company does not typically fund U.S. nonqualified pension plans that are not subject to funding requirements under laws and regulations because contributions to these pension plans may be less economic and investment returns may be less attractive than the company’s other investment alternatives.

The company also sponsors other postretirement (OPEB) plans that provide medical and dental benefits, as well as life insurance for some active and qualifying retired employees. The plans are unfunded, and the company and retirees share the costs. Medical coverage for Medicare-eligible retirees in the company’s main U.S. medical plan is secondary to Medicare (including Part D) and the increase to the company contribution for retiree medical coverage is limited to no more than 4 percent each year. Certain life insurance benefits are paid by the company.

Under accounting standards for postretirement benefits (ASC 715), the company recognizes the overfunded or underfunded status of each of its defined benefit pension and OPEB plans as an asset or liability on the Consolidated Balance Sheet.



Note 21 Employee Benefit Plans - Continued

The funded status of the company’s pension and other postretirement benefit plans for 2011 and 2010 follows:

<table><tr><td rowspan="3"></td><td colspan="6">Pension Benefits</td></tr><tr><td colspan="3">2011</td><td colspan="2">2010</td><td>Other Benefits</td></tr><tr><td>U.S.</td><td>Int&#x27;l.</td><td>U.S.</td><td>Int&#x27;l.</td><td>2011</td><td>2010</td></tr><tr><td>Change in Benefit Obligation</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Benefit obligation at January 1</td><td>$10,271</td><td>$ 5,070</td><td>$ 9,664</td><td>$ 4,715</td><td>$ 3,605</td><td>$ 3,065</td></tr><tr><td>Service cost</td><td>374</td><td>174</td><td>337</td><td>153</td><td>58</td><td>39</td></tr><tr><td>Interest cost</td><td>463</td><td>325</td><td>486</td><td>307</td><td>180</td><td>175</td></tr><tr><td>Plan participants&#x27; contributions</td><td>-</td><td>6</td><td>-</td><td>7</td><td>148</td><td>147</td></tr><tr><td>Plan amendments</td><td>-</td><td>27</td><td>-</td><td>-</td><td>-</td><td>12</td></tr><tr><td>Actuarial loss (gain)</td><td>1,920</td><td>318</td><td>568</td><td>200</td><td>149</td><td>486</td></tr><tr><td>Foreign currency exchange rate changes</td><td>-</td><td>(98)</td><td>-</td><td>(17)</td><td>(19)</td><td>11</td></tr><tr><td>Benefits paid</td><td>(863)</td><td>(303)</td><td>(784)</td><td>(295)</td><td>(346)</td><td>(330)</td></tr><tr><td>Curtailment</td><td>-</td><td>-</td><td>-</td><td>-</td><td>(10)</td><td>-</td></tr><tr><td>Benefit obligation at December 31</td><td>12,165</td><td>5,519</td><td>10,271</td><td>5,070</td><td>3,765</td><td>3,605</td></tr><tr><td>Change in Plan Assets</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Fair value of plan assets at January 1</td><td>8,579</td><td>3,503</td><td>7,304</td><td>3,235</td><td>-</td><td>-</td></tr><tr><td>Actual return on plan assets</td><td>(143)</td><td>118</td><td>867</td><td>361</td><td>-</td><td>-</td></tr><tr><td>Foreign currency exchange rate changes</td><td>-</td><td>(66)</td><td>-</td><td>(63)</td><td>-</td><td>-</td></tr><tr><td>Employer contributions</td><td>1,147</td><td>319</td><td>1,192</td><td>258</td><td>198</td><td>183</td></tr><tr><td>Plan participants&#x27; contributions</td><td>-</td><td>6</td><td>-</td><td>7</td><td>148</td><td>147</td></tr><tr><td>Benefits paid</td><td>(863)</td><td>(303)</td><td>(784)</td><td>(295)</td><td>(346)</td><td>(330)</td></tr><tr><td>Fair value of plan assets at December 31</td><td>8,720</td><td>3,577</td><td>8,579</td><td>3,503</td><td>-</td><td>-</td></tr><tr><td>Funded Status at December 31</td><td>$ (3,445)</td><td>$ (1,942)</td><td>$ (1,692)</td><td>$ (1,567)</td><td>$ (3,765)</td><td>$ (3,605)</td></tr></table>

Amounts recognized on the Consolidated Balance Sheet for the company’s pension and other postretirement benefit plans at December 31, 2011 and 2010, include:

<table><tr><td rowspan="3"></td><td colspan="6">Pension Benefits</td></tr><tr><td colspan="3">2011</td><td colspan="2">2010</td><td>Other Benefits</td></tr><tr><td>U.S.</td><td>Int&#x27;l.</td><td>U.S.</td><td>Int&#x27;l.</td><td>2011</td><td>2010</td></tr><tr><td>Deferred charges and other assets</td><td>$ 5</td><td>$ 116</td><td>$ 7</td><td>$ 77</td><td>$ -</td><td>$ -</td></tr><tr><td>Accrued liabilities</td><td>(72)</td><td>(84)</td><td>(134)</td><td>(71)</td><td>(222)</td><td>(225)</td></tr><tr><td>Reserves for employee benefit plans</td><td>(3,378)</td><td>(1,974)</td><td>(1,565)</td><td>(1,573)</td><td>(3,543)</td><td>(3,380)</td></tr><tr><td>Net amount recognized at December 31</td><td>$ (3,445)</td><td>$ (1,942)</td><td>$ (1,692)</td><td>$ (1,567)</td><td>$ (3,765)</td><td>$ (3,605)</td></tr></table>

Amounts recognized on a before-tax basis in “Accumulated other comprehensive loss” for the company’s pension and OPEB plans were $9,279 and $6,749 at the end of 2011 and 2010, respectively. These amounts consisted of:

<table><tr><td rowspan="3"></td><td colspan="6">Pension Benefits</td></tr><tr><td colspan="3">2011</td><td colspan="2">2010</td><td>Other Benefits</td></tr><tr><td>U.S.</td><td>Int&#x27;l.</td><td>U.S.</td><td>Int&#x27;l.</td><td>2011</td><td>2010</td></tr><tr><td>Net actuarial loss</td><td>$ 5,982</td><td>$ 2,250</td><td>$ 3,919</td><td>$ 1,903</td><td>$ 1,002</td><td>$ 935</td></tr><tr><td>Prior service (credit) costs</td><td>(44)</td><td>152</td><td>(52)</td><td>179</td><td>(63)</td><td>(135)</td></tr><tr><td>Total recognized at December 31</td><td>$ 5,938</td><td>$ 2,402</td><td>$ 3,867</td><td>$ 2,082</td><td>$ 939</td><td>$ 800</td></tr></table>

The accumulated benefit obligations for all U.S. and international pension plans were $11,198 and $4,518, respectively, at December 31, 2011, and $9,535 and $4,161, respectively, at December 31, 2010.



Information for U.S. and international pension plans with an accumulated benefit obligation in excess of plan assets at December 31, 2011 and 2010, was:

<table><tr><td rowspan="2"></td><td colspan="4">Pension Benefits</td></tr><tr><td colspan="2">2011</td><td colspan="2">2010</td></tr><tr><td></td><td>U.S.</td><td>Int&#x27;l.</td><td>U.S.</td><td>Int&#x27;l.</td></tr><tr><td>Projected benefit obligations</td><td>$ 12,157</td><td>$ 4,207</td><td>$ 10,265</td><td>$ 3,668</td></tr><tr><td>Accumulated benefit obligations</td><td>11,191</td><td>3,586</td><td>9,528</td><td>3,113</td></tr><tr><td>Fair value of plan assets</td><td>8,707</td><td>2,357</td><td>8,566</td><td>2,190</td></tr></table>

The components of net periodic benefit cost and amounts recognized in other comprehensive income for 2011, 2010 and 2009 are shown in the table below:

<table><tr><td rowspan="2"></td><td colspan="4">2011</td><td colspan="4">Pension Benefits</td><td colspan="2">Other Benefits</td></tr><tr><td>U.S.</td><td>Int&#x27;l.</td><td>U.S.</td><td>Int&#x27;l.</td><td>U.S.</td><td>U.S.</td><td>Int&#x27;l.</td><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Net Periodic Benefit Cost</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Service cost</td><td>$ 374</td><td>$ 174</td><td>$ 337</td><td>$ 153</td><td>$ 266</td><td>$ 128</td><td>$ 58</td><td>$ 39</td><td>$ 43</td><td></td></tr><tr><td>Interest cost</td><td>463</td><td>325</td><td>486</td><td>307</td><td>481</td><td>292</td><td>180</td><td>175</td><td>180</td><td></td></tr><tr><td>Expected return on plan assets</td><td>(613)</td><td>(283)</td><td>(538)</td><td>(241)</td><td>(395)</td><td>(203)</td><td>-</td><td>-</td><td>-</td><td></td></tr><tr><td>Amortization of prior service (credits) costs</td><td>(8)</td><td>19</td><td>(8)</td><td>22</td><td>(7)</td><td>23</td><td>(72)</td><td>(75)</td><td>(81)</td><td></td></tr><tr><td>Recognized actuarial losses</td><td>310</td><td>101</td><td>318</td><td>98</td><td>298</td><td>108</td><td>64</td><td>27</td><td>27</td><td></td></tr><tr><td>Settlement losses</td><td>298</td><td>-</td><td>186</td><td>6</td><td>141</td><td>1</td><td>-</td><td>-</td><td>-</td><td></td></tr><tr><td>Curtailment losses (gains)</td><td>-</td><td>35</td><td>-</td><td>-</td><td>-</td><td>-</td><td>(10)</td><td>-</td><td>(5)</td><td></td></tr><tr><td>Total net periodic benefit cost</td><td>824</td><td>371</td><td>781</td><td>345</td><td>784</td><td>349</td><td>220</td><td>166</td><td>164</td><td></td></tr><tr><td>Changes Recognized in Other Comprehensive Income</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net actuarial loss during period</td><td>2,671</td><td>448</td><td>242</td><td>118</td><td>823</td><td>194</td><td>131</td><td>497</td><td>82</td><td></td></tr><tr><td>Amortization of actuarial loss</td><td>(608)</td><td>(101)</td><td>(504)</td><td>(104)</td><td>(439)</td><td>(109)</td><td>(64)</td><td>(27)</td><td>(27)</td><td></td></tr><tr><td>Prior service cost during period</td><td>-</td><td>27</td><td>-</td><td>-</td><td>1</td><td>13</td><td>-</td><td>12</td><td>20</td><td></td></tr><tr><td>Amortization of prior service credits (costs)</td><td>8</td><td>(54)</td><td>8</td><td>(22)</td><td>7</td><td>(23)</td><td>72</td><td>75</td><td>81</td><td></td></tr><tr><td>Total changes recognized in other comprehensive income</td><td>2,071</td><td>320</td><td>(254)</td><td>(8)</td><td>392</td><td>75</td><td>139</td><td>557</td><td>156</td><td></td></tr><tr><td>Recognized in Net Periodic Benefit Cost and Other Comprehensive Income</td><td>$2,895</td><td>$ 691</td><td>$ 527</td><td>$ 337</td><td>$ 1,176</td><td>$ 424</td><td>$ 359</td><td>$ 723</td><td>$ 320</td><td></td></tr></table>

Net actuarial losses recorded in “Accumulated other comprehensive loss” at December 31, 2011, for the company’s U.S. pension, international pension and OPEB plans are being amortized on a straight-line basis over approximately 10, 12 and eight years, respectively. These amortization periods represent the estimated average remaining service of employees expected to receive benefits under the plans. These losses are amortized to the extent they exceed 10 percent of the higher of the projected benefit obligation or market-related value of plan assets. The amount subject to amortization is determined on a plan-by-plan basis. During 2012, the company estimates actuarial losses of $476, $142 and $75 will be amortized from “Accumulated other comprehensive loss” for U.S. pension, international pension and OPEB plans, respectively. In addition, the company estimates an additional $260 will be recognized from “Accumulated other comprehensive loss” during 2012 related to lump-sum settlement costs from U.S. pension plans.

The weighted-average amortization period for recognizing prior service costs (credits) recorded in “Accumulated other comprehensive loss” at December 31, 2011, was approximately six and seven years for U.S. and international pension plans, respectively, and two years for other postretirement benefit plans. During 2012, the company estimates prior service (credits) costs of $(8), $21 and $(72) will be amortized from “Accumulated other comprehensive loss” for U.S. pension, international pension and OPEB plans, respectively.



Note 21 Employee Benefit Plans - Continued

Assumptions The following weighted-average assumptions were used to determine benefit obligations and net periodic benefit costs for years ended December 31:

<table><tr><td rowspan="3"></td><td colspan="9">Pension Benefits</td></tr><tr><td colspan="3">2011</td><td colspan="3">2010</td><td colspan="3">Other Benefits</td></tr><tr><td>U.S.</td><td>Int&#x27;l.</td><td>U.S.</td><td>Int&#x27;l.</td><td>U.S.</td><td>U.S.</td><td>Int&#x27;l.</td><td>2011</td><td>2010</td></tr><tr><td>Assumptions used to determine benefit obligations:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Discount rate</td><td>3.8%</td><td>5.9%</td><td>4.8%</td><td>6.5%</td><td>5.3%</td><td>6.8%</td><td>4.2%</td><td>5.2%</td><td>5.9%</td></tr><tr><td>Rate of compensation increase</td><td>4.5%</td><td>5.7%</td><td>4.5%</td><td>6.7%</td><td>4.5%</td><td>6.3%</td><td>N/A</td><td>N/A</td><td>N/A</td></tr><tr><td>Assumptions used to determine net periodic benefit cost:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Discount rate</td><td>4.8%</td><td>6.5%</td><td>5.3%</td><td>6.8%</td><td>6.3%</td><td>7.5%</td><td>5.2%</td><td>5.9%</td><td>6.3%</td></tr><tr><td>Expected return on plan assets</td><td>7.8%</td><td>7.8%</td><td>7.8%</td><td>7.8%</td><td>6.7%</td><td>7.5%</td><td>N/A</td><td>N/A</td><td>N/A</td></tr><tr><td>Rate of compensation increase</td><td>4.5%</td><td>6.7%</td><td>4.5%</td><td>6.3%</td><td>4.5%</td><td>6.8%</td><td>N/A</td><td>N/A</td><td>N/A</td></tr></table>

Expected Return on Plan Assets The company’s estimated long-term rates of return on pension assets are driven primarily by actual historical asset-class returns, an assessment of expected future performance, advice from external actuarial firms and the incorporation of specific asset-class risk factors. Asset allocations are periodically updated using pension plan asset/liability studies, and the company’s estimated long-term rates of return are consistent with these studies.

There have been no changes in the expected long-term rate of return on plan assets since 2002 for U.S. plans, which account for 70 percent of the company’s pension plan assets. At December 31, 2011, the estimated long-term rate of return on U.S. pension plan assets was 7.8 percent.

The market-related value of assets of the major U.S. pension plan used in the determination of pension expense was based on the market values in the three months preceding the year-end measurement date, as opposed to the maximum allowable period of five years under U.S. accounting rules. Management considers the three-month time period long enough to minimize the effects of distortions from day-to-day market volatility and still be contemporaneous to the end of the year. For other plans, market value of assets as of year-end is used in calculating the pension expense.

Discount Rate The discount rate assumptions used to determine U.S. and international pension and postretirement benefit plan obligations and expense reflect the prevailing rates available on high-quality, fixed-income debt instruments. At December 31, 2011, the company selected a 3.8 percent discount rate for the U.S. pension plans and 4.0 percent for the U.S. postretirement benefit plan. This rate was based on a cash flow analysis that matched estimated future benefit payments to the Citigroup Pension Discount Yield Curve as of year-end 2011. The discount rates at the end of 2010 and 2009 were 4.8 and 5.3 percent and 5.0 and 5.8 percent for the U.S. pension plans and the U.S. OPEB plan, respectively. Other Benefit Assumptions For the measurement of accumulated postretirement benefit obligation at December 31, 2011, for the main U.S. postretirement medical plan, the assumed health care cost-trend rates start with 8 percent in 2012 and gradually decline to 5 percent for 2023 and beyond. For this measurement at December 31, 2010, the assumed health care cost-trend rates started with 8 percent in 2011 and gradually declined to 5 percent for 2018 and beyond. In both measurements, the annual increase to company contributions was capped at 4 percent.

Assumed health care cost-trend rates can have a significant effect on the amounts reported for retiree health care costs. The impact is mitigated by the 4 percent cap on the company’s medical contributions for the primary U.S. plan. A one-percentage-point change in the assumed health care cost-trend rates would have the following effects:

<table><tr><td></td><td>1 Percent Increase</td><td>1 Percent Decrease</td></tr><tr><td>Effect on total service and interest cost components</td><td>$ 17</td><td>$ (15)</td></tr><tr><td>Effect on postretirement benefit obligation</td><td>$ 177</td><td>$ (150)</td></tr></table>

Plan Assets and Investment Strategy The fair value hierarchy of inputs the company uses to value the pension assets is divided into three levels:

Level 1: Fair values of these assets are measured using unadjusted quoted prices for the assets or the prices of identical assets in active markets that the plans have the ability to access.

Level 2: Fair values of these assets are measured based on quoted prices for similar assets in active markets; quoted prices for identical or similar assets in inactive markets; inputs other than quoted prices that are observable for the asset; and inputs that are derived principally from or corroborated by observable market data through correlation or other means. If the asset has a contractual term, the Level 2 input is observable for substantially the full term of the asset. The fair values for Level 2 assets are generally obtained from third-party broker quotes, independent pricing services and exchanges.



Level 3: Inputs to the fair value measurement are unobservable for these assets. Valuation may be performed using a financial model with estimated inputs entered into the model.

The fair value measurements of the company’s pension plans for 2011 and 2010 are below:

<table><tr><td rowspan="2"></td><td colspan="8">U.S.</td></tr><tr><td>Total Fair Value</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total Fair Value</td><td>Level 1</td><td>Level 2</td><td>Level 3</td></tr><tr><td>At December 31, 2011</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Equities</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>U.S.¹</td><td>$ 1,470</td><td>$ 1,470</td><td>$ -</td><td>$ -</td><td>$ 497</td><td>$ 497</td><td>$ -</td><td>$ -</td></tr><tr><td>International</td><td>1,203</td><td>1,203</td><td>-</td><td>-</td><td>693</td><td>693</td><td>-</td><td>-</td></tr><tr><td>Collective Trusts/Mutual Funds²</td><td>2,633</td><td>14</td><td>2,619</td><td>-</td><td>596</td><td>28</td><td>568</td><td>-</td></tr><tr><td>Fixed Income</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Government</td><td>622</td><td>146</td><td>476</td><td>-</td><td>635</td><td>25</td><td>610</td><td>-</td></tr><tr><td>Corporate</td><td>338</td><td>-</td><td>338</td><td>-</td><td>319</td><td>16</td><td>276</td><td>27</td></tr><tr><td>Mortgage-Backed Securities</td><td>107</td><td>-</td><td>107</td><td>-</td><td>2</td><td>-</td><td>-</td><td>2</td></tr><tr><td>Other Asset Backed</td><td>61</td><td>-</td><td>61</td><td>-</td><td>5</td><td>-</td><td>5</td><td>-</td></tr><tr><td>Collective Trusts/Mutual Funds²</td><td>1,046</td><td>-</td><td>1,046</td><td>-</td><td>345</td><td>61</td><td>284</td><td>-</td></tr><tr><td>Mixed Funds³</td><td>10</td><td>10</td><td>-</td><td>-</td><td>102</td><td>13</td><td>89</td><td>-</td></tr><tr><td>Real Estate⁴</td><td>843</td><td>-</td><td>-</td><td>843</td><td>155</td><td>-</td><td>-</td><td>155</td></tr><tr><td>Cash and Cash Equivalents</td><td>404</td><td>404</td><td>-</td><td>-</td><td>211</td><td>211</td><td>-</td><td>-</td></tr><tr><td>Other⁵</td><td>(17)</td><td>(79)</td><td>8</td><td>54</td><td>17</td><td>(2)</td><td>17</td><td>2</td></tr><tr><td>Total at December 31, 2011</td><td>$ 8,720</td><td>$ 3,168</td><td>$ 4,655</td><td>$ 897</td><td>$ 3,577</td><td>$ 1,542</td><td>$ 1,849</td><td>$ 186</td></tr><tr><td>At December 31, 2010</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Equities</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>U.S.¹</td><td>$ 2,121</td><td>$ 2,121</td><td>$ -</td><td>$ -</td><td>$ 465</td><td>$ 465</td><td>$ -</td><td>$ -</td></tr><tr><td>International</td><td>1,405</td><td>1,405</td><td>-</td><td>-</td><td>721</td><td>721</td><td>-</td><td>-</td></tr><tr><td>Collective Trusts/Mutual Funds²</td><td>2,068</td><td>5</td><td>2,063</td><td>-</td><td>578</td><td>80</td><td>498</td><td>-</td></tr><tr><td>Fixed Income</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Government</td><td>659</td><td>19</td><td>640</td><td>-</td><td>568</td><td>38</td><td>530</td><td>-</td></tr><tr><td>Corporate</td><td>314</td><td>-</td><td>314</td><td>-</td><td>351</td><td>24</td><td>299</td><td>28</td></tr><tr><td>Mortgage-Backed Securities</td><td>82</td><td>-</td><td>82</td><td>-</td><td>2</td><td>-</td><td>-</td><td>2</td></tr><tr><td>Other Asset Backed</td><td>74</td><td>-</td><td>74</td><td>-</td><td>16</td><td>-</td><td>16</td><td>-</td></tr><tr><td>Collective Trusts/Mutual Funds²</td><td>1,064</td><td>-</td><td>1,064</td><td>-</td><td>332</td><td>19</td><td>313</td><td>-</td></tr><tr><td>Mixed Funds³</td><td>9</td><td>9</td><td>-</td><td>-</td><td>105</td><td>16</td><td>89</td><td>-</td></tr><tr><td>Real Estate⁴</td><td>596</td><td>-</td><td>-</td><td>596</td><td>142</td><td>-</td><td>-</td><td>142</td></tr><tr><td>Cash and Cash Equivalents</td><td>213</td><td>213</td><td>-</td><td>-</td><td>217</td><td>217</td><td>-</td><td>-</td></tr><tr><td>Other⁵</td><td>(26)</td><td>(87)</td><td>8</td><td>53</td><td>6</td><td>(5)</td><td>9</td><td>2</td></tr><tr><td>Total at December 31, 2010</td><td>$ 8,579</td><td>$ 3,685</td><td>$ 4,245</td><td>$ 649</td><td>$ 3,503</td><td>$ 1,575</td><td>$ 1,754</td><td>$ 174</td></tr></table>

 \( ^{1} \)  U.S. equities include investments in the company's common stock in the amount of $35 at December 31, 2011, and $38 at December 31, 2010.

 \( ^{2} \)  Collective Trusts/Mutual Funds for U.S. plans are entirely index funds; for International plans, they are mostly index funds. For these index funds, the Level 2 designation is partially based on the restriction that advance notification of redemptions, typically two business days, is required.

 \( ^{3} \)  Mixed funds are composed of funds that invest in both equity and fixed-income instruments in order to diversify and lower risk.

 \( ^{4} \)  The year-end valuations of the U.S. real estate assets are based on internal appraisals by the real estate managers, which are updates of third-party appraisals that occur at least once a year for each property in the portfolio.

 \( ^{5} \)  The “Other” asset class includes net payables for securities purchased but not yet settled (Level 1); dividends and interest- and tax-related receivables (Level 2); insurance contracts and investments in private-equity limited partnerships (Level 3).



The effects of fair value measurements using significant unobservable inputs on changes in Level 3 plan assets for the period are outlined below:

<table><tr><td rowspan="2"></td><td colspan="6">Fixed Income</td></tr><tr><td>Corporate</td><td>Mortgage-Backed Securities</td><td>Real Estate</td><td>Other</td><td>Total</td><td></td></tr><tr><td>Total at December 31, 2009</td><td>$ 18</td><td>$ 2</td><td>$ 610</td><td>$ 52</td><td>$ 682</td><td></td></tr><tr><td>Actual Return on Plan Assets:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets held at the reporting date</td><td>3</td><td>-</td><td>34</td><td>1</td><td>38</td><td></td></tr><tr><td>Assets sold during the period</td><td>-</td><td>-</td><td>1</td><td>-</td><td>1</td><td></td></tr><tr><td>Purchases, Sales and Settlements</td><td>7</td><td>-</td><td>93</td><td>2</td><td>102</td><td></td></tr><tr><td>Transfers in and/or out of Level 3</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td><td></td></tr><tr><td>Total at December 31, 2010</td><td>$ 28</td><td>$ 2</td><td>$ 738</td><td>$ 55</td><td>$ 823</td><td></td></tr><tr><td>Actual Return on Plan Assets:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets held at the reporting date</td><td>-</td><td>-</td><td>103</td><td>4</td><td>107</td><td></td></tr><tr><td>Assets sold during the period</td><td>-</td><td>-</td><td>1</td><td>(2)</td><td>(1)</td><td></td></tr><tr><td>Purchases, Sales and Settlements</td><td>(1)</td><td>-</td><td>156</td><td>(1)</td><td>154</td><td></td></tr><tr><td>Transfers in and/or out of Level 3</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td><td></td></tr><tr><td>Total at December 31, 2011</td><td>$ 27</td><td>$ 2</td><td>$ 998</td><td>$ 56</td><td>$1,083</td><td></td></tr></table>

The primary investment objectives of the pension plans are to achieve the highest rate of total return within prudent levels of risk and liquidity, to diversify and mitigate potential downside risk associated with the investments, and to provide adequate liquidity for benefit payments and portfolio management.

The company’s U.S. and U.K. pension plans comprise 86 percent of the total pension assets. Both the U.S. and U.K. plans have an Investment Committee that regularly meets during the year to review the asset holdings and their returns. To assess the plans’ investment performance, long-term asset allocation policy benchmarks have been established.

For the primary U.S. pension plan, the Chevron Board of Directors has established the following approved asset allocation ranges: Equities 40–70 percent, Fixed Income and Cash 20–65 percent, Real Estate 0–15 percent, and Other 0–5 percent. For the U.K. pension plan, the U.K. Board of Trustees has established the following asset allocation guidelines, which are reviewed regularly: Equities 60–80 percent and Fixed Income and Cash 20–40 percent. The other significant international pension plans also have established maximum and minimum asset allocation ranges that vary by plan. Actual asset allocation within approved ranges is based on a variety of current economic and market conditions and consideration of specific asset class risk. To mitigate concentration and other risks, assets are invested across multiple asset classes with active investment managers and passive index funds.

The company does not prefund its OPEB obligations.

Cash Contributions and Benefit Payments In 2011, the company contributed $1,147 and $319 to its U.S. and international pension plans, respectively. In 2012, the company expects contributions to be approximately $600 and $300 to its U.S. and international pension plans, respectively. Actual contribution amounts are dependent upon investment returns, changes in pension obligations, regulatory environments and other economic factors. Additional funding may ultimately be required if investment returns are insufficient to offset increases in plan obligations.

The company anticipates paying other postretirement benefits of approximately $223 in 2012, compared with $198 paid in 2011.

The following benefit payments, which include estimated future service, are expected to be paid by the company in the next 10 years:

<table><tr><td rowspan="2"></td><td colspan="2">Pension Benefits</td><td rowspan="2">Other Benefits</td></tr><tr><td>U.S.</td><td>Int&#x27;l.</td></tr><tr><td>2012</td><td>$ 1,053</td><td>$ 268</td><td>$ 223</td></tr><tr><td>2013</td><td>$ 1,043</td><td>$ 316</td><td>$ 229</td></tr><tr><td>2014</td><td>$ 1,046</td><td>$ 320</td><td>$ 234</td></tr><tr><td>2015</td><td>$ 1,050</td><td>$ 344</td><td>$ 240</td></tr><tr><td>2016</td><td>$ 1,062</td><td>$ 375</td><td>$ 245</td></tr><tr><td>2017-2021</td><td>$ 5,261</td><td>$ 2,153</td><td>$ 1,287</td></tr></table>

Employee Savings Investment Plan Eligible employees of Chevron and certain of its subsidiaries participate in the Chevron Employee Savings Investment Plan (ESIP).

Charges to expense for the ESIP represent the company’s contributions to the plan, which are funded either through the purchase of shares of common stock on the open market or through the release of common stock held in the leveraged employee stock ownership plan (LESOP), which is described in the section that follows. Total company matching contributions to employee accounts within the ESIP were $263, $253 and $257 in 2011, 2010 and 2009, respectively. This cost was reduced by the value of shares released from the



LESOP totaling $38, $97 and $184 in 2011, 2010 and 2009, respectively. The remaining amounts, totaling $225, $156 and $73 in 2011, 2010 and 2009, respectively, represent open market purchases.

Employee Stock Ownership Plan Within the Chevron ESIP is an employee stock ownership plan (ESOP). In 1989, Chevron established a LESOP as a constituent part of the ESOP. The LESOP provides partial prefunding of the company’s future commitments to the ESIP.

As permitted by accounting standards for share-based compensation (ASC 718), the debt of the LESOP is recorded as debt, and shares pledged as collateral are reported as “Deferred compensation and benefit plan trust” on the Consolidated Balance Sheet and the Consolidated Statement of Equity.

The company reports compensation expense equal to LESOP debt principal repayments less dividends received and used by the LESOP for debt service. Interest accrued on LESOP debt is recorded as interest expense. Dividends paid on LESOP shares are reflected as a reduction of retained earnings. All LESOP shares are considered outstanding for earnings-per-share computations.

Total credits to expense for the LESOP were $1, $1 and $3 in 2011, 2010 and 2009, respectively. The net credit for the respective years was composed of credits to compensation expense of $5, $6 and $15 and charges to interest expense for LESOP debt of $4, $5 and $12.

Of the dividends paid on the LESOP shares, $18, $46 and $110 were used in 2011, 2010 and 2009, respectively, to service LESOP debt. No contributions were required in 2011, 2010 or 2009, as dividends received by the LESOP were sufficient to satisfy LESOP debt service.

Shares held in the LESOP are released and allocated to the accounts of plan participants based on debt service deemed to be paid in the year in proportion to the total of current-year and remaining debt service. LESOP shares as of December 31, 2011 and 2010, were as follows:

<table><tr><td>Thousands</td><td>2011</td><td>2010</td></tr><tr><td>Allocated shares</td><td>19,047</td><td>20,718</td></tr><tr><td>Unallocated shares</td><td>1,864</td><td>2,374</td></tr><tr><td>Total LESOP shares</td><td>20,911</td><td>23,092</td></tr></table>

Benefit Plan Trusts Prior to its acquisition by Chevron, Texaco established a benefit plan trust for funding obligations under some of its benefit plans. At year-end 2011, the trust contained 14.2 million shares of Chevron treasury stock. The trust will sell the shares or use the dividends from the shares to pay benefits only to the extent that the company does not pay such benefits. The company intends to continue to pay its obligations under the benefit plans. The trustee will vote the shares held in the trust as instructed by the trust’s beneficiaries. The shares held in the trust are not considered outstanding for earnings-per-share purposes until distributed or sold by the trust in payment of benefit obligations.

Prior to its acquisition by Chevron, Unocal established various grantor trusts to fund obligations under some of its benefit plans, including the deferred compensation and supplemental retirement plans. At December 31, 2011 and 2010, trust assets of $51 and $57, respectively, were invested primarily in interest-earning accounts.

Employee Incentive Plans The Chevron Incentive Plan is an annual cash bonus plan for eligible employees that links awards to corporate, unit and individual performance in the prior year. Charges to expense for cash bonuses were $1,217, $766 and $561 in 2011, 2010 and 2009, respectively. Chevron also has the LTIP for officers and other regular salaried employees of the company and its subsidiaries who hold positions of significant responsibility. Awards under the LTIP consist of stock options and other share-based compensation that are described in Note 20, beginning on page 56.

## Note 22

## Equity

Retained earnings at December 31, 2011 and 2010, included approximately $10,127 and $9,159, respectively, for the company’s share of undistributed earnings of equity affiliates.

At December 31, 2011, about 67 million shares of Chevron’s common stock remained available for issuance from the 160 million shares that were reserved for issuance under the Chevron LTIP. In addition, approximately 258,000 shares remain available for issuance from the 800,000 shares of the company’s common stock that were reserved for awards under the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan.

## Note 23

## Restructuring and Reorganization

In the first quarter 2010, the company announced employee reduction programs related to the restructuring and reorganization of its downstream businesses and corporate staffs. Total terminations under the programs are expected to be approximately 2,700 employees. About 1,300 of the affected employees are located in the United States. About 2,500 employees have been terminated through December 31, 2011, and the programs were substantially completed by the end of 2011. Substantially all of the remaining employees designated for termination under the programs are expected to leave in 2012.

A before-tax charge of $244 was recorded in first quarter 2010 associated with these programs, of which $138 remained outstanding at December 31, 2010. During 2011,



the company made payments of $74 associated with these liabilities. The majority of the payments were in Downstream. The balance at December 31, 2011, was classified as a current liability on the Consolidated Balance Sheet.

<table><tr><td></td><td>Amounts Before Tax</td></tr><tr><td>Balance at January 1, 2011</td><td>$ 138</td></tr><tr><td>Adjustments</td><td>(28)</td></tr><tr><td>Payments</td><td>(74)</td></tr><tr><td>Balance at December 31, 2011</td><td>$ 36</td></tr></table>

## Note 24

## Other Contingencies and Commitments

Income Taxes The company calculates its income tax expense and liabilities quarterly. These liabilities generally are subject to audit and are not finalized with the individual taxing authorities until several years after the end of the annual period for which income taxes have been calculated. Refer to Note 15, beginning on page 51, for a discussion of the periods for which tax returns have been audited for the company’s major tax jurisdictions and a discussion for all tax jurisdictions of the differences between the amount of tax benefits recognized in the financial statements and the amount taken or expected to be taken in a tax return. The company does not expect settlement of income tax liabilities associated with uncertain tax positions to have a material effect on its results of operations, consolidated financial position or liquidity.

Guarantees The company’s guarantee of approximately $600 is associated with certain payments under a terminal use agreement entered into by a company affiliate. The terminal commenced operations in third quarter 2011. Over the approximate 16-year term of the guarantee, the maximum guarantee amount will be reduced over time as certain fees are paid by the affiliate. There are numerous cross-indemnity agreements with the affiliate and the other partners to permit recovery of amounts paid under the guarantee. Chevron has recorded no liability for its obligation under this guarantee.

Indemnifications The company provided certain indemnities of contingent liabilities of Equilon and Motiva to Shell and Saudi Refining, Inc., in connection with the February 2002 sale of the company’s interests in those investments. Through the end of 2011, the company paid $48 under these indemnities and continues to be obligated up to $250 for possible additional indemnification payments in the future.

The company has also provided indemnities relating to contingent environmental liabilities of assets originally contributed by Texaco to the Equilon and Motiva joint ventures and environmental conditions that existed prior to the formation of Equilon and Motiva, or that occurred during the period of Texaco's ownership interest in the joint ventures. In general, the environmental conditions or events that are subject to these indemnities must have arisen prior to December 2001. Claims had to be asserted by February 2009 for Equilon indemnities and must be asserted no later than February 2012 for Motiva indemnities. In February 2012, Motiva Enterprises LLC delivered a letter to the company purporting to preserve unmitigated claims for certain Motiva indemnities. The letter itself provides no estimate of the ultimate claim amount. Management does not believe this letter or any other information provides a basis to estimate the amount, if any, of a range of loss or potential range of loss with respect to either the Equilon or the Motiva indemnities. Under the terms of these indemnities, there is no maximum limit on the amount of potential future payments. The company posts no assets as collateral and has made no payments under the indemnities.

The amounts payable for the indemnities described in the preceding paragraph are to be net of amounts recovered from insurance carriers and others and net of liabilities recorded by Equilon or Motiva prior to September 30, 2001, for any applicable incident.

In the acquisition of Unocal, the company assumed certain indemnities relating to contingent environmental liabilities associated with assets that were sold in 1997. The acquirer of those assets shared in certain environmental remediation costs up to a maximum obligation of $200, which had been reached at December 31, 2009. Under the indemnification agreement, after reaching the $200 obligation, Chevron is solely responsible until April 2022, when the indemnification expires. The environmental conditions or events that are subject to these indemnities must have arisen prior to the sale of the assets in 1997.

Although the company has provided for known obligations under this indemnity that are probable and reasonably estimable, the amount of additional future costs may be material to results of operations in the period in which they are recognized. The company does not expect these costs will have a material effect on its consolidated financial position or liquidity.

Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements The company and its subsidiaries have certain other contingent liabilities with respect to long-term unconditional purchase obligations and commitments, including throughput and take-or-pay agreements, some of which relate to suppliers' financing arrangements. The agreements typically provide goods and services, such as pipeline and storage capacity, drilling rigs, utilities, and petroleum products, to be used or sold in the ordinary course of the company's business. The aggregate approximate amounts of required payments under these



various commitments are: 2012 – $6,000; 2013 – $4,000; 2014 – $3,900; 2015 – $3,200; 2016 – $1,900; 2017 and after – $7,400. A portion of these commitments may ultimately be shared with project partners. Total payments under the agreements were approximately $6,600 in 2011, $6,500 in 2010 and $8,100 in 2009.

Environmental The company is subject to loss contingencies pursuant to laws, regulations, private claims and legal proceedings related to environmental matters that are subject to legal settlements or that in the future may require the company to take action to correct or ameliorate the effects on the environment of prior release of chemicals or petroleum substances, including MTBE, by the company or other parties. Such contingencies may exist for various sites, including, but not limited to, federal Superfund sites and analogous sites under state laws, refineries, crude oil fields, service stations, terminals, land development areas, and mining operations, whether operating, closed or divested. These future costs are not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company's liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties.

Although the company has provided for known environmental obligations that are probable and reasonably estimable, the amount of additional future costs may be material to results of operations in the period in which they are recognized. The company does not expect these costs will have a material effect on its consolidated financial position or liquidity. Also, the company does not believe its obligations to make such expenditures have had, or will have, any significant impact on the company's competitive position relative to other U.S. or international petroleum or chemical companies.

Chevron’s environmental reserve as of December 31, 2011, was $1,404. Included in this balance were remediation activities at approximately 180 sites for which the company had been identified as a potentially responsible party or otherwise involved in the remediation by the U.S. Environmental Protection Agency (EPA) or other regulatory agencies under the provisions of the federal Superfund law or analogous state laws. The company’s remediation reserve for these sites at year-end 2011 was $185. The federal Superfund law and analogous state laws provide for joint and several liability for all responsible parties. Any future actions by the EPA or other regulatory agencies to require Chevron to assume other potentially responsible parties’ costs at designated hazardous waste sites are not expected to have a material effect on the company’s results of operations, consolidated financial position or liquidity.
Of the remaining year-end 2011 environmental reserves balance of $1,219, $675 related to the company’s U.S. downstream operations, including refineries and other plants, marketing locations (i.e., service stations and terminals), chemical facilities, and pipelines. The remaining $544 was associated with various sites in international downstream ($95), upstream ($368) and other businesses ($81). Liabilities at all sites, whether operating, closed or divested, were primarily associated with the company’s plans and activities to remediate soil or groundwater contamination or both. These and other activities include one or more of the following: site assessment; soil excavation; offsite disposal of contaminants; onsite containment, remediation and/or extraction of petroleum hydrocarbon liquid and vapor from soil; groundwater extraction and treatment; and monitoring of the natural attenuation of the contaminants.

The company manages environmental liabilities under specific sets of regulatory requirements, which in the United States include the Resource Conservation and Recovery Act and various state and local regulations. No single remediation site at year-end 2011 had a recorded liability that was material to the company’s results of operations, consolidated financial position or liquidity.

It is likely that the company will continue to incur additional liabilities, beyond those recorded, for environmental remediation relating to past operations. These future costs are not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties.

Refer to Note 25 on page 66 for a discussion of the company’s asset retirement obligations.

Other Contingencies On April 26, 2010, a California appeals court issued a ruling related to the adequacy of an Environmental Impact Report (EIR) supporting the issuance of certain permits by the city of Richmond, California, to replace and upgrade certain facilities at Chevron’s refinery in Richmond. Settlement discussions with plaintiffs in the case ended late fourth quarter 2010, and on March 3, 2011, the trial court entered a final judgment and peremptory writ ordering the City to set aside the project EIR and conditional use permits and enjoining Chevron from any further work. On May 23, 2011, the company filed an application with the City Planning Department for a conditional use permit for a revised project to complete construction of the hydrogen plant, certain sulfur removal facilities and related infrastructure. On June 10, 2011, the City published its Notice of Preparation of the revised EIR for the project. The revised



and recirculated EIR is intended to comply with the appeals court decision. Management believes the outcomes associated with the project are uncertain. Due to the uncertainty of the company’s future course of action, or potential outcomes of any action or combination of actions, management does not believe an estimate of the financial effects, if any, can be made at this time. However, the company’s ultimate exposure may be significant to net income in any one future period.

Chevron receives claims from and submits claims to customers; trading partners; U.S. federal, state and local regulatory bodies; governments; contractors; insurers; and suppliers. The amounts of these claims, individually and in the aggregate, may be significant and take lengthy periods to resolve.

The company and its affiliates also continue to review and analyze their operations and may close, abandon, sell, exchange, acquire or restructure assets to achieve operational or strategic benefits and to improve competitiveness and profitability. These activities, individually or together, may result in gains or losses in future periods.

## Note 25

## Asset Retirement Obligations

The company records the fair value of a liability for an asset retirement obligation (ARO) as an asset and liability when there is a legal obligation associated with the retirement of a tangible long-lived asset and the liability can be reasonably estimated. The legal obligation to perform the asset retirement activity is unconditional, even though uncertainty may exist about the timing and/or method of settlement that may be beyond the company's control. This uncertainty about the timing and/or method of settlement is factored into the measurement of the liability when sufficient information exists to reasonably estimate fair value. Recognition of the ARO includes: (1) the present value of a liability and offsetting asset, (2) the subsequent accretion of that liability and depreciation of the asset, and (3) the periodic review of the ARO liability estimates and discount rates.

AROs are primarily recorded for the company’s crude oil and natural gas producing assets. No significant AROs associated with any legal obligations to retire downstream long-lived assets have been recognized, as indeterminate settlement dates for the asset retirements prevent estimation of the fair value of the associated ARO. The company performs periodic reviews of its downstream long-lived assets for any changes in facts and circumstances that might require recognition of a retirement obligation.
The following table indicates the changes to the company’s before-tax asset retirement obligations in 2011, 2010 and 2009:

<table><tr><td></td><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Balance at January 1</td><td>$ 12,488</td><td>$ 10,175</td><td>$ 9,395</td></tr><tr><td>Liabilities incurred</td><td>62</td><td>129</td><td>144</td></tr><tr><td>Liabilities settled</td><td>(1,316)</td><td>(755)</td><td>(757)</td></tr><tr><td>Accretion expense</td><td>628</td><td>513</td><td>463</td></tr><tr><td>Revisions in estimated cash flows</td><td>905</td><td>2,426</td><td>930</td></tr><tr><td>Balance at December 31</td><td>$ 12,767</td><td>$ 12,488</td><td>$ 10,175</td></tr></table>

The long-term portion of the $12,767 balance at the end of 2011 was $11,999.

## Note 26

## Other Financial Information

Earnings in 2011 included gains of approximately $1,300 relating to the sale of nonstrategic properties. Of this amount, approximately $800 and $500 related to downstream and upstream assets, respectively. Earnings in 2010 included gains of approximately $700 relating to the sale of nonstrategic properties. Of this amount, approximately $400 and $300 related to downstream and upstream assets, respectively. The revenues and earnings contributions of these assets were not material to periods presented.

Other financial information is as follows:

<table><tr><td rowspan="2"></td><td colspan="3">Year ended December 31</td></tr><tr><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Total financing interest and debt costs</td><td>$ 288</td><td>$ 317</td><td>$ 301</td></tr><tr><td>Less: Capitalized interest</td><td>288</td><td>267</td><td>273</td></tr><tr><td>Interest and debt expense</td><td>$ -</td><td>$ 50</td><td>$ 28</td></tr><tr><td>Research and development expenses</td><td>$ 627</td><td>$ 526</td><td>$ 603</td></tr><tr><td>Foreign currency effects*</td><td>$ 121</td><td>$ (423)</td><td>$ (744)</td></tr></table>

*Includes $(27), $(71) and $(194) in 2011, 2010 and 2009, respectively, for the company’s share of equity affiliates’ foreign currency effects.

The excess of replacement cost over the carrying value of inventories for which the last-in, first-out (LIFO) method is used was $9,025 and $6,975 at December 31, 2011 and 2010, respectively. Replacement cost is generally based on average acquisition costs for the year. LIFO profits (charges) of $193, $21 and $168) were included in earnings for the years 2011, 2010 and 2009, respectively.

The company has $4,642 in goodwill on the Consolidated Balance Sheet related to the 2005 acquisition of Unocal and to the 2011 acquisition of Atlas Energy, Inc. Under the accounting standard for goodwill (ASC 350), the company tested this goodwill for impairment during 2011 and concluded no impairment was necessary.



## Note 27

Earnings Per Share

Basic earnings per share (EPS) is based upon “Net Income Attributable to Chevron Corporation” (“earnings”) and includes the effects of deferrals of salary and other compensation awards that are invested in Chevron stock units by certain officers and employees of the company. Diluted EPS includes the effects of these items as well as the dilutive effects of outstanding stock options awarded under the company’s stock option programs (refer to Note 20, “Stock Options and Other Share-Based Compensation,” beginning on page 56). The table below sets forth the computation of basic and diluted EPS:

<table><tr><td rowspan="2"></td><td colspan="3">Year ended December 31</td></tr><tr><td>2011</td><td>2010</td><td>2009</td></tr><tr><td>Basic EPS Calculation</td><td></td><td></td><td></td></tr><tr><td>Earnings available to common stockholders - Basic*</td><td>$ 26,895</td><td>$ 19,024</td><td>$ 10,483</td></tr><tr><td>Weighted-average number of common shares outstanding</td><td>1,986</td><td>1,996</td><td>1,991</td></tr><tr><td>Add: Deferred awards held as stock units</td><td>-</td><td>1</td><td>1</td></tr><tr><td>Total weighted-average number of common shares outstanding</td><td>1,986</td><td>1,997</td><td>1,992</td></tr><tr><td>Earnings per share of common stock - Basic</td><td>$ 13.54</td><td>$ 9.53</td><td>$ 5.26</td></tr><tr><td>Diluted EPS Calculation</td><td></td><td></td><td></td></tr><tr><td>Earnings available to common stockholders - Diluted*</td><td>$ 26,895</td><td>$ 19,024</td><td>$ 10,483</td></tr><tr><td>Weighted-average number of common shares outstanding</td><td>1,986</td><td>1,996</td><td>1,991</td></tr><tr><td>Add: Deferred awards held as stock units</td><td>-</td><td>1</td><td>1</td></tr><tr><td>Add: Dilutive effect of employee stock-based awards</td><td>15</td><td>10</td><td>9</td></tr><tr><td>Total weighted-average number of common shares outstanding</td><td>2,001</td><td>2,007</td><td>2,001</td></tr><tr><td>Earnings per share of common stock - Diluted</td><td>$ 13.44</td><td>$ 9.48</td><td>$ 5.24</td></tr></table>

 \( ^{*} \) There was no effect of dividend equivalents paid on stock units or dilutive impact of employee stock-based awards on earnings.



<table><tr><td>Millions of dollars, except per-share amounts</td><td>2011</td><td>2010</td><td>2009</td><td>2008</td><td>2007</td></tr><tr><td>Statement of Income Data</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revenues and Other Income</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total sales and other operating revenues*</td><td>$ 244,371</td><td>$ 198,198</td><td>$ 167,402</td><td>$ 264,958</td><td>$ 214,091</td></tr><tr><td>Income from equity affiliates and other income</td><td>9,335</td><td>6,730</td><td>4,234</td><td>8,047</td><td>6,813</td></tr><tr><td>Total Revenues and Other Income</td><td>253,706</td><td>204,928</td><td>171,636</td><td>273,005</td><td>220,904</td></tr><tr><td>Total Costs and Other Deductions</td><td>206,072</td><td>172,873</td><td>153,108</td><td>229,948</td><td>188,630</td></tr><tr><td>Income Before Income Tax Expense</td><td>47,634</td><td>32,055</td><td>18,528</td><td>43,057</td><td>32,274</td></tr><tr><td>Income Tax Expense</td><td>20,626</td><td>12,919</td><td>7,965</td><td>19,026</td><td>13,479</td></tr><tr><td>Net Income</td><td>27,008</td><td>19,136</td><td>10,563</td><td>24,031</td><td>18,795</td></tr><tr><td>Less: Net income attributable to noncontrolling interests</td><td>113</td><td>112</td><td>80</td><td>100</td><td>107</td></tr><tr><td>Net Income Attributable to Chevron Corporation</td><td>$ 26,895</td><td>$ 19,024</td><td>$ 10,483</td><td>$ 23,931</td><td>$ 18,688</td></tr><tr><td>Per Share of Common Stock</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net Income Attributable to Chevron</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>- Basic</td><td>$ 13.54</td><td>$ 9.53</td><td>$ 5.26</td><td>$ 11.74</td><td>$ 8.83</td></tr><tr><td>- Diluted</td><td>$ 13.44</td><td>$ 9.48</td><td>$ 5.24</td><td>$ 11.67</td><td>$ 8.77</td></tr><tr><td>Cash Dividends Per Share</td><td>$ 3.09</td><td>$ 2.84</td><td>$ 2.66</td><td>$ 2.53</td><td>$ 2.26</td></tr><tr><td>Balance Sheet Data (at December 31)</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Current assets</td><td>$ 53,234</td><td>$ 48,841</td><td>$ 37,216</td><td>$ 36,470</td><td>$ 39,377</td></tr><tr><td>Noncurrent assets</td><td>156,240</td><td>135,928</td><td>127,405</td><td>124,695</td><td>109,409</td></tr><tr><td>Total Assets</td><td>209,474</td><td>184,769</td><td>164,621</td><td>161,165</td><td>148,786</td></tr><tr><td>Short-term debt</td><td>340</td><td>187</td><td>384</td><td>2,818</td><td>1,162</td></tr><tr><td>Other current liabilities</td><td>33,260</td><td>28,825</td><td>25,827</td><td>29,205</td><td>32,636</td></tr><tr><td>Long-term debt and capital lease obligations</td><td>9,812</td><td>11,289</td><td>10,130</td><td>6,083</td><td>6,070</td></tr><tr><td>Other noncurrent liabilities</td><td>43,881</td><td>38,657</td><td>35,719</td><td>35,942</td><td>31,626</td></tr><tr><td>Total Liabilities</td><td>87,293</td><td>78,958</td><td>72,060</td><td>74,048</td><td>71,494</td></tr><tr><td>Total Chevron Corporation Stockholders&#x27; Equity</td><td>$ 121,382</td><td>$ 105,081</td><td>$ 91,914</td><td>$ 86,648</td><td>$ 77,088</td></tr><tr><td>Noncontrolling interests</td><td>799</td><td>730</td><td>647</td><td>469</td><td>204</td></tr><tr><td>Total Equity</td><td>$ 122,181</td><td>$ 105,811</td><td>$ 92,561</td><td>$ 87,117</td><td>$ 77,292</td></tr><tr><td>*Includes excise, value-added and similar taxes:</td><td>$ 8,085</td><td>$ 8,591</td><td>$ 8,109</td><td>$ 9,846</td><td>$ 10,121</td></tr></table>



<table><tr><td colspan="6">Worldwide - Includes Equity in Affiliates</td></tr><tr><td colspan="6">Thousands of barrels per day, except natural gas data, which is millions of cubic feet per day</td></tr><tr><td>United States</td><td>2011</td><td>2010</td><td>2009</td><td>2008</td><td>2007</td></tr><tr><td>Net production of crude oil and natural gas liquids</td><td>465</td><td>489</td><td>484</td><td>421</td><td>460</td></tr><tr><td>Net production of natural gas \( ^{1} \)</td><td>1,279</td><td>1,314</td><td>1,399</td><td>1,501</td><td>1,699</td></tr><tr><td>Net oil-equivalent production</td><td>678</td><td>708</td><td>717</td><td>671</td><td>743</td></tr><tr><td>Refinery input</td><td>854</td><td>890</td><td>899</td><td>891</td><td>812</td></tr><tr><td>Sales of refined products</td><td>1,257</td><td>1,349</td><td>1,403</td><td>1,413</td><td>1,457</td></tr><tr><td>Sales of natural gas liquids</td><td>161</td><td>161</td><td>161</td><td>159</td><td>160</td></tr><tr><td>Total sales of petroleum products</td><td>1,418</td><td>1,510</td><td>1,564</td><td>1,572</td><td>1,617</td></tr><tr><td>Sales of natural gas</td><td>5,836</td><td>5,932</td><td>5,901</td><td>7,226</td><td>7,624</td></tr><tr><td>International</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net production of crude oil and natural gas liquids \( ^{2} \)</td><td>1,384</td><td>1,434</td><td>1,362</td><td>1,228</td><td>1,296</td></tr><tr><td>Other produced volumes \( ^{3} \)</td><td>-</td><td>-</td><td>26</td><td>27</td><td>27</td></tr><tr><td>Net production of natural gas \( ^{1} \)</td><td>3,662</td><td>3,726</td><td>3,590</td><td>3,624</td><td>3,320</td></tr><tr><td>Net oil-equivalent production</td><td>1,995</td><td>2,055</td><td>1,987</td><td>1,859</td><td>1,876</td></tr><tr><td>Refinery input</td><td>933</td><td>1,004</td><td>979</td><td>967</td><td>1,021</td></tr><tr><td>Sales of refined products</td><td>1,692</td><td>1,764</td><td>1,851</td><td>2,016</td><td>2,027</td></tr><tr><td>Sales of natural gas liquids</td><td>87</td><td>105</td><td>111</td><td>114</td><td>118</td></tr><tr><td>Total sales of petroleum products</td><td>1,779</td><td>1,869</td><td>1,962</td><td>2,130</td><td>2,145</td></tr><tr><td>Sales of natural gas</td><td>4,361</td><td>4,493</td><td>4,062</td><td>4,215</td><td>3,792</td></tr><tr><td>Total Worldwide</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net production of crude oil and natural gas liquids</td><td>1,849</td><td>1,923</td><td>1,846</td><td>1,649</td><td>1,756</td></tr><tr><td>Other produced volumes</td><td>-</td><td>-</td><td>26</td><td>27</td><td>27</td></tr><tr><td>Net production of natural gas \( ^{1} \)</td><td>4,941</td><td>5,040</td><td>4,989</td><td>5,125</td><td>5,019</td></tr><tr><td>Net oil-equivalent production</td><td>2,673</td><td>2,763</td><td>2,704</td><td>2,530</td><td>2,619</td></tr><tr><td>Refinery input</td><td>1,787</td><td>1,894</td><td>1,878</td><td>1,858</td><td>1,833</td></tr><tr><td>Sales of refined products</td><td>2,949</td><td>3,113</td><td>3,254</td><td>3,429</td><td>3,484</td></tr><tr><td>Sales of natural gas liquids</td><td>248</td><td>266</td><td>272</td><td>273</td><td>278</td></tr><tr><td>Total sales of petroleum products</td><td>3,197</td><td>3,379</td><td>3,526</td><td>3,702</td><td>3,762</td></tr><tr><td>Sales of natural gas</td><td>10,197</td><td>10,425</td><td>9,963</td><td>11,441</td><td>11,416</td></tr><tr><td>Worldwide - Excludes Equity in Affiliates</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Number of wells completed (net) \( ^{4} \)</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Oil and gas</td><td>1,551</td><td>1,160</td><td>1,265</td><td>1,648</td><td>1,633</td></tr><tr><td>Dry</td><td>27</td><td>31</td><td>24</td><td>12</td><td>30</td></tr><tr><td>Productive oil and gas wells (net) \( ^{4} \)</td><td>55,049</td><td>52,677</td><td>51,326</td><td>51,262</td><td>51,528</td></tr><tr><td> \( ^{1} \)  Includes natural gas consumed in operations:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>United States</td><td>69</td><td>62</td><td>58</td><td>70</td><td>65</td></tr><tr><td>International</td><td>513</td><td>475</td><td>463</td><td>450</td><td>433</td></tr><tr><td>Total</td><td>582</td><td>537</td><td>521</td><td>520</td><td>498</td></tr><tr><td>Drops off after 2006</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td> \( ^{2} \)  Includes: Canada-synthetic oil</td><td>40</td><td>24</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Venezuela affiliate-synthetic oil</td><td>32</td><td>28</td><td>-</td><td>-</td><td>-</td></tr><tr><td> \( ^{3} \)  Includes: Canada oil sands</td><td>-</td><td>-</td><td>26</td><td>27</td><td>27</td></tr><tr><td>Boscan operating service agreement in Venezuela</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td></tr><tr><td colspan="6">\( ^{4} \)  Net wells include wholly owned and the sum of fractional interests in partially owned wells.</td></tr></table>



the company’s estimated net proved-reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows. The Africa geographic area includes activities principally in Angola, Chad, Democratic Republic of the Congo, Nigeria, and Republic of the Congo. The Asia geographic area includes activities principally in Azerbaijan, Bangladesh, China, Indonesia, Kazakhstan, Myanmar, the Partitioned Zone between Kuwait and Saudi Arabia, the Philippines and Thailand. The Europe geographic area includes activity

in Denmark, the Netherlands, Norway and the United Kingdom. The Other Americas geographic region includes activities in Argentina, Brazil, Canada, Colombia, and Trinidad and Tobago. Amounts for TCO represent Chevron’s 50 percent equity share of Tengizchevroil, an exploration and production partnership in the Republic of Kazakhstan. The affiliated companies Other amounts are composed of the company’s equity interests in Venezuela and Angola. Refer to Note 12, beginning on page 47, for a discussion of the company’s major equity affiliates.

Table II - Capitalized Costs Related to Oil and Gas Producing Activities

<table><tr><td rowspan="2">Millions of dollars</td><td rowspan="2">U.S.</td><td colspan="9">Consolidated Companies</td><td colspan="2">Affiliated Companies</td></tr><tr><td>Other Americas</td><td>Africa</td><td>Asia</td><td>Australia</td><td>Europe</td><td>Total</td><td>TCO</td><td>Other</td><td></td><td></td><td></td></tr><tr><td>At December 31, 2011</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Unproved properties</td><td>$ 9,806</td><td>$ 1,417</td><td>$ 368</td><td>$ 2,408</td><td>$ 6</td><td>$ 33</td><td>$ 14,038</td><td>$ 109</td><td>$ -</td><td></td><td></td><td></td></tr><tr><td>Proved properties and related producing assets</td><td>57,674</td><td>11,029</td><td>25,549</td><td>36,740</td><td>2,244</td><td>9,549</td><td>142,785</td><td>6,583</td><td>1,607</td><td></td><td></td><td></td></tr><tr><td>Support equipment</td><td>1,071</td><td>292</td><td>1,362</td><td>1,544</td><td>533</td><td>169</td><td>4,971</td><td>1,018</td><td>-</td><td></td><td></td><td></td></tr><tr><td>Deferred exploratory wells</td><td>565</td><td>63</td><td>629</td><td>260</td><td>709</td><td>208</td><td>2,434</td><td>-</td><td>-</td><td></td><td></td><td></td></tr><tr><td>Other uncompleted projects</td><td>4,887</td><td>2,408</td><td>4,773</td><td>3,109</td><td>6,076</td><td>492</td><td>21,745</td><td>605</td><td>1,466</td><td></td><td></td><td></td></tr><tr><td>Gross Capitalized Costs</td><td>74,003</td><td>15,209</td><td>32,681</td><td>44,061</td><td>9,568</td><td>10,451</td><td>185,973</td><td>8,315</td><td>3,073</td><td></td><td></td><td></td></tr><tr><td>Unproved properties valuation</td><td>1,085</td><td>498</td><td>178</td><td>262</td><td>2</td><td>13</td><td>2,038</td><td>38</td><td>-</td><td></td><td></td><td></td></tr><tr><td>Proved producing properties - Depreciation and depletion</td><td>39,210</td><td>4,826</td><td>13,173</td><td>20,991</td><td>1,574</td><td>7,742</td><td>87,516</td><td>1,910</td><td>436</td><td></td><td></td><td></td></tr><tr><td>Support equipment depreciation</td><td>530</td><td>175</td><td>715</td><td>1,192</td><td>238</td><td>129</td><td>2,979</td><td>451</td><td>-</td><td></td><td></td><td></td></tr><tr><td>Accumulated provisions</td><td>40,825</td><td>5,499</td><td>14,066</td><td>22,445</td><td>1,814</td><td>7,884</td><td>92,533</td><td>2,399</td><td>436</td><td></td><td></td><td></td></tr><tr><td>Net Capitalized Costs</td><td>$ 33,178</td><td>$ 9,710</td><td>$ 18,615</td><td>$ 21,616</td><td>$ 7,754</td><td>$ 2,567</td><td>$ 93,440</td><td>$ 5,916</td><td>$ 2,637</td><td></td><td></td><td></td></tr><tr><td>At December 31, 2010</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Unproved properties</td><td>$ 2,553</td><td>$ 1,349</td><td>$ 359</td><td>$ 2,561</td><td>$ 6</td><td>$ 8</td><td>$ 6,836</td><td>$ 108</td><td>$ -</td><td></td><td></td><td></td></tr><tr><td>Proved properties and related producing assets</td><td>55,601</td><td>7,747</td><td>23,683</td><td>33,316</td><td>2,585</td><td>9,035</td><td>131,967</td><td>6,512</td><td>1,594</td><td></td><td></td><td></td></tr><tr><td>Support equipment</td><td>975</td><td>265</td><td>1,282</td><td>1,421</td><td>259</td><td>165</td><td>4,367</td><td>985</td><td>-</td><td></td><td></td><td></td></tr><tr><td>Deferred exploratory wells</td><td>743</td><td>210</td><td>611</td><td>224</td><td>732</td><td>198</td><td>2,718</td><td>-</td><td>-</td><td></td><td></td><td></td></tr><tr><td>Other uncompleted projects</td><td>2,299</td><td>3,844</td><td>4,061</td><td>3,627</td><td>3,631</td><td>362</td><td>17,824</td><td>357</td><td>1,001</td><td></td><td></td><td></td></tr><tr><td>Gross Capitalized Costs</td><td>62,171</td><td>13,415</td><td>29,996</td><td>41,149</td><td>7,213</td><td>9,768</td><td>163,712</td><td>7,962</td><td>2,595</td><td></td><td></td><td></td></tr><tr><td>Unproved properties valuation</td><td>967</td><td>436</td><td>150</td><td>200</td><td>2</td><td>-</td><td>1,755</td><td>34</td><td>-</td><td></td><td></td><td></td></tr><tr><td>Proved producing properties - Depreciation and depletion</td><td>37,682</td><td>3,986</td><td>10,986</td><td>18,197</td><td>1,718</td><td>7,162</td><td>79,731</td><td>1,530</td><td>249</td><td></td><td></td><td></td></tr><tr><td>Support equipment depreciation</td><td>518</td><td>153</td><td>600</td><td>1,126</td><td>84</td><td>114</td><td>2,595</td><td>402</td><td>-</td><td></td><td></td><td></td></tr><tr><td>Accumulated provisions</td><td>39,167</td><td>4,575</td><td>11,736</td><td>19,523</td><td>1,804</td><td>7,276</td><td>84,081</td><td>1,966</td><td>249</td><td></td><td></td><td></td></tr><tr><td>Net Capitalized Costs</td><td>$ 23,004</td><td>$ 8,840</td><td>$ 18,260</td><td>$ 21,626</td><td>$ 5,409</td><td>$ 2,492</td><td>$ 79,631</td><td>$ 5,996</td><td>$ 2,346</td><td></td><td></td><td></td></tr></table>



<table><tr><td rowspan="2">Millions of dollars</td><td rowspan="2">U.S.</td><td rowspan="2">Other Americas</td><td rowspan="2">Africa</td><td rowspan="2">Asia</td><td rowspan="2">Australia</td><td rowspan="2">Europe</td><td rowspan="2">Total</td><td colspan="2">Consolidated Companies</td><td colspan="2">Affiliated Companies</td></tr><tr><td>TCO</td><td>Other</td><td></td></tr><tr><td>At December 31, 2009</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Unproved properties</td><td>$ 2,320</td><td>$ 946</td><td>$ 321</td><td>$ 3,355</td><td>$ 7</td><td>$ 10</td><td>$ 6,959</td><td>$ 113</td><td>$</td><td>-</td><td></td></tr><tr><td>Proved properties and related producing assets</td><td>51,582</td><td>6,033</td><td>20,967</td><td>29,637</td><td>2,507</td><td>8,727</td><td>119,453</td><td>6,404</td><td>1,759</td><td></td><td></td></tr><tr><td>Support equipment</td><td>810</td><td>323</td><td>1,012</td><td>1,383</td><td>162</td><td>163</td><td>3,853</td><td>947</td><td>-</td><td></td><td></td></tr><tr><td>Deferred exploratory wells</td><td>762</td><td>216</td><td>603</td><td>209</td><td>440</td><td>205</td><td>2,435</td><td>-</td><td>-</td><td></td><td></td></tr><tr><td>Other uncompleted projects</td><td>2,384</td><td>4,106</td><td>3,960</td><td>2,936</td><td>1,274</td><td>192</td><td>14,852</td><td>284</td><td>58</td><td></td><td></td></tr><tr><td>Gross Capitalized Costs</td><td>57,858</td><td>11,624</td><td>26,863</td><td>37,520</td><td>4,390</td><td>9,297</td><td>147,552</td><td>7,748</td><td>1,817</td><td></td><td></td></tr><tr><td>Unproved properties valuation</td><td>915</td><td>391</td><td>163</td><td>170</td><td>1</td><td>(2)</td><td>1,638</td><td>32</td><td>-</td><td></td><td></td></tr><tr><td>Proved producing properties - Depreciation and depletion</td><td>34,574</td><td>3,182</td><td>8,823</td><td>15,783</td><td>1,579</td><td>6,482</td><td>70,423</td><td>1,150</td><td>282</td><td></td><td></td></tr><tr><td>Support equipment depreciation</td><td>424</td><td>197</td><td>526</td><td>773</td><td>58</td><td>102</td><td>2,080</td><td>356</td><td>-</td><td></td><td></td></tr><tr><td>Accumulated provisions</td><td>35,913</td><td>3,770</td><td>9,512</td><td>16,726</td><td>1,638</td><td>6,582</td><td>74,141</td><td>1,538</td><td>282</td><td></td><td></td></tr><tr><td>Net Capitalized Costs</td><td>$ 21,945</td><td>$ 7,854</td><td>$ 17,351</td><td>$ 20,794</td><td>$ 2,752</td><td>$ 2,715</td><td>$ 73,411</td><td>$ 6,210</td><td>$ 1,535</td><td></td><td></td></tr></table>



The company’s results of operations from oil and gas producing activities for the years 2011, 2010 and 2009 are shown in the following table. Net income from exploration and production activities as reported on page 46 reflects income taxes computed on an effective rate basis. Income taxes in Table III are based on statutory tax rates, reflecting allowable deductions and tax credits. Interest income and expense are excluded from the results reported in Table III and from the net income amounts on page 46.

<table><tr><td rowspan="2">Millions of dollars</td><td rowspan="2">U.S.</td><td colspan="8">Consolidated Companies</td><td colspan="2">Affiliated Companies</td></tr><tr><td>Other Americas</td><td>Africa</td><td>Asia</td><td>Australia</td><td>Europe</td><td>Total</td><td>TCO</td><td>Other</td><td></td><td></td></tr><tr><td>Year Ended December 31, 2011</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revenues from net production</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Sales</td><td>$ 2,508</td><td>$ 1,672</td><td>$ 1,174</td><td>$ 9,431</td><td>$ 1,474</td><td>$ 1,868</td><td>$ 18,127</td><td>$ 8,581</td><td>$ 1,988</td><td></td><td></td><td></td></tr><tr><td>Transfers</td><td>15,811</td><td>3,724</td><td>15,726</td><td>8,962</td><td>1,012</td><td>2,672</td><td>47,907</td><td>-</td><td>-</td><td></td><td></td><td></td></tr><tr><td>Total</td><td>18,319</td><td>5,396</td><td>16,900</td><td>18,393</td><td>2,486</td><td>4,540</td><td>66,034</td><td>8,581</td><td>1,988</td><td></td><td></td><td></td></tr><tr><td>Production expenses excluding taxes</td><td>(3,668)</td><td>(1,061)</td><td>(1,526)</td><td>(4,489)</td><td>(117)</td><td>(564)</td><td>(11,425)</td><td>(449)</td><td>(235)</td><td></td><td></td><td></td></tr><tr><td>Taxes other than on income</td><td>(597)</td><td>(137)</td><td>(153)</td><td>(242)</td><td>(396)</td><td>(2)</td><td>(1,527)</td><td>(429)</td><td>(815)</td><td></td><td></td><td></td></tr><tr><td>Proved producing properties:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Depreciation and depletion</td><td>(3,366)</td><td>(796)</td><td>(2,225)</td><td>(2,923)</td><td>(136)</td><td>(580)</td><td>(10,026)</td><td>(442)</td><td>(140)</td><td></td><td></td><td></td></tr><tr><td>Accretion expense²</td><td>(291)</td><td>(27)</td><td>(106)</td><td>(81)</td><td>(18)</td><td>(39)</td><td>(562)</td><td>(8)</td><td>(4)</td><td></td><td></td><td></td></tr><tr><td>Exploration expenses</td><td>(207)</td><td>(144)</td><td>(188)</td><td>(271)</td><td>(128)</td><td>(277)</td><td>(1,215)</td><td>-</td><td>-</td><td></td><td></td><td></td></tr><tr><td>Unproved properties valuation</td><td>(134)</td><td>(146)</td><td>(27)</td><td>(60)</td><td>-</td><td>(14)</td><td>(381)</td><td>-</td><td>-</td><td></td><td></td><td></td></tr><tr><td>Other income (expense)³</td><td>163</td><td>(1,191)</td><td>(409)</td><td>231</td><td>(18)</td><td>(74)</td><td>(1,298)</td><td>(8)</td><td>(29)</td><td></td><td></td><td></td></tr><tr><td>Results before income taxes</td><td>10,219</td><td>1,894</td><td>12,266</td><td>10,558</td><td>1,673</td><td>2,990</td><td>39,600</td><td>7,245</td><td>765</td><td></td><td></td><td></td></tr><tr><td>Income tax expense</td><td>(3,728)</td><td>(535)</td><td>(7,802)</td><td>(5,374)</td><td>(507)</td><td>(1,913)</td><td>(19,859)</td><td>(2,176)</td><td>(392)</td><td></td><td></td><td></td></tr><tr><td>Results of Producing Operations</td><td>$ 6,491</td><td>$ 1,359</td><td>$ 4,464</td><td>$ 5,184</td><td>$ 1,166</td><td>$ 1,077</td><td>$ 19,741</td><td>$ 5,069</td><td>$ 373</td><td></td><td></td><td></td></tr><tr><td>Year Ended December 31, 2010</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revenues from net production</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Sales</td><td>$ 2,540</td><td>$ 2,441</td><td>$ 2,278</td><td>$ 7,221</td><td>$ 994</td><td>$ 1,519</td><td>$ 16,993</td><td>$ 6,031</td><td>$ 1,307</td><td></td><td></td><td></td></tr><tr><td>Transfers</td><td>12,172</td><td>1,038</td><td>10,306</td><td>6,242</td><td>985</td><td>2,138</td><td>32,881</td><td>-</td><td>-</td><td></td><td></td><td></td></tr><tr><td>Total</td><td>14,712</td><td>3,479</td><td>12,584</td><td>13,463</td><td>1,979</td><td>3,657</td><td>49,874</td><td>6,031</td><td>1,307</td><td></td><td></td><td></td></tr><tr><td>Production expenses excluding taxes</td><td>(3,338)</td><td>(805)</td><td>(1,413)</td><td>(2,996)</td><td>(96)</td><td>(534)</td><td>(9,182)</td><td>(347)</td><td>(152)</td><td></td><td></td><td></td></tr><tr><td>Taxes other than on income</td><td>(542)</td><td>(102)</td><td>(130)</td><td>(85)</td><td>(334)</td><td>(2)</td><td>(1,195)</td><td>(360)</td><td>(101)</td><td></td><td></td><td></td></tr><tr><td>Proved producing properties:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Depreciation and depletion</td><td>(3,639)</td><td>(907)</td><td>(2,204)</td><td>(2,816)</td><td>(151)</td><td>(681)</td><td>(10,398)</td><td>(432)</td><td>(131)</td><td></td><td></td><td></td></tr><tr><td>Accretion expense²</td><td>(240)</td><td>(23)</td><td>(102)</td><td>(35)</td><td>(15)</td><td>(53)</td><td>(468)</td><td>(8)</td><td>(5)</td><td></td><td></td><td></td></tr><tr><td>Exploration expenses</td><td>(193)</td><td>(173)</td><td>(242)</td><td>(289)</td><td>(175)</td><td>(75)</td><td>(1,147)</td><td>(5)</td><td>-</td><td></td><td></td><td></td></tr><tr><td>Unproved properties valuation</td><td>(123)</td><td>(71)</td><td>(25)</td><td>(33)</td><td>-</td><td>(2)</td><td>(254)</td><td>-</td><td>-</td><td></td><td></td><td></td></tr><tr><td>Other income (expense)³</td><td>(154)</td><td>(818)</td><td>(103)</td><td>(282)</td><td>109</td><td>165</td><td>(1,083)</td><td>(65)</td><td>191</td><td></td><td></td><td></td></tr><tr><td>Results before income taxes</td><td>6,483</td><td>580</td><td>8,365</td><td>6,927</td><td>1,317</td><td>2,475</td><td>26,147</td><td>4,814</td><td>1,109</td><td></td><td></td><td></td></tr><tr><td>Income tax expense⁴</td><td>(2,273)</td><td>(223)</td><td>(4,535)</td><td>(3,886)</td><td>(325)</td><td>(1,455)</td><td>(12,697)</td><td>(1,445)</td><td>(615)</td><td></td><td></td><td></td></tr><tr><td>Results of Producing Operations</td><td>$ 4,210</td><td>$ 357</td><td>$ 3,830</td><td>$ 3,041</td><td>$ 992</td><td>$ 1,020</td><td>$ 13,450</td><td>$ 3,369</td><td>$ 494</td><td></td><td></td><td></td></tr></table>

 \( ^{1} \)  The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations.

 \( ^{2} \)  Represents accretion of ARO liability. Refer to Note 25, “Asset Retirement Obligations,” on page 66.

 \( ^{3} \)  Includes foreign currency gains and losses, gains and losses on property dispositions, and income from operating and technical service agreements.

 \( ^{4} \)  Income tax expense for 2010 conformed to 2011 presentation for certain tax items.



<table><tr><td rowspan="2">Millions of dollars</td><td rowspan="2">U.S.</td><td rowspan="2">Other Americas</td><td rowspan="2">Africa</td><td rowspan="2">Asia</td><td rowspan="2">Australia</td><td colspan="3">Consolidated Companies</td><td colspan="2">Affiliated Companies</td></tr><tr><td>Europe</td><td>Total</td><td>TCO</td><td>Other</td><td></td></tr><tr><td>Year Ended December 31, 2009</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revenues from net production</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Sales</td><td>$ 2,278</td><td>$ 918</td><td>$ 1,767</td><td>$ 5,648</td><td>$ 543</td><td>$ 1,712</td><td>$ 12,866</td><td>$ 4,043</td><td>$ 938</td><td></td><td></td><td></td></tr><tr><td>Transfers</td><td>9,133</td><td>1,555</td><td>7,304</td><td>4,926</td><td>765</td><td>1,546</td><td>25,229</td><td>-</td><td>-</td><td></td><td></td><td></td></tr><tr><td>Total</td><td>11,411</td><td>2,473</td><td>9,071</td><td>10,574</td><td>1,308</td><td>3,258</td><td>38,095</td><td>4,043</td><td>938</td><td></td><td></td><td></td></tr><tr><td>Production expenses excluding taxes</td><td>(3,281)</td><td>(731)</td><td>(1,345)</td><td>(2,208)</td><td>(94)</td><td>(565)</td><td>(8,224)</td><td>(363)</td><td>(240)</td><td></td><td></td><td></td></tr><tr><td>Taxes other than on income</td><td>(367)</td><td>(90)</td><td>(132)</td><td>(53)</td><td>(190)</td><td>(4)</td><td>(836)</td><td>(50)</td><td>(96)</td><td></td><td></td><td></td></tr><tr><td>Proved producing properties:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Depreciation and depletion</td><td>(3,493)</td><td>(486)</td><td>(2,175)</td><td>(2,279)</td><td>(214)</td><td>(898)</td><td>(9,545)</td><td>(381)</td><td>(88)</td><td></td><td></td><td></td></tr><tr><td>Accretion expense \( ^{2} \)</td><td>(194)</td><td>(27)</td><td>(66)</td><td>(70)</td><td>(2)</td><td>(50)</td><td>(409)</td><td>(7)</td><td>(3)</td><td></td><td></td><td></td></tr><tr><td>Exploration expenses</td><td>(451)</td><td>(203)</td><td>(236)</td><td>(113)</td><td>(224)</td><td>(115)</td><td>(1,342)</td><td>-</td><td>-</td><td></td><td></td><td></td></tr><tr><td>Unproved properties valuation</td><td>(228)</td><td>(28)</td><td>(11)</td><td>(44)</td><td>-</td><td>-</td><td>(311)</td><td>-</td><td>-</td><td></td><td></td><td></td></tr><tr><td>Other income (expense) \( ^{3} \)</td><td>156</td><td>(508)</td><td>98</td><td>(327)</td><td>350</td><td>(182)</td><td>(413)</td><td>(131)</td><td>9</td><td></td><td></td><td></td></tr><tr><td>Results before income taxes</td><td>3,553</td><td>400</td><td>5,204</td><td>5,480</td><td>934</td><td>1,444</td><td>17,015</td><td>3,111</td><td>520</td><td></td><td></td><td></td></tr><tr><td>Income tax expense</td><td>(1,258)</td><td>(203)</td><td>(3,214)</td><td>(2,921)</td><td>(256)</td><td>(901)</td><td>(8,753)</td><td>(935)</td><td>(258)</td><td></td><td></td><td></td></tr><tr><td>Results of Producing Operations</td><td>$ 2,295</td><td>$ 197</td><td>$ 1,990</td><td>$ 2,559</td><td>$ 678</td><td>$ 543</td><td>$ 8,262</td><td>$ 2,176</td><td>$ 262</td><td></td><td></td><td></td></tr></table>

 \( ^{1} \)  The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations.

 \( ^{2} \)  Represents accretion of ARO liability. Refer to Note 25, “Asset Retirement Obligations,” on page 66.

 \( ^{3} \)  Includes foreign currency gains and losses, gains and losses on property dispositions, and income from operating and technical service agreements.



Summary of Net Oil and Gas Reserves

<table><tr><td rowspan="2"></td><td colspan="6">2011*</td><td colspan="6">2010*</td><td colspan="6">2009*</td></tr><tr><td>Crude Oil Condensate NGLs</td><td>Synthetic Oil</td><td>Natural Gas</td><td>Crude Oil Condensate NGLs</td><td>Synthetic Oil</td><td>Natural Gas</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Liquids and Synthetic Oil in Millions of Barrels Natural Gas in Billions of Cubic Feet</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Proved Developed</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Consolidated Companies</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>U.S.</td><td>990</td><td>-</td><td>2,486</td><td>1,045</td><td>-</td><td>2,113</td><td>1,122</td><td>-</td><td>2,314</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Other Americas</td><td>82</td><td>403</td><td>1,147</td><td>84</td><td>352</td><td>1,490</td><td>66</td><td>190</td><td>1,678</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Africa</td><td>792</td><td>-</td><td>1,276</td><td>830</td><td>-</td><td>1,304</td><td>820</td><td>-</td><td>978</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Asia</td><td>703</td><td>-</td><td>4,300</td><td>826</td><td>-</td><td>4,836</td><td>926</td><td>-</td><td>5,062</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Australia</td><td>39</td><td>-</td><td>813</td><td>39</td><td>-</td><td>881</td><td>50</td><td>-</td><td>1,071</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Europe</td><td>116</td><td>-</td><td>204</td><td>136</td><td>-</td><td>235</td><td>151</td><td>-</td><td>302</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total Consolidated</td><td>2,722</td><td>403</td><td>10,226</td><td>2,960</td><td>352</td><td>10,859</td><td>3,135</td><td>190</td><td>11,405</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Affiliated Companies</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>TCO</td><td>1,019</td><td>-</td><td>1,400</td><td>1,128</td><td>-</td><td>1,484</td><td>1,256</td><td>-</td><td>1,830</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Other</td><td>93</td><td>50</td><td>75</td><td>95</td><td>53</td><td>70</td><td>97</td><td>56</td><td>73</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total Consolidated and Affiliated Companies</td><td>3,834</td><td>453</td><td>11,701</td><td>4,183</td><td>405</td><td>12,413</td><td>4,488</td><td>246</td><td>13,308</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Proved Undeveloped</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Consolidated Companies</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>U.S.</td><td>321</td><td>-</td><td>1,160</td><td>230</td><td>-</td><td>359</td><td>239</td><td>-</td><td>384</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Other Americas</td><td>31</td><td>120</td><td>517</td><td>24</td><td>114</td><td>325</td><td>38</td><td>270</td><td>307</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Africa</td><td>363</td><td>-</td><td>1,920</td><td>338</td><td>-</td><td>1,640</td><td>426</td><td>-</td><td>2,043</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Asia</td><td>191</td><td>-</td><td>2,421</td><td>187</td><td>-</td><td>2,357</td><td>245</td><td>-</td><td>2,798</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Australia</td><td>101</td><td>-</td><td>8,931</td><td>49</td><td>-</td><td>5,175</td><td>48</td><td>-</td><td>5,174</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Europe</td><td>43</td><td>-</td><td>54</td><td>16</td><td>-</td><td>40</td><td>19</td><td>-</td><td>42</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total Consolidated</td><td>1,050</td><td>120</td><td>15,003</td><td>844</td><td>114</td><td>9,896</td><td>1,015</td><td>270</td><td>10,748</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Affiliated Companies</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>TCO</td><td>740</td><td>-</td><td>851</td><td>692</td><td>-</td><td>902</td><td>690</td><td>-</td><td>1,003</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Other</td><td>64</td><td>194</td><td>1,128</td><td>62</td><td>203</td><td>1,040</td><td>54</td><td>210</td><td>990</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total Consolidated and Affiliated Companies</td><td>1,854</td><td>314</td><td>16,982</td><td>1,598</td><td>317</td><td>11,838</td><td>1,759</td><td>480</td><td>12,741</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total Proved Reserves</td><td>5,688</td><td>767</td><td>28,683</td><td>5,781</td><td>722</td><td>24,251</td><td>6,247</td><td>726</td><td>26,049</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr></table>

* Based on 12-month average price.

estimates and changes; confirm that proved reserves are recognized in accordance with SEC guidelines; determine that reserve volumes are calculated using consistent and appropriate standards, procedures and technology; and maintain the Corporate Reserves Manual, which provides standardized procedures used corporatewide for classifying and reporting hydrocarbon reserves.

During the year, the RAC is represented in meetings with each of the company’s upstream business units to review and discuss reserve changes recommended by the various asset teams. Major changes are also reviewed with the company’s Strategy and Planning Committee, whose members include the Chief Executive Officer and the Chief Financial Officer. The company’s annual reserve activity is also reviewed with the Board of Directors. If major changes to reserves were to occur between the annual reviews, those matters would also be discussed with the Board.

RAC subteams also conduct in-depth reviews during the year of many of the fields that have large proved reserves quantities. These reviews include an examination of the proved-reserve records and documentation of their compliance with the Corporate Reserves Manual.
Technologies Used in Establishing Proved Reserves Additions in 2011 In 2011, additions to Chevron's proved reserves were based on a wide range of geologic and engineering technologies. Information generated from wells, such as well logs, wire line sampling, production and pressure testing, fluid analysis, and core analysis, was integrated with seismic, regional geologic studies, and information from analogous reservoirs to provide “reasonably certain” proved reserves estimates. Both proprietary and commercially available analytic tools including reservoir simulation, geologic modeling, and seismic processing have been used in the interpretation of the subsurface data. These technologies have been utilized extensively by the company in the past, and the company believes that they provide a high degree of confidence in establishing reliable and consistent reserves estimates.

Proved Undeveloped Reserve Quantities At the end of 2011, proved undeveloped reserves for consolidated companies totaled 3.7 billion barrels of oil-equivalent (BOE). Approximately 68 percent of these reserves are attributed to natural gas, of which about 60 percent were located in Australia. Crude oil, condensate and natural gas liquids



(NGLs) accounted for about 29 percent of the total, with the largest concentration of these reserves in Africa, Asia and the United States. Synthetic oil accounted for the balance of the proved undeveloped reserves and was located in Canada in the Other Americas region.

Proved undeveloped reserves of equity affiliates amounted to 1.3 billion BOE. At year-end, crude oil, condensate and NGLs represented 61 percent of these reserves, with TCO accounting for the majority of this amount. Natural gas represented 25 percent of the total, with approximately 43 percent of those reserves from TCO. The remaining proved undeveloped reserves are attributed to synthetic oil in Venezuela.

In 2011, a total of 220 million BOE was transferred from proved undeveloped to proved developed for consolidated companies. In the United States, approximately 90 million BOE were transferred, primarily due to ongoing drilling activities in California and other locations. In Asia, 55 million BOE were transferred to proved developed primarily driven by the start-up of a gas project in Thailand. The start-up of several small projects in Africa, Europe and Other Americas accounted for the remainder.

Affiliated companies had transfers of 25 million BOE from proved undeveloped to proved developed.

Investment to Convert Proved Undeveloped to Proved Developed Reserves During 2011, investments totaling approximately $6.7 billion were made by consolidated companies and equity affiliates to advance the development of proved undeveloped reserves. In Australia, $2.1 billion was expended, which was primarily driven by construction activities at the Gorgon LNG project. In Africa, $1.4 billion was expended on various projects, including offshore development projects in Nigeria and Angola. In Nigeria, construction progressed on a deepwater project, and development activities continued at a natural gas processing plant. In Angola, offshore development drilling was progressed along with several gas injection projects. In Asia, expenditures during the year totaled $1.0 billion, which included construction of a gas processing facility in Thailand, a gas development project in China and development activities in Indonesia. In the United States, expenditures totaled $0.9 billion for offshore development projects in the Gulf of Mexico. In Other Americas, development expenditures totaled $0.9 billion for a variety of projects, including an offshore development project in Brazil. In Europe, $0.1 billion was expended on various development projects.

The company’s share of affiliated companies’ expenditures was $0.3 billion, primarily on an LNG project in Angola and development activities in Kazakhstan.

Proved Undeveloped Reserves for Five Years or More Reserves that remain proved undeveloped for five or more years are a result of several factors that affect optimal project development and execution, such as the complex nature of the development project in adverse and remote locations, physical limitations of infrastructure or plant capacities that dictate project timing, compression projects that are pending reservoir pressure declines, and contractual limitations that dictate production levels.

At year-end 2011, the company held approximately 1.8 billion BOE of proved undeveloped reserves that have remained undeveloped for five years or more. The reserves are held by consolidated and affiliated companies, and the majority of these reserves are in locations where the company has a proven track record of developing major projects.

In Africa, approximately 330 million BOE is related to deepwater and natural gas developments in Nigeria and Angola. Major Nigerian deepwater development projects include Agbami, which started production in 2008 and has ongoing development activities to maintain full utilization of infrastructure capacity, and the Usan development, which is expected to start production in 2012. Also in Nigeria, various fields and infrastructure associated with the Escravos Gas Projects are currently under development.

In Asia, approximately 240 million BOE remain classified as proved undeveloped. The majority of the volumes relate to ongoing development activities in the Pattani Field (Thailand) and the Malampaya Field (Philippines) that are scheduled to maintain production within contractual and infrastructure constraints. The balance relates to infrastructure constraints in Azerbaijan.

In Australia, approximately 110 million BOE remain classified as undeveloped due to a compression project at the North West Shelf Venture, which is scheduled for start-up in 2013.

In the United States, approximately 70 million BOE remain proved undeveloped, primarily related to a steamflood expansion and deepwater development projects. In Other Americas and Europe, approximately 50 million BOE is related to contractual constraints, infrastructure limitations and future compression projects.

Affiliated companies have approximately 1.0 billion BOE of proved undeveloped reserves held for five years or more. The TCO affiliate in Kazakhstan accounts for approximately 880 million BOE. Field production is constrained by plant capacity limitations. Further field development to convert the remaining proved undeveloped reserves is scheduled to occur in line with reservoir depletion.

In Venezuela, the affiliate that operates the Hamaca Field’s synthetic heavy oil upgrading operation accounts for about 120 million BOE of these proved undeveloped reserves. Development drilling continues at Hamaca to optimize utilization of upgrader capacity.

Annually, the company assesses whether any changes have occurred in facts or circumstances, such as changes to development plans, regulations or government policies, that would warrant a revision to reserve estimates. For 2011, this assessment did not result in any material changes in reserves classified as proved undeveloped. Over the past three years,



the ratio of proved undeveloped reserves to total proved reserves has ranged between 37 percent and 44 percent. The consistent completion of major capital projects has kept the ratio in a narrow range over this time period.

Proved Reserve Quantities At December 31, 2011, proved reserves for the company’s consolidated operations were 8.5 billion BOE. (Refer to the term “Reserves” on page 8 for the definition of oil-equivalent reserves.) Approximately 23 percent of the total reserves were located in the United States. For the company’s interests in equity affiliates, proved reserves were 2.7 billion BOE, 78 percent of which were associated with the company’s 50 percent ownership in TCO.

Aside from the Tengiz Field in the TCO affiliate, no single property accounted for more than 5 percent of the company’s total oil-equivalent proved reserves. About 22 other individual properties in the company’s portfolio of assets each contained between 1 percent and 5 percent of the company’s oil-equivalent proved reserves, which in the aggregate accounted for 47 percent of the company’s total oil-equivalent proved reserves. These properties were geographically dispersed, located in the United States, Canada, South America, Africa, Asia and Australia.

In the United States, total proved reserves at year-end 2011 were 1.9 billion BOE. California properties accounted for 35 percent of the U.S. reserves, with most classified as heavy oil. Because of heavy oil's high viscosity and the need to employ enhanced recovery methods, most of the company's heavy-oil fields in California employ a continuous steamflooding process. The Gulf of Mexico region contains 24 percent of the U.S. reserves, with liquids representing about 77 percent of reserves in the Gulf. Production operations are mostly offshore and, as a result, are also capital intensive. Other U.S. areas represent the remaining 41 percent of U.S. reserves, with liquids accounting for about 42 percent of the total. For production of crude oil, some fields utilize enhanced recovery methods, including waterflood and  \( CO_{2} \)  injection.

For the three years ending December 31, 2011, the pattern of net reserve changes shown in the following tables are not necessarily indicative of future trends. Apart from acquisitions, the company’s ability to add proved reserves is affected by, among other things, events and circumstances that are outside the company’s control, such as delays in government permitting, partner approvals of development plans, changes in oil and gas prices, OPEC constraints, geopolitical uncertainties, and civil unrest.

The company’s estimated net proved reserves of crude oil, condensate, natural gas liquids and synthetic oil and changes thereto for the years 2009, 2010 and 2011 are shown in the table on the following page. The company’s estimated net proved reserves of natural gas are shown on page 81.



Net Proved Reserves of Crude Oil, Condensate, Natural Gas Liquids and Synthetic Oil

<table><tr><td rowspan="2">Millions of barrels</td><td rowspan="2">U.S.</td><td rowspan="2">Other Americas \( ^{1} \)</td><td rowspan="2">Africa</td><td rowspan="2">Asia</td><td rowspan="2">Australia</td><td colspan="3">Consolidated Companies</td><td colspan="3">Affiliated Companies</td><td rowspan="2">Total Consolidated and Affiliated Companies</td></tr><tr><td>Europe</td><td>Synthetic Oil \( ^{2,3} \)</td><td>Total</td><td>TCO</td><td>Synthetic Oil \( ^{2} \)</td><td>Other \( ^{4} \)</td></tr><tr><td>Reserves at January 1, 2009</td><td>1,470</td><td>149</td><td>1,385</td><td>1,456</td><td>73</td><td>202</td><td>—</td><td>4,735</td><td>2,176</td><td>—</td><td>439</td><td>7,350</td></tr><tr><td>Changes attributable to:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revisions</td><td>63</td><td>(29)</td><td>(46)</td><td>(121)</td><td>18</td><td>10</td><td>460</td><td>355</td><td>(184)</td><td>266</td><td>(269)</td><td>168</td></tr><tr><td>Improved recovery</td><td>2</td><td>—</td><td>48</td><td>—</td><td>—</td><td>—</td><td>—</td><td>50</td><td>36</td><td>—</td><td>—</td><td>86</td></tr><tr><td>Extensions and discoveries</td><td>6</td><td>13</td><td>10</td><td>3</td><td>20</td><td>—</td><td>—</td><td>52</td><td>—</td><td>—</td><td>—</td><td>52</td></tr><tr><td>Purchases</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>−</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Sales</td><td>(3)</td><td>(6)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(9)</td><td>—</td><td>—</td><td>—</td><td>(9)</td></tr><tr><td>Production</td><td>(177)</td><td>(23)</td><td>(151)</td><td>(167)</td><td>(13)</td><td>(42)</td><td>—</td><td>(573)</td><td>(82)</td><td>—</td><td>(19)</td><td>(674)</td></tr><tr><td>Reserves at December 31, 2009 \( ^{5} \)</td><td>1,361</td><td>104</td><td>1,246</td><td>1,171</td><td>98</td><td>170</td><td>460</td><td>4,610</td><td>1,946</td><td>266</td><td>151</td><td>6,973</td></tr><tr><td>Changes attributable to:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revisions</td><td>63</td><td>12</td><td>17</td><td>(26)</td><td>3</td><td>19</td><td>15</td><td>103</td><td>(33)</td><td>—</td><td>12</td><td>82</td></tr><tr><td>Improved recovery</td><td>11</td><td>3</td><td>58</td><td>2</td><td>—</td><td>—</td><td>—</td><td>74</td><td>—</td><td>—</td><td>3</td><td>77</td></tr><tr><td>Extensions and discoveries</td><td>19</td><td>19</td><td>9</td><td>16</td><td>—</td><td>—</td><td>—</td><td>63</td><td>—</td><td>—</td><td>—</td><td>63</td></tr><tr><td>Purchases</td><td>—</td><td>—</td><td>—</td><td>11</td><td>—</td><td>—</td><td>—</td><td>11</td><td>—</td><td>—</td><td>−</td><td>11</td></tr><tr><td>Sales</td><td>(1)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(1)</td><td>—</td><td>—</td><td>—</td><td>(1)</td></tr><tr><td>Production</td><td>(178)</td><td>(30)</td><td>(162)</td><td>(161)</td><td>(13)</td><td>(37)</td><td>(9)</td><td>(590)</td><td>(93)</td><td>(10)</td><td>(9)</td><td>(702)</td></tr><tr><td>Reserves at December 31, 2010 \( ^{5} \)</td><td>1,275</td><td>108</td><td>1,168</td><td>1,013</td><td>88</td><td>152</td><td>466</td><td>4,270</td><td>1,820</td><td>256</td><td>157</td><td>6,503</td></tr><tr><td>Changes attributable to:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revisions</td><td>63</td><td>4</td><td>60</td><td>25</td><td>(2)</td><td>15</td><td>32</td><td>197</td><td>28</td><td>—</td><td>10</td><td>235</td></tr><tr><td>Improved recovery</td><td>6</td><td>4</td><td>48</td><td>—</td><td>—</td><td>—</td><td>—</td><td>58</td><td>—</td><td>—</td><td>—</td><td>58</td></tr><tr><td>Extensions and discoveries</td><td>140</td><td>30</td><td>34</td><td>4</td><td>65</td><td>26</td><td>—</td><td>299</td><td>—</td><td>—</td><td>—</td><td>299</td></tr><tr><td>Purchases</td><td>2</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>40</td><td>42</td><td>—</td><td>—</td><td>—</td><td>42</td></tr><tr><td>Sales</td><td>(5)</td><td>—</td><td>—</td><td>—</td><td>(1)</td><td>—</td><td>—</td><td>(6)</td><td>—</td><td>—</td><td>—</td><td>(6)</td></tr><tr><td>Production</td><td>(170)</td><td>(33)</td><td>(155)</td><td>(148)</td><td>(10)</td><td>(34)</td><td>(15)</td><td>(565)</td><td>(89)</td><td>(12)</td><td>(10)</td><td>(676)</td></tr><tr><td>Reserves at December 31, 2011 \( ^{5} \)</td><td>1,311</td><td>113</td><td>1,155</td><td>894</td><td>140</td><td>159</td><td>523</td><td>4,295</td><td>1,759</td><td>244</td><td>157</td><td>6,455</td></tr></table>

 \( ^{1} \)  Ending reserve balances in North America were 13, 14 and 12 and in South America were 100, 94 and 92 in 2011, 2010 and 2009, respectively.

 \( ^{2} \)  Prospective reporting effective December 31, 2009, in accordance with the SEC rule on Modernization of Oil and Gas Reporting.

 \( ^{3} \)  Reserves associated with Canada.

 \( ^{4} \)  Ending reserve balances in Africa were 38, 36 and 31 and in South America were 119, 121 and 120 in 2011, 2010 and 2009, respectively.

 \( ^{5} \)  Included are year-end reserve quantities related to production-sharing contracts (PSC) (refer to page 8 for the definition of a PSC). PSC-related reserve quantities are

22 percent, 24 percent and 26 percent for consolidated companies for 2011, 2010 and 2009, respectively.

Noteworthy amounts in the categories of liquids proved reserve changes for 2009 through 2011 are discussed below:

Revisions In 2009, net revisions increased reserves by 355 million barrels for worldwide consolidated companies and decreased reserves by 187 million barrels for equity affiliates. For consolidated companies, the largest increase was 460 million barrels in Other Americas due to the inclusion of synthetic oil related to Canadian oil sands. In the United States, reserves increased 63 million barrels as a result of development drilling and performance revisions. The increases were partially offset by decreases of 121 million barrels in Asia and 46 million barrels in Africa. In Asia, decreases in Indonesia and Azerbaijan were driven by the effect of higher 12-month average prices on the calculation of reserves associated with production-sharing contracts and the effect of reservoir performance revisions. In Africa, reserves in Nigeria declined as a result of higher prices on production-sharing contracts as well as reservoir performance.
For affiliated companies, TCO declined by 184 million barrels primarily due to the effect of higher 12-month average prices on royalty determination. For Other affiliated companies, 266 million barrels of heavy crude oil were reclassified to synthetic oil for the activities in Venezuela.

In 2010, net revisions increased reserves 103 million barrels for consolidated companies and decreased reserves 21 million barrels for affiliated companies. For consolidated companies, improved reservoir performance accounted for a majority of the 63 million barrel increase in the United States. Increases in the other regions were partially offset by Asia, which decreased as a result of the effect of higher prices on production-sharing contracts in Kazakhstan. For affiliated companies, the price effect on royalty determination at TCO decreased reserves by 33 million barrels. This was partially offset by improved reservoir performance and development drilling in Venezuela.



In 2011, net revisions increased reserves 197 million barrels for consolidated companies and increased reserves 38 million barrels for affiliated companies. For consolidated companies, improved reservoir performance accounted for a majority of the 63 million barrel increase in the United States. In Africa, improved field performance drove the 60 million barrel increase. In Asia, increases from improved reservoir performance were partially offset by the effects of higher prices on production-sharing contracts. Synthetic oil reserves in Canada increased by 32 million barrels, primarily due to geotechnical revisions. For affiliated companies, improved facility and reservoir performance was partially offset by the price effect on royalty determination at TCO. Continued development drilling increased reserves in Venezuela.

Improved Recovery In 2009, improved recovery increased liquids volumes by 86 million barrels worldwide. Consolidated companies accounted for 50 million barrels. The largest addition was related to improved secondary recovery in Nigeria. Affiliated companies increased reserves 36 million barrels due to improvements related to the TCO Sour Gas Injection/Second Generation Plant (SGI/SGP) facilities.

In 2010, improved recovery increased volumes by 77 million barrels worldwide. For consolidated companies, reserves in Africa increased 58 million barrels due primarily to secondary recovery performance in Nigeria. Reserves in the United States increased 11 million, primarily in California. Affiliated companies increased reserves 3 million barrels.

In 2011, improved recovery increased volumes by 58 million barrels worldwide. For consolidated companies, reserves in Africa increased 48 million barrels due primarily to secondary recovery performance in Nigeria. Reserves in the United States increased by 6 million, primarily in California. Other Americas increased 4 million barrels.
Extensions and Discoveries In 2009, extensions and discoveries increased liquids volumes by 52 million barrels worldwide. The largest additions were 20 million barrels in Australia related to the Gorgon Project and 13 million barrels in Other Americas related to delineation drilling in Argentina. Africa and the United States accounted for 10 million barrels and 6 million barrels, respectively.

In 2010, extensions and discoveries increased consolidated companies reserves 63 million barrels worldwide. The United States and Other Americas each increased reserves 19 million barrels, and Asia increased reserves 16 million barrels. No single area in the United States was individually significant. Drilling activity in Argentina and Brazil accounted for the majority of the increase in Other Americas. In Asia, the increase was primarily related to activity in Azerbaijan.

In 2011, extensions and discoveries increased consolidated companies reserves 299 million barrels worldwide. In the United States, additions related to two Gulf of Mexico projects resulted in the majority of the 140 million barrel increase. In Australia, the Wheatstone Project increased liquid volumes 65 million barrels. Africa and Other Americas increased reserves 34 million and 30 million barrels, respectively, following the start of new projects in these areas. In Europe, a new project in the United Kingdom increased reserves 26 million barrels. In Asia, reserves increased 4 million barrels.

Purchases In 2011, purchases increased worldwide liquid volumes 42 million barrels. The acquisition of additional acreage in Canada increased synthetic oil reserves 40 million barrels.



Net Proved Reserves of Natural Gas

<table><tr><td rowspan="2">Billions of cubic feet (BCF)</td><td rowspan="2">U.S.</td><td rowspan="2">Other Americas \( ^{1} \)</td><td rowspan="2">Africa</td><td colspan="5">Consolidated Companies</td><td colspan="2">Affiliated Companies</td><td rowspan="2">Total Consolidated and Affiliated Companies</td></tr><tr><td>Asia</td><td>Australia</td><td>Europe</td><td>Total</td><td>TCO</td><td>Other \( ^{2} \)</td><td></td></tr><tr><td>Reserves at January 1, 2009</td><td>3,150</td><td>2,368</td><td>3,056</td><td>7,996</td><td>1,962</td><td>490</td><td>19,022</td><td>3,175</td><td>878</td><td>23,075</td><td></td></tr><tr><td>Changes attributable to:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revisions</td><td>39</td><td>(126)</td><td>4</td><td>493</td><td>166</td><td>(7)</td><td>569</td><td>(237)</td><td>193</td><td>525</td><td></td></tr><tr><td>Improved recovery</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td><td>&lt;ecel&gt;</td><td></td><td></td><td></td></tr></table>

 \( ^{1} \)  Ending reserve balances in North America and South America were 19, 21, 23 and 1,645, 1,794, 1,962 in 2011, 2010 and 2009, respectively.

 \( ^{2} \)  Ending reserve balances in Africa and South America were 1,016, 953, 898 and 187, 157, 165 in 2011, 2010 and 2009, respectively.

 \( ^{3} \)  Total “as sold” volumes are 4.4 BCF, 4.5 BCF and 4.5 BCF for 2011, 2010 and 2009, respectively.

 \( ^{4} \)  Includes reserve quantities related to production-sharing contracts (PSC) (refer to page 8 for the definition of a PSC). PSC-related reserve quantities are 21 percent,

29 percent and 31 percent for consolidated companies for 2011, 2010 and 2009, respectively.

Noteworthy amounts in the categories of natural gas proved-reserve changes for 2009 through 2011 are discussed below:

Revisions In 2009, net revisions increased reserves 569 BCF for consolidated companies and decreased reserves 44 BCF for affiliated companies. For consolidated companies, net increases were 493 BCF in Asia, primarily as a result of reservoir studies in Bangladesh and development drilling in Thailand. These results were partially offset by a downward revision due to the impact of higher prices on production-sharing contracts in Myanmar. In Australia, the 166 BCF increase in reserves resulted from improved reservoir performance and compression. In Other Americas, reserves decreased 126 BCF, driven primarily by the effect of higher prices on production-sharing contracts in Trinidad and Tobago. In the United States, a net increase of 39 BCF was the result of development drilling in the Gulf of Mexico, partially offset by performance revisions in the California and mid-continent areas.
For equity affiliates, a downward revision of 237 BCF at TCO was due to the effect of higher prices on royalty determination and an increase in gas injection for SGI/SGP facilities. This decline was partially offset by performance and drilling opportunities related to the Angola LNG project.

In 2010, net revisions increased reserves by 197 BCF for consolidated companies, which was more than offset by a 268 BCF decrease in net revisions for affiliated companies. For consolidated companies, a net increase in the United States of 220 BCF, primarily in the mid-continent area and the Gulf of Mexico, was the result of a number of small upward revisions related to improved reservoir performance and drilling activity, none of which were individually significant. The increase was partially offset by downward revisions due to the impact of higher prices on production-sharing contracts in Asia. For equity affiliates, a downward revision of 324 BCF at TCO was due to the price effect on royalty determination and a change in the variable-royalty calculation. This decline was partially offset by the recognition of additional reserves related to the Angola LNG project.



In 2011, net revisions increased reserves 415 BCF for consolidated companies and increased reserves 82 BCF for affiliated companies. For consolidated companies, improved reservoir performance accounted for a majority of the 217 BCF increase in the United States. In Asia, a net increase of 196 BCF was driven by development drilling and improved field performance in Thailand, partially offset by the effects of higher prices on production-sharing contracts in Kazakhstan. In Other Americas, a negative performance revision in Trinidad and Tobago was partially offset by increases in Colombia from drilling activities and the reactivation of an existing field. For affiliated companies, ongoing reservoir assessment resulted in the recognition of additional reserves related to the Angola LNG project. At TCO, improved facility and reservoir performance was more than offset by the price effect on royalty determination.

Extensions and Discoveries In 2009, worldwide extensions and discoveries of 4,387 BCF were attributed to consolidated companies. In Australia, the Gorgon Project accounted for all of the 4,276 BCF additions. In Asia, development drilling in Thailand accounted for the majority of the increase. In the United States, delineation drilling in California accounted for the majority of the increase.
In 2011, extensions and discoveries increased consolidated companies' reserves 4,680 BCF worldwide. In Australia, the Wheatstone Project accounted for the 4,035 BCF in additions. In Africa, the start of a new natural gas development project in Nigeria resulted in the 290 BCF increase. In the United States, development drilling accounted for the majority of the 287 BCF increase.

Purchases In 2011, purchases increased worldwide reserves 1,233 BCF. In the United States, acquisitions in the Marcellus Shale increased reserves 1,230 BCF.

Sales In 2009, worldwide sales of 117 BCF were related to consolidated companies. For Other Americas, the sale of properties in Argentina accounted for 84 BCF. The sale of properties in the Gulf of Mexico accounted for the majority of the 33 BCF decrease in the United States.

In 2011, sales decreased consolidated companies' reserves 174 BCF worldwide. In Australia, the Wheatstone Project unitization and equity sales agreements reduced reserves 77 BCF. In the United States, sales in Alaska and other smaller fields reduced reserves 95 BCF.



The standardized measure of discounted future net cash flows, related to the preceding proved oil and gas reserves, is calculated in accordance with the requirements of the FASB. Estimated future cash inflows from production are computed by applying 12-month average prices for oil and gas to year-end quantities of estimated net proved reserves. Future price changes are limited to those provided by contractual arrangements in existence at the end of each reporting year. Future development and production costs are those estimated future expenditures necessary to develop and produce year-end estimated proved reserves based on year-end cost indices, assuming continuation of year-end economic conditions, and include estimated costs for asset retirement obligations. Estimated future income taxes are calculated by applying appropriate year-end statutory tax rates. These rates reflect allowable deductions and tax credits and are applied to estimated future pretax net cash flows, less the tax basis of related assets. Discounted future net cash flows are calculated

using 10 percent midperiod discount factors. Discounting requires a year-by-year estimate of when future expenditures will be incurred and when reserves will be produced.

The information provided does not represent management’s estimate of the company’s expected future cash flows or value of proved oil and gas reserves. Estimates of proved-reserve quantities are imprecise and change over time as new information becomes available. Moreover, probable and possible reserves, which may become proved in the future, are excluded from the calculations. The valuation prescribed by the FASB requires assumptions as to the timing and amount of future development and production costs. The calculations are made as of December 31 each year and should not be relied upon as an indication of the company’s future cash flows or value of its oil and gas reserves. In the following table, “Standardized Measure Net Cash Flows” refers to the standardized measure of discounted future net cash flows.

<table><tr><td rowspan="2">Millions of dollars</td><td rowspan="2">U.S.</td><td rowspan="2">Other Americas</td><td rowspan="2">Africa</td><td rowspan="2">Asia</td><td rowspan="2">Australia</td><td colspan="2">Consolidated Companies</td><td colspan="2">Affiliated Companies</td><td rowspan="2">Total Consolidated and Affiliated Companies</td></tr><tr><td>Europe</td><td>Total</td><td>TCO</td><td>Other</td></tr><tr><td>At December 31, 2011</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Future cash inflows from production \( ^{1} \)</td><td>$ 143,633</td><td>$ 63,579</td><td>$124,077</td><td>$113,773</td><td>$ 19,704</td><td>$ 589,738</td><td>$171,588</td><td>$ 42,212</td><td>$ 803,538</td><td></td></tr><tr><td>Future production costs</td><td>(39,523)</td><td>(22,856)</td><td>(22,703)</td><td>(35,579)</td><td>(15,411)</td><td>(7,467)</td><td>(143,539)</td><td>(7,976)</td><td>(19,430)</td><td>(170,945)</td></tr><tr><td>Future development costs</td><td>(11,272)</td><td>(9,345)</td><td>(10,695)</td><td>(15,035)</td><td>(29,489)</td><td>(676)</td><td>(76,512)</td><td>(10,778)</td><td>(2,836)</td><td>(90,126)</td></tr><tr><td>Future income taxes</td><td>(34,050)</td><td>(9,121)</td><td>(53,103)</td><td>(33,884)</td><td>(20,661)</td><td>(7,229)</td><td>(158,048)</td><td>(43,176)</td><td>(10,833)</td><td>(212,057)</td></tr><tr><td>Undiscounted future net cash flows</td><td>58,788</td><td>22,257</td><td>37,576</td><td>40,474</td><td>48,212</td><td>4,332</td><td>211,639</td><td>109,658</td><td>9,113</td><td>330,410</td></tr><tr><td>10 percent midyear annual discount for timing of estimated cash flows</td><td>(25,013)</td><td>(15,082)</td><td>(13,801)</td><td>(14,627)</td><td>(35,051)</td><td>(1,117)</td><td>(104,691)</td><td>(61,675)</td><td>(4,883)</td><td>(171,249)</td></tr><tr><td>Standardized Measure</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net Cash Flows</td><td>$ 33,775</td><td>$ 7,175</td><td>$ 23,775</td><td>$ 25,847</td><td>$ 13,161</td><td>$ 3,215</td><td>$ 106,948</td><td>$ 47,983</td><td>$ 4,230</td><td>$ 159,161</td></tr><tr><td>At December 31, 2010</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Future cash inflows from production \( ^{1} \)</td><td>$ 101,281</td><td>$ 48,068</td><td>$ 90,402</td><td>$ 101,553</td><td>$ 52,635</td><td>$ 13,618</td><td>$ 407,557</td><td>$ 124,970</td><td>$ 31,188</td><td>$ 563,715</td></tr><tr><td>Future production costs</td><td>(36,609)</td><td>(22,118)</td><td>(19,591)</td><td>(30,793)</td><td>(9,191)</td><td>(5,842)</td><td>(124,144)</td><td>(7,298)</td><td>(4,172)</td><td>(135,614)</td></tr><tr><td>Future development costs</td><td>(6,661)</td><td>(6,953)</td><td>(12,239)</td><td>(11,690)</td><td>(13,160)</td><td>(708)</td><td>(51,411)</td><td>(8,777)</td><td>(2,254)</td><td>(62,442)</td></tr><tr><td>Future income taxes</td><td>(20,307)</td><td>(7,337)</td><td>(34,405)</td><td>(26,355)</td><td>(9,085)</td><td>(4,031)</td><td>(101,520)</td><td>(30,763)</td><td>(12,919)</td><td>(145,202)</td></tr><tr><td>Undiscounted future net cash flows</td><td>37,704</td><td>11,660</td><td>24,167</td><td>32,715</td><td>21,199</td><td>3,037</td><td>130,482</td><td>78,132</td><td>11,843</td><td>220,457</td></tr><tr><td>10 percent midyear annual discount for timing of estimated cash flows</td><td>(13,218)</td><td>(6,751)</td><td>(9,221)</td><td>(12,287)</td><td>(15,282)</td><td>(699)</td><td>(57,458)</td><td>(43,973)</td><td>(6,574)</td><td>(108,005)</td></tr><tr><td>Standardized Measure</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net Cash Flows</td><td>$ 24,486</td><td>$ 4,909</td><td>$ 14,946</td><td>$ 20,428</td><td>$ 5,917</td><td>$ 2,338</td><td>$ 73,024</td><td>$ 34,159</td><td>$ 5,269</td><td>$ 112,452</td></tr><tr><td>At December 31, 2009</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Future cash inflows from production \( ^{2} \)</td><td>$ 81,332</td><td>$ 39,251</td><td>$ 75,338</td><td>$ 91,993</td><td>$ 49,875</td><td>$ 11,988</td><td>$ 349,777</td><td>$ 97,793</td><td>$ 23,825</td><td>$ 471,395</td></tr><tr><td>Future production costs</td><td>(35,295)</td><td>(27,716)</td><td>(22,459)</td><td>(31,843)</td><td>(8,648)</td><td>(5,842)</td><td>(131,803)</td><td>(6,923)</td><td>(4,765)</td><td>(143,491)</td></tr><tr><td>Future development costs</td><td>(7,027)</td><td>(3,711)</td><td>(14,715)</td><td>(12,884)</td><td>(12,371)</td><td>(561)</td><td>(51,269)</td><td>(8,190)</td><td>(3,986)</td><td>(63,445)</td></tr><tr><td>Future income taxes</td><td>(13,662)</td><td>(3,674)</td><td>(22,503)</td><td>(18,905)</td><td>(10,484)</td><td>(3,269)</td><td>(72,497)</td><td>(23,357)</td><td>(7,774)</td><td>(103,628)</td></tr><tr><td>Undiscounted future net cash flows</td><td>25,348</td><td>4,150</td><td>15,661</td><td>28,361</td><td>18,372</td><td>2,316</td><td>94,208</td><td>59,323</td><td>7,300</td><td>160,831</td></tr><tr><td>10 percent midyear annual discount for timing of estimated cash flows</td><td>(8,822)</td><td>(2,275)</td><td>(5,882)</td><td>(11,722)</td><td>(14,764)</td><td>(467)</td><td>(43,932)</td><td>(34,937)</td><td>(4,450)</td><td>(83,319)</td></tr><tr><td>Standardized Measure</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net Cash Flows</td><td>$ 16,526</td><td>$ 1,875</td><td>$ 9,779</td><td>$ 16,639</td><td>$ 3,608</td><td>$ 1,849</td><td>$ 50,276</td><td>$ 24,386</td><td>$ 2,850</td><td>$ 77,512</td></tr></table>

 \( ^{1} \)  Based on 12-month average price.

 \( ^{2} \)  Based on year-end prices.



The changes in present values between years, which can be significant, reflect changes in estimated proved-reserve quantities and prices and assumptions used in forecasting production volumes and costs. Changes in the timing of production are included with “Revisions of previous quantity estimates.”

<table><tr><td>Millions of dollars</td><td>Consolidated Companies</td><td>Affiliated Companies</td><td>Total Consolidated and Affiliated Companies</td></tr><tr><td>Present Value at January 1, 2009</td><td>$ 25,661</td><td>$ 9,741</td><td>$ 35,402</td></tr><tr><td>Sales and transfers of oil and gas produced net of production costs</td><td>(27,559)</td><td>(4,209)</td><td>(31,768)</td></tr><tr><td>Development costs incurred</td><td>10,791</td><td>335</td><td>11,126</td></tr><tr><td>Purchases of reserves</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Sales of reserves</td><td>(285)</td><td>-</td><td>(285)</td></tr><tr><td>Extensions, discoveries and improved recovery less related costs</td><td>3,438</td><td>697</td><td>4,135</td></tr><tr><td>Revisions of previous quantity estimates</td><td>3,230</td><td>(4,343)</td><td>(1,113)</td></tr><tr><td>Net changes in prices, development and production costs</td><td>51,528</td><td>30,915</td><td>82,443</td></tr><tr><td>Accretion of discount</td><td>4,282</td><td>1,412</td><td>5,694</td></tr><tr><td>Net change in income tax</td><td>(20,810)</td><td>(7,312)</td><td>(28,122)</td></tr><tr><td>Net change for 2009</td><td>24,615</td><td>17,495</td><td>42,110</td></tr><tr><td>Present Value at December 31, 2009</td><td>$ 50,276</td><td>$ 27,236</td><td>$ 77,512</td></tr><tr><td>Sales and transfers of oil and gas produced net of production costs</td><td>(39,499)</td><td>(6,377)</td><td>(45,876)</td></tr><tr><td>Development costs incurred</td><td>12,042</td><td>572</td><td>12,614</td></tr><tr><td>Purchases of reserves</td><td>513</td><td>-</td><td>513</td></tr><tr><td>Sales of reserves</td><td>(47)</td><td>-</td><td>(47)</td></tr><tr><td>Extensions, discoveries and improved recovery less related costs</td><td>5,194</td><td>63</td><td>5,257</td></tr><tr><td>Revisions of previous quantity estimates</td><td>10,156</td><td>974</td><td>11,130</td></tr><tr><td>Net changes in prices, development and production costs</td><td>43,887</td><td>19,878</td><td>63,765</td></tr><tr><td>Accretion of discount</td><td>8,391</td><td>3,797</td><td>12,188</td></tr><tr><td>Net change in income tax</td><td>(17,889)</td><td>(6,715)</td><td>(24,604)</td></tr><tr><td>Net change for 2010</td><td>22,748</td><td>12,192</td><td>34,940</td></tr><tr><td>Present Value at December 31, 2010</td><td>$ 73,024</td><td>$ 39,428</td><td>$ 112,452</td></tr><tr><td>Sales and transfers of oil and gas produced net of production costs</td><td>(53,063)</td><td>(8,679)</td><td>(61,742)</td></tr><tr><td>Development costs incurred</td><td>13,869</td><td>729</td><td>14,598</td></tr><tr><td>Purchases of reserves</td><td>1,212</td><td>-</td><td>1,212</td></tr><tr><td>Sales of reserves</td><td>(803)</td><td>-</td><td>(803)</td></tr><tr><td>Extensions, discoveries and improved recovery less related costs</td><td>12,288</td><td>-</td><td>12,288</td></tr><tr><td>Revisions of previous quantity estimates</td><td>16,750</td><td>791</td><td>17,541</td></tr><tr><td>Net changes in prices, development and production costs</td><td>61,428</td><td>19,097</td><td>80,525</td></tr><tr><td>Accretion of discount</td><td>11,943</td><td>5,563</td><td>17,506</td></tr><tr><td>Net change in income tax</td><td>(29,700)</td><td>(4,716)</td><td>(34,416)</td></tr><tr><td>Net change for 2011</td><td>33,924</td><td>12,785</td><td>46,709</td></tr><tr><td>Present Value at December 31, 2011</td><td>$ 106,948</td><td>$ 52,213</td><td>$ 159,161</td></tr></table>



## Chevron History

## 1879

Incorporated in San Francisco,
California, as the Pacific Coast
Oil Company.

## 1900

Acquired by the West Coast operations of John D. Rockefeller’s original Standard Oil Company.

## 1911

Emerged as an autonomous entity – Standard Oil Company (California) – following U.S. Supreme Court decision to divide the Standard Oil conglomerate into 34 independent companies.

## 1926

Acquired Pacific Oil Company to become Standard Oil Company of California (Socal).

## 1936

Formed the Caltex Group of Companies, jointly owned by Social and The Texas Company (later became Texaco), to combine Social’s exploration and production interests in the Middle East and Indonesia and provide an outlet for crude oil through The Texas Company’s marketing network in Africa and Asia.

## 1947

Acquired Signal Oil Company,
obtaining the Signal brand name
and adding 2,000 retail stations
in the western United States.

## 1961

Acquired Standard Oil Company (Kentucky), a major petroleum products marketer in five south-eastern states, to provide outlets for crude oil from southern Louisiana and the U.S. Gulf of Mexico, where the company was a major producer.

## 1984

Acquired Gulf Corporation – nearly doubling the company’s crude oil and natural gas activities – and gained significant presence in industrial chemicals, natural gas liquids and coal. Changed name to Chevron Corporation to identify with the name under which most products were marketed.

## 1988

Purchased Tenneco Inc.'s U.S. Gulf of Mexico crude oil and natural gas properties, becoming one of the largest U.S. natural gas producers.

## 1993

Formed Tengizchevroil, a joint venture with the Republic of Kazakhstan, to develop and produce the giant Tengiz Field, becoming the first major Western oil company to enter newly independent Kazakhstan.

## 1999

Acquired Rutherford-Moran Oil Corporation. This acquisition provided inroads to Asian natural gas markets.

## 2001

Merged with Texaco Inc. and changed name to ChevronTexaco Corporation. Became the second-largest U.S.-based energy company.

## 2002

Relocated corporate headquarters from San Francisco, California, to San Ramon, California.

## 2005

Acquired Unocal Corporation, an independent crude oil and natural gas exploration and production company. Unocal’s upstream assets bolstered Chevron’s already-strong position in the Asia-Pacific, U.S. Gulf of Mexico and Caspian regions. Changed name to Chevron Corporation to convey a clearer, stronger and more unified presence in the global marketplace.

## 2011

Acquired Atlas Energy, Inc., an independent U.S. developer and producer of shale gas resources. The acquired assets provide a targeted, high-quality core acreage position primarily in the Marcellus Shale.






## Board of Directors



## John S. Watson, 55

Chairman of the Board and Chief Executive Officer since 2010. Previously he was elected a Director and Vice Chairman in 2009; Executive Vice President, Strategy and Development; Corporate Vice President and President, Chevron International Exploration and Production Company; Vice President and Chief Financial Officer; and Corporate Vice President, Strategic Planning. He is Chairman of the Board of Directors and the Executive Committee of the American Petroleum Institute. Joined Chevron in 1980.

## George L. Kirkland, 61

Vice Chairman of the Board since 2010 and Executive Vice President of Upstream and Gas since 2005. In addition to Board responsibilities, he is responsible for global exploration, production and gas activities. Previously Corporate Vice President and President, Chevron Overseas Petroleum Inc., and President, Chevron U.S.A. Production Company. Joined Chevron in 1974.

## Linnet F. Deily, 66

Director since 2006. She served as a Deputy U.S. Trade Representative and U.S. Ambassador to the World Trade Organization from 2001 to June 2005. Previously she was Vice Chairman of Charles Schwab Corporation. She is a Director of Honeywell International Inc. (2, 4)

## Robert E. Denham, 66

Lead Director since 2011 and a Director since 2004. He is a Partner in the law firm of Munger, Tolles & Olson LLP. Previously he was Chairman and Chief Executive Officer of Salomon Inc. He is a Director of The New York Times Company; Oaktree Capital Group, LLC; QLL Limited; and Fomento Económico Mexicano, S.A. de C.V. (3, 4)

## Chuck Hagel, 65

Director since 2010. He is Distinguished Professor at Georgetown University and the University of Nebraska at Omaha. He served as a U.S. Senator from Nebraska from 1997 to 2009 and participated in numerous committees, including Foreign Relations; Banking, Housing and Urban Affairs; Intelligence; and Energy and Natural Resources. (2, 3)



## Enrique Hernandez Jr., 56

Director since 2008. He is Chairman, Chief Executive Officer and President of Inter-Con Security Systems, Inc., a global security services provider. He is a Director of McDonald's Corporation; Nordstrom, Inc.; and Wells Fargo & Company. (1)

## Kevin W. Sharer, 64

Director since 2007. He is Chairman of the Board and Chief Executive Officer of Amgen Inc., a global biotechnology medicines company. Previously he was President and Chief Operating Officer of Amgen and President of the Business Markets Division of MCI Communications Corporation. He is a Director of Northrop Grumman Corporation. (3, 4)

## John G. Stumpf, 58

Director since 2010. He is Chairman of the Board, Chief Executive Officer and President of Wells Fargo & Company, a diversified financial services company. Previously he served as Group Executive Vice President of Community Banking at Wells Fargo. He is a Director of Target Corporation. (1)

## Ronald D. Sugar, 63

Director since 2005. He is retired Chairman of the Board and Chief Executive Officer of Northrop Grumman Corporation, a global defense and technology company. Previously he was President and Chief Operating Officer of Northrop Grumman. He is a Director of Amgen Inc., Air Lease Corporation and Apple Inc. (1)

## Carl Ware, 68

Director since 2001. He is retired Executive Vice President of The Coca-Cola Company, a manufacturer of beverages. Previously he was a Senior Adviser to the Chief Executive Officer of The Coca-Cola Company and Executive Vice President of Global Public Affairs and Administration for The Coca-Cola Company. He is a Director of Cummins Inc. (3, 4)

## Committees of the Board

1) Audit; Ronald D. Sugar, Chair

2) Public Policy: Linnet F. Deily, Chair

3) Board Nominating and Governance: Robert E. Denham, Chair

4) Management Compensation: Carl Ware, Chair

## Retiring Directors

Three Directors have reached the mandatory retirement age and will not stand for re-election at the Annual Meeting in May: (left to right) Robert J. Eaton, a Director since 2000; Donald B. Rice, a Director since 2005; and Charles R. Shoemate, a Director since 1998. Eaton is retired Chairman of the Board of Management of DaimlerChrysler AG, (2, 4); Rice is retired President and Chief Executive Officer of Agensys, Inc., (3, 4); and Shoemate is retired Chairman of the Board, President and Chief Executive Officer of Bestfoods, (1).










## Corporate Officers



## Lydia I. Beebe, 59

Corporate Secretary and Chief Governance Officer since 1995. Responsible for managing the Corporate Governance Department, counseling the Board of Directors and senior management on corporate governance, and overseeing stockholder services for Chevron and its subsidiaries. Previously Senior Manager, Chevron Tax Department. Joined Chevron in 1977.

## Paul V. Bennett, 58

Vice President and Treasurer since 2011. Previously Vice President, Finance, Downstream and Chemicals, and Assistant Treasurer, Credit and Receivables Management. Serves on the Board of Directors of GS Caltex. Joined the company in 1980.

## James R. Blackwell, 53

Executive Vice President, Technology and Services, since 2011. Responsible also for major capital project management, procurement, and other corporate operating and support functions. Previously President, Chevron Asia Pacific Exploration and Production Company; Managing Director, Chevron Southern Africa Strategic Business Unit; and President, Chevron Pipe Line Company. Joined the company in 1980.

## Matthew J. Foehr, 54

Vice President and Comptroller since 2010. Responsible for corporatewide accounting, financial reporting and analysis, internal controls, and Finance Shared Services. Previously Vice President, Finance, Global Upstream and Gas, and Vice President, Finance, Global Downstream. Joined Chevron in 1982.

## Joseph C. Geagea, 52

Corporate Vice President and President Chevron Gas and Midstream since January 2012. Responsible for the company’s natural gas business and oversight of shipping, pipeline, power operations and natural gas trading operations. Previously Managing Director, Chevron Asia South Ltd., Chevron Asia Pacific Exploration and Production Company, and Vice President, Upstream Capability, Chevron International Exploration and Production Company. Joined the company in 1982.

## Stephen W. Green, 54

Vice President, Policy, Government and Public Affairs, since 2011. Oversees U.S. and international government relations, all aspects of communications, and the company's worldwide efforts to protect and enhance its reputation. Previously President, Chevron Indonesia Company and Managing Director, IndoAsia Business Unit, Chevron Asia Pacific Exploration and Production Company, and Managing Director, Asia South Business Unit, Chevron International Exploration and Production Company. Joined the company in 1998.

## Joe W. Laymon, 59

Vice President, Human Resources, Medical and Security, since 2008. Responsible for the company’s global human resources, medical services and security functions. Previously Group Vice President, Corporate Human Resources and Labor Affairs, Ford Motor Company. Joined the company in 2008.

## Wesley E. Lohec, 52

Vice President, Health, Environment and Safety (HES), since 2011. Responsible for corporate HES strategy and management systems and Chevron Environmental Management Company. Previously Managing Director, Latin America, Chevron Africa and Latin America Exploration and Production Company. Joined the company in 1981.



## Charles N. Macfarlane, 57

General Tax Counsel since 2010. He is responsible for directing Chevron’s worldwide tax activities. Previously the company’s Assistant General Tax Counsel. Joined Chevron in 1986.

## John W. McDonald, 60

Vice President and Chief Technology Officer since 2008. Responsible for Chevron’s three technology companies: Energy Technology, Information Technology and Technology Ventures. Previously Corporate Vice President, Strategic Planning; President and Managing Director, Chevron Upstream Europe, Chevron Overseas Petroleum Inc.; and Vice President, Gulf of Mexico Offshore Division, Texaco Exploration and Production. Joined the company in 1975.

## R. Hewitt Pate, 49

Vice President and General Counsel since 2009. Responsible for directing the company’s worldwide legal affairs. Previously Chair, Competition Practice, Hunton & Williams LLP, Washington, D.C., and Assistant Attorney General, Antitrust Division, U.S. Department of Justice. Joined Chevron in 2009.

## Jay R. Pryor, 54

Vice President, Business Development, since 2006. Responsible for identifying and developing new, large-scale upstream and downstream business opportunities, including mergers and acquisitions. Previously Managing Director, Nigeria/Mid-Africa Strategic Business Unit and Chevron Nigeria Ltd., and Managing Director, Asia South Business Unit and Chevron Offshore (Thailand) Ltd. Joined Chevron in 1979.

## Charles A. Taylor, 54

Vice President, Strategic Planning, since 2011. Responsible for advising senior corporate executives in setting strategic direction for the company, allocating capital and other resources, and determining operating unit performance measures and targets. Previously Corporate Vice President, Health, Environment and Safety. Joined the company in 1980.

## Michael K. Wirth, 51

Executive Vice President, Downstream and Chemicals, since 2006. Responsible for worldwide manufacturing, marketing, lubricants, supply and trading businesses, chemicals and Onrite additives. Previously President, Global Supply and Trading; President, Marketing, Asia/ Middle East/Africa Strategic Business Unit; and President, Marketing, Caltex Corporation. Joined Chevron in 1982.

## Patricia E. Yarrington, 56

Vice President and Chief Financial Officer since 2009. Deputy Chair of the San Francisco Federal Reserve’s Board of Directors. Previously a Director, Chevron Phillips Chemical Company LLC; Corporate Vice President and Treasurer; Corporate Vice President, Policy, Government and Public Affairs; Corporate Vice President, Strategic Planning; President, Chevron Canada Limited; and Comptroller, Chevron Products Company. Joined Chevron in 1980.

## Rhonda I. Zygocki, 54

Executive Vice President, Policy and Planning, since 2011. Responsible for Strategic Planning; Health, Environment and Safety; and oversight of Policy, Government and Public Affairs. Previously Corporate Vice President, Policy, Government and Public Affairs; Corporate Vice President, Health, Environment and Safety; and Managing Director, Chevron Australia Pty Ltd. Joined Chevron in 1980.

## Executive Committee

John S. Watson, George L. Kirkland, James R. Blackwell, R. Hewitt Pate, Michael K. Wirth, Patricia E. Yarrington and Rhonda I. Zygocki. Lydia I. Beebe, Secretary.



## Stockholder and Investor Information

## Stock Exchange Listing

Chevron common stock is listed on the New York Stock Exchange. The symbol is “CVX.”

## Stockholder Information

Questions about stock ownership, changes of address, dividend payments or direct deposit of dividends should be directed to Chevron’s transfer agent and registrar:

Computershare Shareowner

Services LLC

P.O. Box 358015

Pittsburgh, PA 15252-8015

800 368 8357

www-us.computershare.com/investor

The Computershare Shareowner Services Program features dividend reinvestment, optional cash investments of $50 to $100,000 a year and automatic stock purchase.

## Dividend Payment Dates

Quarterly dividends on common stock are paid, following declaration by the Board of Directors, on or about the 10th day of March, June, September and December. Direct deposit of dividends is available to stockholders. For information, contact Computershare Shareowner Services. (See Stockholder Information.)

## Annual Meeting

The Annual Meeting of stockholders will be held at 8:00 a.m., Wednesday, May 30, 2012, at: Chevron Corporation 6001 Bollinger Canyon Road San Ramon, CA 94583-2324

## Electronic Access

In an effort to conserve natural resources and reduce the cost of printing and shipping proxy materials next year, we encourage stockholders to register to receive these documents via email and vote their shares on the Internet. Stockholders of record may sign up on our website, www.icsdelivery.com/cvx/index.html, for electronic access. Enrollment is revocable until each year’s Annual Meeting record date. Beneficial stockholders may be able to request electronic access by contacting their broker or bank, or Broadridge Financial Solutions at: www.icsdelivery.com/cvx/index.html.

## Investor Information

Securities analysts, portfolio managers and representatives of financial institutions may contact:
Investor Relations
Chevron Corporation
6001 Bollinger Canyon Road
San Ramon, CA 94583-2324
925 842 5690
Email: invest@chevron.com

## Notice

As used in this report, the term “Chevron” and such terms as “the company,” “the corporation,” “our,” “we” and “us” may refer to one or more of its consolidated subsidiaries or to all of them taken as a whole. 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.

## Corporate Headquarters

6001 Bollinger Canyon Road
San Ramon, CA 94583-2324
925 842 1000




2011 Annual Report



2011 Supplement to the Annual Report



2011 Corporate Responsibility Report

## Publications and
Other News Sources

The Annual Report, distributed in April, summarizes the company’s financial performance in the preceding year and provides an overview of the company’s major activities.

Chevron’s Annual Report on Form 10-K filed with the U.S. Securities and Exchange Commission and the Supplement to the Annual Report, containing additional financial and operating data, are available on the company’s website, Chevron.com, or copies may be requested by writing to:

Comptroller’s Department
Chevron Corporation
6001 Bollinger Canyon Road, A3201
San Ramon, CA 94583-2324
The Corporate Responsibility Report is available in May on the company’s website, Chevron.com, or a copy may be requested by writing to:
Policy, Government and Public Affairs
Chevron Corporation
6101 Bollinger Canyon Road
BR1X3170
San Ramon, CA 94583-5177

Details of the company’s political contributions for 2011 are available on the company’s website, Chevron.com, or by writing to: Policy, Government and Public Affairs Chevron Corporation 6101 Bollinger Canyon Road BR1X3400 San Ramon, CA 94583-5177
Information about charitable contributions is available in the second half of the year on Chevron’s website, Chevron.com.

For additional information about the company and the energy industry, visit Chevron’s website, Chevron.com. It includes articles, news releases, speeches, quarterly earnings information, the Proxy Statement and the complete text of this Annual Report.

This Annual Report contains forward-looking statements – identified by words such as “expects,” “intends,” “projects,” etc. – that reflect management’s current estimates and beliefs, but are not guarantees of future results. Please see “Cautionary Statement Relevant to Forward-Looking Information for the Purpose of ‘Safe Harbor’ Provisions of the Private Securities Litigation Reform Act of 1995” on Page 9 for a discussion of some of the factors that could cause actual results to differ materially.

PHOTOGRAPHY

Cover: Jeremy Ashton; Inside Front Cover: Dan Grantham; Page 2: Eric Myer; Page 6: Marc Marriott.
PRODUCED BY Policy, Government and Public Affairs and Comptroller’s Departments, Chevron Corporation
DESIGN Design One – San Francisco, California
PRINTING ColorGraphics – Los Angeles, California
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