UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2015

OR    

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

SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 001-00368

(Exact name of registrant as specified in its charter)

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

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

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ☑           No  o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   ☑

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

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

Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant's most recently completed second fiscal quarter - $181,530,939,081 (As of June 30, 2015 )

Number of Shares of Common Stock outstanding as of February 15, 2016  - 1,883,156,295

DOCUMENTS INCORPORATED BY REFERENCE

(To The Extent Indicated Herein)

Notice of the 2016 Annual Meeting and 2016 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, in connection with the company's 2016 Annual Meeting of Stockholders (in Part III)

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TABLE OF CONTENTS

CAUTIONARY STATEMENT RELEVANT TO FORWARD-LOOKING INFORMATION
FOR THE PURPOSE OF "SAFE HARBOR" PROVISIONS OF THE
PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This Annual Report on Form 10-K of Chevron Corporation contains forward-looking statements relating to Chevron's operations that are based on management's current expectations, estimates and projections about the petroleum, chemicals and other energy-related industries. Words or phrases such as "anticipates," "expects," "intends," "plans," "targets," "forecasts," "projects," "believes," "seeks," "schedules," "estimates," "may," "could," "should," "budgets," "outlook," "on schedule," "on track" 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, many 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 chemicals margins; the company's ability to realize anticipated cost savings and expenditure reductions; 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 the company's suppliers, vendors, partners and equity affiliates, particularly during extended periods of low prices for crude oil and natural gas; 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 operations due to war, accidents, political events, civil unrest, severe weather, cyber threats and terrorist acts, crude oil production quotas or other actions that might be imposed by the Organization of Petroleum Exporting Countries, or other natural or human causes beyond its control; changing economic, regulatory and political environments in the various countries in which the company operates; general domestic and international economic and political conditions; the potential liability for remedial actions or assessments under existing or future environmental regulations and litigation; significant operational, investment or product changes required by existing or future environmental statutes and regulations, including international agreements and national or regional legislation and regulatory measures to limit or reduce greenhouse gas emissions; 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; material reductions in corporate liquidity and access to debt markets; the effects of changed accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; the company's ability to identify and mitigate the risks and hazards inherent in operating in the global energy industry; and the factors set forth under the heading "Risk Factors" on pages 21 through 23 in this report. Other unpredictable or unknown factors not discussed in this report could also have material adverse effects on forward-looking statements.

Item 1. Business

General Development of Business

Summary Description of Chevron

Chevron Corporation, * a Delaware corporation, manages its investments in subsidiaries and affiliates and provides administrative, financial, management and technology support to U.S. and international subsidiaries that engage in integrated energy and chemicals operations. Upstream operations consist primarily of exploring for, developing and producing crude oil and natural gas; processing, liquefaction, transportation and regasification associated with liquefied natural gas; transporting crude oil by major international oil export pipelines; transporting, storage and marketing of natural gas; and a gas-to-liquids plant. Downstream operations consist primarily of refining crude oil into petroleum products; marketing of crude oil and refined products; transporting crude oil and refined products by pipeline, marine vessel, motor equipment and rail car; and manufacturing and marketing of commodity petrochemicals, plastics for industrial uses and fuel and lubricant additives.

A list of the company's major subsidiaries is presented on page E-4. As of December 31, 2015 , Chevron had approximately 61,500 employees (including about 3,300 service station employees). Approximately 29,600 employees (including about 3,100 service station employees), or 48 percent, were employed in U.S. operations.

Overview of Petroleum Industry

Petroleum industry operations and profitability are influenced by many factors. Prices for crude oil, natural gas, petroleum products and petrochemicals are generally determined by supply and demand. Production levels from the members of the Organization of Petroleum Exporting Countries (OPEC) are a major factor in determining worldwide supply. Demand for crude oil and its products and for natural gas is largely driven by the conditions of local, national and global economies, although weather patterns and taxation relative to other energy sources also play a significant part. Laws and governmental policies, particularly in the areas of taxation, energy and the environment, affect where and how companies conduct their operations and formulate their products and, in some cases, limit their profits directly.

Strong competition exists in all sectors of the petroleum and petrochemical industries in supplying the energy, fuel and chemical needs of industry and individual consumers. Chevron competes with fully integrated, major global petroleum companies, as well as independent and national petroleum companies, for the acquisition of crude oil and natural gas leases and other properties and for the equipment and labor required to develop and operate those properties. In its downstream business, Chevron competes with fully integrated, major petroleum companies and other independent refining, marketing, transportation and chemicals entities and national petroleum companies in the sale or acquisition of various goods or services in many national and international markets.

Operating Environment

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

Chevron's Strategic Direction

Chevron's primary objective is to create shareholder value and achieve sustained financial returns from its operations that will enable it to outperform its competitors. In the upstream, the company's strategies are to grow profitably in core areas and build new legacy positions. In the downstream, the strategies are to deliver competitive returns and grow earnings across the value chain. The company also continues to apply commercial and functional excellence in supply, trading and transportation to enable the success of the upstream and downstream strategies, and to utilize technology across all its businesses to differentiate performance.

Information about the company is available on the company's website at www.chevron.com . Information contained on the company's website is not part of this Annual Report on Form 10-K. The company's Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available free of charge on the company's website soon after such reports are filed with or furnished to the U.S. Securities and Exchange Commission (SEC). The reports are also available on the SEC's website at www.sec.gov .

Description of Business and Properties

The upstream and downstream activities of the company and its equity affiliates are widely dispersed geographically, with operations and projects * in North America, South America, Europe, Africa, Asia and Australia. Tabulations of segment sales and other operating revenues, earnings and income taxes for the three years ending December 31, 2015 , and assets as of the end of 2015 and 2014  - for the United States and the company's international geographic areas - are in Note 14 to the Consolidated Financial Statements beginning on page FS-37. Similar comparative data for the company's investments in and income from equity affiliates and property, plant and equipment are in Notes 15 and 16 on pages FS-40 through FS-41. Refer to page FS-13 of this Form 10-K in Management's Discussion and Analysis of Financial Condition and Results of Operations for a discussion of the company's capital and exploratory expenditures.

Upstream

Reserves

Refer to Table V beginning on page FS-65 for a tabulation of the company's proved net liquids (including crude oil, condensate, natural gas liquids and synthetic oil) and natural gas reserves by geographic area, at the beginning of 2013 and each year-end from 2013 through 2015 . Reserves governance, technologies used in establishing proved reserves additions, and major changes to proved reserves by geographic area for the three-year period ended December 31, 2015 , are summarized in the discussion for Table V. Discussion is also provided regarding the nature of, status of, and planned future activities associated with the development of proved undeveloped reserves. The company recognizes reserves for projects with various development periods, sometimes exceeding five years. The external factors that impact the duration of a project include scope and complexity, remoteness or adverse operating conditions, infrastructure constraints, and contractual limitations.

At December 31, 2015, 21 percent of the company's net proved reserves were located in Kazakhstan and 19 percent were located in the United States.

The net proved reserve balances at the end of each of the three years 2013 through 2015 are shown in the following table:

* Oil-equivalent conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of oil .

Net Production of Liquids and Natural Gas

The following table summarizes the net production of liquids and natural gas for 2015 and 2014 by the company and its affiliates. Worldwide oil-equivalent production of 2.622 million barrels per day in 2015 was up 2 percent from 2014 . Production increases from project ramp-ups in the United States and Bangladesh and production entitlement effects in several locations were partially offset by the Partitioned Zone shut-in, normal field declines and the effect of asset sales. Refer to the "Results of Operations" section beginning on page FS-6 for a detailed discussion of the factors explaining the 2013  through 2015 changes in production for crude oil and natural gas liquids, and natural gas, and refer to Table V on pages FS-68 and FS-69 for information on annual production by geographical region.

Production Outlook

The company estimates its average worldwide oil-equivalent production in 2016 will be flat to 4 percent growth compared to 2015. This estimate is subject to many factors and uncertainties, as described beginning on page FS-4. Refer to the "Review of Ongoing Exploration and Production Activities in Key Areas," beginning on page 8, for a discussion of the company's major crude oil and natural gas development projects.

Average Sales Prices and Production Costs per Unit of Production

Refer to Table IV on page FS-64 for the company's average sales price per barrel of crude oil, condensate and natural gas liquids and per thousand cubic feet of natural gas produced, and the average production cost per oil-equivalent barrel for 2015 , 2014 and 2013 .

Gross and Net Productive Wells

The following table summarizes gross and net productive wells at year-end 2015 for the company and its affiliates:

Acreage

At December 31, 2015 , the company owned or had under lease or similar agreements undeveloped and developed crude oil and natural gas properties throughout the world. The geographical distribution of the company's acreage is shown in the following table:

Delivery Commitments

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

In the United States, the company is contractually committed to deliver 160 billion cubic feet of natural gas to third parties through 2018 . The company believes it can satisfy these contracts through a combination of equity production from the company's proved developed U.S. reserves and third-party purchases. These commitments are all based on contracts with indexed pricing terms.

Outside the United States, the company is contractually committed to deliver a total of 1,343 billion cubic feet of natural gas to third parties from 2016 through 2018 from operations in Australia, Colombia, Denmark and the Philippines. These sales contracts contain variable pricing formulas that are generally referenced to the prevailing market price for crude oil, natural gas or other petroleum products at the time of delivery. The company believes it can satisfy these contracts from quantities available from production of the company's proved developed reserves in these countries.

Development Activities

Refer to Table I on page FS-61 for details associated with the company's development expenditures and costs of proved property acquisitions for 2015 , 2014 and 2013 .

The following table summarizes the company's net interest in productive and dry development wells completed in each of the past three years, and the status of the company's development wells drilling at December 31, 2015 . A "development well" is a well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Exploration Activities

Refer to Table I on page FS-61 for detail on the company's exploration expenditures and costs of unproved property acquisitions for 2015 , 2014 and 2013 .

The following table summarizes the company's net interests in productive and dry exploratory wells completed in each of the last three years, and the number of exploratory wells drilling at December 31, 2015 . "Exploratory wells" are wells drilled to find and produce crude oil or natural gas in unproved areas and include delineation and appraisal wells, which are wells drilled to find a new reservoir in a field previously found to be productive of crude oil or natural gas in another reservoir or to extend a known reservoir beyond the proved area.

Review of Ongoing Exploration and Production Activities in Key Areas

Chevron has exploration and production activities in most of the world's major hydrocarbon basins. Chevron's 2015 key upstream activities, some of which are also discussed in Management's Discussion and Analysis of Financial Condition and Results of Operations, beginning on page FS-6, are presented below. The comments include references to "total production" and "net production," which are defined under "Production" in Exhibit 99.1 on page E-10.

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

United States

Upstream activities in the United States are primarily located in California, the Gulf of Mexico, Colorado, Louisiana, Michigan, New Mexico, Ohio, Oklahoma, Pennsylvania, Texas, West Virginia and Wyoming. Net oil-equivalent production in the United States during 2015 averaged 720,000 barrels per day.

In California, the company has significant production in the San Joaquin Valley. In 2015, net daily production averaged 166,000 barrels of crude oil, 61 million cubic feet of natural gas and 3,000 barrels of natural gas liquids (NGLs).

During 2015, net daily production in the Gulf of Mexico averaged 164,000 barrels of crude oil, 315 million cubic feet of natural gas and 16,000 barrels of NGLs. The company is pursuing selected opportunities for divestment of shelf assets in the Gulf of Mexico. Chevron is also engaged in various exploration, development and production activities in the deepwater Gulf of Mexico.

The deepwater Jack and St. Malo fields are being jointly developed with a host floating production unit (FPU) located between the two fields. Chevron has a 50 percent interest in the Jack Field and a 51 percent interest in the St. Malo Field. Both fields are company operated. The company has a 40.6 percent interest in the production host facility, which is designed to accommodate production from the Jack/St. Malo development and third-party tiebacks. Total daily production from the Jack and St. Malo fields in 2015 averaged 61,000 barrels of liquids (31,000 net) and 10 million cubic feet of natural gas (5 million net). Production ramp-up and development drilling for the first development phase continued in 2015. In addition, front-end engineering and design (FEED) activities for the second development phase, Stage 2, were completed in September 2015. Drilling of the Stage 2 development wells commenced in fourth quarter 2015 and is planned to continue into 2016. First oil from Stage 2 is expected in 2017, and proved reserves have been recognized for this project. Production from the Jack/St. Malo development is expected to ramp up to a total daily rate of 94,000 barrels of crude oil and 21 million cubic feet of natural gas. The Jack and St. Malo fields have an estimated remaining production life of 30 years.

The development plan for the 60 percent-owned and operated Big Foot Project includes a 15-slot drilling and production platform with water injection facilities and a design capacity of 75,000 barrels of crude oil and 25 million cubic feet of natural gas per day. Work to install the platform was suspended in second quarter 2015 when nine of 16 mooring tendons lost buoyancy. The remaining tendons were recovered, and the platform was moved to a safe harbor location. As of early 2016, the company is completing reviews of schedule and cost estimate. No production is expected in 2016 or 2017. The field has an estimated production life of 35 years from the time of start-up. Proved reserves have been recognized for this project.

At the 58 percent-owned and operated Tahiti Field, net daily production averaged 31,000 barrels of crude oil, 12 million cubic feet of natural gas, and 2,000 barrels of NGLs. The next development phase, the Tahiti Vertical Expansion Project, entered FEED in mid-2015, and a final investment decision is expected in mid-2016. At the end of 2015, proved reserves had not been recognized for the vertical expansion project. The Tahiti Field has an estimated remaining production life of at least 20 years.

The company has a 42.9 percent nonoperated working interest in the Tubular Bells Field. In 2015, net daily production averaged 10,000 barrels of crude oil and 20 million cubic feet of natural gas. Development drilling continued during 2015.

The company has a 15.6 percent nonoperated working interest in the Mad Dog Field. The first of five planned infill wells commenced production in fourth quarter 2015. The next development phase, the Mad Dog 2 Project, is planned to develop the southern portion of the Mad Dog Field. FEED activities continued during 2015. At the end of 2015, proved reserves had not been recognized for the Mad Dog 2 Project.

Chevron holds a 25 percent nonoperated working interest in the Stampede Project, the unitized development of the Knotty Head and Pony discoveries. The planned facilities have a design capacity of 80,000 barrels of crude oil and 40 million cubic feet of natural gas per day. Development drilling commenced in fourth quarter 2015, with first oil expected in 2018. The field has an estimated production life of 30 years from the time of start-up. Proved reserves have been recognized for this project.

FEED activities progressed in 2015 on a project to jointly develop the 55 percent-owned and operated Buckskin Field and the 87.5 percent-owned and operated Moccasin Field. A decision was made in fourth quarter 2015 not to pursue the development. In January 2016, the company relinquished its interest in Moccasin and transferred the operatorship of Buckskin to another working interest partner. The company plans to transfer its interest in Buckskin to the other working interest owners in 2016.

During 2015 and early 2016, the company participated in five appraisal wells and four exploration wells in the deepwater Gulf of Mexico. Drilling was completed at the 50 percent-owned and operated Sicily exploration well in second quarter 2015, which resulted in a crude oil discovery. Drilling commenced on an appraisal well at Sicily in December 2015. Appraisal activities, including a sidetrack of the discovery well, at the 55 percent-owned and operated Anchor discovery were completed in fourth quarter 2015 and were successful. Drilling commenced on an additional appraisal well at Anchor in first quarter 2016.

Chevron is the operator of an exploration and appraisal program covering 28 jointly held offshore leases in the northwest portion of Keathley Canyon. This area may have the potential to support a multifield hub development of the Guadalupe and Tiber discoveries, with the potential addition of the Gibson prospect. This potential development, named Tigris, is under evaluation as exploration and appraisal work progresses. Drilling of a sidetrack well at the 36 percent-owned and operated Gila discovery was completed in third quarter 2015. The Gila prospect was deemed noncommercial, and two of the leases were relinquished in early 2016. Drilling commenced at a 36 percent-owned and operated Gibson exploration well in fourth quarter 2015 and is planned to be completed in second quarter 2016.

Chevron added thirteen leases to its deepwater portfolio as a result of awards from the central Gulf of Mexico Lease Sale 235, held in first quarter 2015.

The company produces crude oil and natural gas in the midcontinent region of the United States, primarily in Colorado, New Mexico, Oklahoma, Texas and Wyoming. During 2015, net daily production in these areas averaged 116,000 barrels of crude oil, 600 million cubic feet of natural gas and 34,000 barrels of NGLs. The company is pursuing selected opportunities for divestment.

In the Permian Basin of West Texas and southeast New Mexico, development drilling of shale and tight resources in the Midland and Delaware basins focused on horizontal wells with multistage fracture stimulation, where the company holds approximately 500,000 and 1,000,000 net acres, respectively. The company drilled 147 wells and participated in 180 nonoperated wells in the Midland and Delaware basins in 2015.

The company holds leases in the Marcellus Shale and the Utica Shale, primarily located in southwestern Pennsylvania, eastern Ohio and the West Virginia panhandle, and in the Antrim Shale and Collingwood/Utica Shale in Michigan. During 2015, net production in these areas averaged 334 million cubic feet of natural gas per day. In 2015, development of the Marcellus Shale progressed at a measured pace and was focused on improving execution capability, well performance and cost effectiveness. Activities in the Utica Shale during 2015 focused on exploration drilling to acquire data necessary for potential future development.

Other Americas

"Other Americas" includes Argentina, Brazil, Canada, Colombia, Greenland, Suriname, Trinidad and Tobago and Venezuela. Net oil-equivalent production from these countries averaged 224,000 barrels per day during 2015.

Canada Upstream activities in Canada are concentrated in Alberta, British Columbia and the offshore Atlantic region. The company also has exploration interests in the Beaufort Sea region of the Northwest Territories. Net oil-equivalent production during 2015 averaged 69,000 barrels per day, composed of 20,000 barrels of crude oil, 14 million cubic feet of natural gas and 47,000 barrels of synthetic oil from oil sands.

Chevron holds a 26.9 percent nonoperated working interest in the Hibernia Field, which comprises the Hibernia and Ben Nevis Avalon (BNA) reservoirs, and a 23.6 percent nonoperated working interest in the unitized Hibernia Southern Extension (HSE) areas offshore Atlantic Canada. Production start-up of HSE was achieved in 2015. The company holds a 29.6 percent nonoperated working interest in the heavy oil Hebron Field, also offshore Atlantic Canada. The development plan includes a platform with a design capacity of 150,000 barrels of crude oil per day. Construction activities progressed in 2015. The project has an expected economic life of 30 years from the time of start-up, and first oil is expected in 2017. Proved reserves have been recognized for this project.

In the Flemish Pass Basin offshore Newfoundland, Chevron holds a 40 percent nonoperated working interest in two exploration blocks. A 3-D seismic survey was completed on these blocks, and exploratory drilling commenced in the fourth quarter 2015 and is expected to be completed in March 2016. In November 2015, the company was awarded a 35 percent interest and

operatorship in another block in the Flemish Pass Basin.

The company holds a 20 percent nonoperated working interest in the Athabasca Oil Sands Project (AOSP) in Alberta. Oil sands are mined from both the Muskeg River and the Jackpine mines, and bitumen is extracted from the oil sands and upgraded into synthetic oil. Construction progressed during 2015 on the Quest Project, and the project was commissioned in the fourth quarter. The Quest Project is designed to capture and store more than one million tons of carbon dioxide produced annually by AOSP bitumen processing.

The company holds approximately 228,000 net acres in the Duvernay Shale in Alberta and approximately 200,000 overlying acres in the Montney tight rock formation. Chevron has a 70 percent-owned and operated interest in most of the Duvernay acreage. Production from the initial wells in the Duvernay continued to demonstrate good flow rates and high condensate yields. Drilling continued during 2015 on an expanded 16-well appraisal program. A total of 28 wells had been tied into production facilities by early 2016.

Chevron holds a 50 percent-owned and operated interest in the proposed Kitimat LNG and Pacific Trail Pipeline projects and a 50 percent interest in 300,000 net acres in the Horn River and Liard shale gas basins in British Colombia. The Kitimat LNG Project is planned to include a two-train LNG facility and has a 10.0 million-metric-ton-per-year export license. The total production capacity for the project is expected to be 1.6 billion cubic feet of natural gas per day. Spending is being paced until LNG market conditions and reductions in project costs are sufficient to support the development of this project. The company became operator of the upstream portion of the project in May 2015 and continued with the horizontal appraisal drilling program that began in 2014. At the end of 2015, proved reserves had not been recognized for this project.

The company holds a 93.8 percent operated interest in the Aitken Creek and a 42.9 percent nonoperated interest in the Alberta Hub natural gas storage facilities, which have an aggregate total capacity of approximately 100 billion cubic feet. These facilities are located adjacent to several shale gas plays. The company is pursuing opportunities for divestment of these interests.

Greenland Chevron holds a 29.2 percent-owned and operated interest in Blocks 9 and 14 located in the Kanumas Area, offshore the northeast coast of Greenland. The company acquired 2-D seismic data in 2015 and evaluation of the acreage is ongoing.

Argentina In the Vaca Muerta Shale formation, Chevron holds a 50 percent nonoperated interest in two concessions covering 73,000 net acres. Chevron also holds an 85 percent-owned and operated interest in one concession covering 94,000 net acres with both conventional production and Vaca Muerta Shale potential. In addition, the company holds operated interests in three concessions covering 73,000 net acres in the Neuquen Basin, with interests ranging from 18.8 percent to 100 percent. Net oil-equivalent production in 2015 averaged 27,000 barrels per day, composed of 21,000 barrels of crude oil and 36 million cubic feet of natural gas.

Development activities continued at the Loma Campana concession in the Vaca Muerta Shale where 156 wells were drilled in 2015, most of which were vertical wells. In 2016, the drilling plan shifts to primarily horizontal wells.

During 2015, the company progressed the exploration of shale oil and gas resources in the Narambuena Block in the Chihuido de la Sierra Negra concession, also in the Vaca Muerta Shale. The exploration plan for Narambuena includes nine wells to be drilled in two phases.

Brazil Chevron holds interests in the Frade (51.7 percent-owned and operated) and Papa-Terra (37.5 percent-owned and nonoperated) deepwater fields located in the Campos Basin. The concession that includes the Frade Field expires in 2025 and the concession that includes the Papa-Terra Field expires in 2032. Net oil-equivalent production in 2015 averaged 18,000 barrels per day, composed of 17,000 barrels of crude oil and 5 million cubic feet of natural gas.

Additionally, Chevron holds a 50 percent-owned and operated interest in Block CE-M715, located in the Ceara Basin offshore equatorial Brazil. Acquisition of 3-D seismic data commenced in September 2015.

Colombia The company operates the offshore Chuchupa and the onshore Ballena natural gas fields and receives 43 percent of the production for the remaining life of each field and a variable production volume based on prior Chuchupa capital contributions. Net production in 2015 averaged 161 million cubic feet of natural gas per day.

Suriname Chevron holds a 50 percent nonoperated working interest in deepwater Blocks 42 and 45 offshore Suriname. Farm-down opportunities are being pursued for the two blocks.

Trinidad and Tobago The company has a 50 percent nonoperated working interest in three blocks in the East Coast Marine Area offshore Trinidad, which includes the Dolphin, Dolphin Deep and Starfish natural gas fields. Net production in 2015 averaged 116 million cubic feet of natural gas per day.

Venezuela Chevron's production activities in Venezuela are performed by two affiliates in western Venezuela and one affiliate in the Orinoco Belt. Net oil-equivalent production during 2015 averaged 64,000 barrels per day, composed of 30,000 barrels of crude oil, 30 million cubic feet of natural gas and 29,000 barrels of synthetic oil upgraded from heavy oil.

Chevron has a 30 percent interest in the Petropiar affiliate that operates the Hamaca heavy oil production and upgrading project located in Venezuela's Orinoco Belt under an agreement expiring in 2033. Petropiar drilled 41 development wells in 2015. Chevron also holds a 39.2 percent interest in the Petroboscan affiliate that operates the Boscan Field in western Venezuela and a 25.2 percent interest in the Petroindependiente affiliate that operates the LL-652 Field in Lake Maracaibo, both of which are under agreements expiring in 2026. Petroboscan drilled 30 development wells in 2015.

Chevron also holds a 34 percent interest in the Petroindependencia affiliate which includes the Carabobo 3 heavy oil project located within the Orinoco Belt.

Africa

In Africa, the company is engaged in upstream activities in Angola, Democratic Republic of the Congo, Liberia, Mauritania, Morocco, Nigeria and Republic of Congo. Net oil-equivalent production averaged 412 , 000 barrels per day during 2015.

Angola  The company operates and holds a 39.2 percent interest in Block 0, a concession adjacent to the Cabinda coastline, and a 31 percent interest in a production-sharing contract (PSC) for deepwater Block 14. The concession for Block 0 extends through 2030 and the development and production rights for the various producing fields in Block 14 expire between 2023 and 2028. In addition, Chevron has a 36.4 percent interest in Angola LNG Limited. During 2015, net production averaged 110,000 barrels of liquids and 55 million cubic feet of natural gas per day.

Mafumeira Sul, the second development stage for the Mafumeira Field in Block 0, has a design capacity of 150,000 barrels of liquids and 350 million cubic feet of natural gas per day. Construction, hook-up and development drilling activities progressed during 2015. First production is planned for second-half 2016, and ramp-up to full production is expected to continue through 2018. Proved reserves have been recognized for this project.

Start-up occurred in first quarter 2015 on the Nemba Enhanced Secondary Recovery Stage 1 & 2 Project in Block 0. In 2015, total production averaged 7,000 barrels of crude oil per day.

Angola LNG Limited operates an onshore natural gas liquefaction plant in Soyo, Angola. The plant has the capacity to process 1.1 billion cubic feet of natural gas per day, with expected average total daily sales of 670 million cubic feet of natural gas and up to 63,000 barrels of NGLs. This is the world's first LNG plant supplied with associated gas, where the natural gas is a byproduct of crude oil production. Feedstock for the plant originates from multiple fields and operators. In early 2016, work was completed on plant modifications and capacity and reliability enhancements. First LNG cargo is expected in second quarter 2016. The remaining economic life of the project is anticipated to be in excess of 20 years.

The company also holds a 38.1 percent interest in the Congo River Canyon Crossing Pipeline project that is designed to transport up to 250 million cubic feet of natural gas per day from Block 0 and Block 14 to the Angola LNG plant. Construction on the 87-mile offshore pipeline was completed in mid-2015. Start-up is planned for 2016.

Angola-Republic of Congo Joint Development Area  Chevron operates and holds a 31.3 percent interest in the Lianzi Unitization Zone, located in an area shared equally by Angola and Republic of Congo. The Lianzi Project has a design capacity of 46,000 barrels of crude oil per day. Construction and initial drilling activities were completed during 2015 and first production occurred in fourth quarter 2015.

Democratic Republic of the Congo  Chevron has a 17.7 percent nonoperated working interest in an offshore concession. Net production in 2015 averaged 2,000 barrels of crude oil per day.

Republic of Congo  Chevron has a 31.5 percent nonoperated working interest in the offshore Haute Mer permit areas (Nkossa, Nsoko and Moho-Bilondo). The licenses for Nsoko, Nkossa, and Moho-Bilondo expire in 2018, 2027 and 2030, respectively. Net production averaged 18,000 barrels of liquids per day in 2015.

During 2015, development drilling and infrastructure work continued on the Moho Nord Project, located in the Moho-Bilondo development area. First production to the existing Moho-Bilondo FPU occurred in December 2015, and total daily production is expected to reach 140,000 barrels of crude oil.

The company has a 20.4 percent nonoperated working interest in the Haute Mer B permit area offshore Republic of Congo. In 2015, the company conducted exploration prospect identification activities.

Liberia  Chevron operates and holds a 45 percent interest Blocks LB-11, LB-12 and LB-14 off the coast of Liberia.

Sierra Leone In third quarter 2015, Chevron relinquished its two deepwater blocks off the coast of Sierra Leone.

Mauritania In early 2015, the company acquired a 30 percent nonoperated working interest in the C8, C12 and C13 contract areas offshore Mauritania. In 2015, a deepwater exploration well was drilled to test the Marsouin prospect in Block C8 and resulted in a natural gas discovery. The company is evaluating whether to retain its working interest in the contract areas.

Morocco The company operates and holds a 75 percent interest in three deepwater areas offshore Morocco. The acquisition of Block Cap Rhir Deep 3-D seismic data was completed in 2015. In early 2016, Chevron reached an agreement to farm out a 30 percent interest in the three leases.

Nigeria  Chevron holds a 40 percent interest in eight operated concessions, in the onshore and near-offshore regions of the Niger Delta. The company also holds acreage positions in three operated and six nonoperated deepwater blocks, with working interests ranging from 20 percent to 100 percent. The company is pursuing selected opportunities for divestment and farm-down in Nigeria. In 2015, the company's net oil-equivalent production in Nigeria averaged 270,000 barrels per day, composed of 224,000 barrels of crude oil, 246 million cubic feet of natural gas and 6,000 barrels of liquefied petroleum gas.

Chevron operates and holds a 67.3 percent interest in the Agbami Field, located in deepwater Oil Mining Lease (OML) 127 and OML 128. During 2015, drilling neared completion on a second phase development program, Agbami 2, that is expected to offset field decline. The last Agbami 2 well is expected on line in second quarter 2016. The third development phase, Agbami 3, is a five-well development program and is also expected to offset field decline. Drilling for Agbami 3 commenced in early 2015 with first production achieved in third quarter 2015. Drilling for Agbami 3 is scheduled to end in 2017. The leases that contain the Agbami Field expire in 2023 and 2024.

Also in the deepwater area, the Aparo Field in OML 132 and OML 140 and the third-party-owned Bonga SW Field in OML 118 share a common geologic structure and are planned to be jointly developed. Chevron holds a 16.6 percent nonoperated working interest in the unitized area. The development plan involves subsea wells tied back to a floating production, storage and offloading vessel (FPSO) with a planned design capacity of 225,000 barrels of crude oil per day. Spending is being paced until market conditions and reductions in project costs are sufficient to support the development of this project. At the end of 2015, no proved reserves were recognized for this project.

In deepwater exploration, Chevron operates and holds a 55 percent interest in the deepwater Nsiko discovery in OML 140 following completion of a farm-down in second quarter 2015. In 2015, two wells of a multiwell program were completed, both resulting in crude oil discoveries. A third exploration well was underway at year-end and is expected to be completed in March 2016. Additional exploration activities are planned for 2016. Chevron also holds a 30 percent nonoperated working interest in OML 138, which includes the Usan Field. In 2015, an exploration well was drilled in the Usan area resulting in a crude oil discovery. In 2016, the company plans to continue to evaluate development opportunities for the 2014 and 2015 discoveries in the Usan area.

In the Niger Delta region, Phase 3B of the Escravos Gas Plant (EGP) project was completed and project start-up was achieved in 2015. This project was designed to gather 120 million cubic feet of natural gas per day from eight near-shore fields and to compress and transport the natural gas to onshore facilities.

Construction activities progressed during 2015 on the 40 percent-owned and operated Sonam Field Development Project, which is designed to process natural gas through EGP, deliver 215 million cubic feet of natural gas per day to the domestic market and produce a total of 30,000 barrels of liquids per day. First production is expected in 2017. Proved reserves have been recognized for the project.

Chevron is the operator of the 33,000-barrel-per-day gas-to-liquids facility at Escravos. The facility is designed to process 325 million cubic feet per day of natural gas.

With a 36.7 percent interest, Chevron is the largest shareholder in the West African Gas Pipeline Company Limited affiliate, which owns and operates the 421-mile West African Gas Pipeline. The pipeline supplies Nigerian natural gas to customers in Benin, Ghana and Togo for industrial applications and power generation and has the capacity to transport 170 million cubic feet per day.

South Africa In 2015, the company discontinued evaluating shale gas exploration opportunities in the Karoo Basin in South Africa.

Asia

In Asia, the company is engaged in upstream activities in Azerbaijan, Bangladesh, China, Indonesia, Kazakhstan, the Kurdistan Region of Iraq, Myanmar, the Partitioned Zone located between Saudi Arabia and Kuwait, the Philippines, Russia, and Thailand. During 2015, net oil-equivalent production averaged 1,089,000 barrels per day.

Azerbaijan  Chevron holds an 11.3 percent nonoperated working interest in the Azerbaijan International Operating Company (AIOC) and the crude oil production from the Azeri-Chirag-Gunashli (ACG) fields. AIOC operations are conducted under a PSC that expires in 2024. Net oil-equivalent production in 2015 averaged 34,000 barrels per day, composed of 32,000 barrels of crude oil and 12 million cubic feet of natural gas. Production at the Chirag Oil Project ramped up in 2015, and drilling activities continue.

Chevron also has an 8.9 percent interest in the Baku-Tbilisi-Ceyhan (BTC) Pipeline affiliate, which transports the majority of ACG production from Baku, Azerbaijan, through Georgia to Mediterranean deepwater port facilities at Ceyhan, Turkey. The BTC Pipeline has a capacity of 1 million barrels per day. Another production export route for crude oil is the Western Route Export Pipeline, which is operated by AIOC, with capacity to transport 100,000 barrels per day from Baku, Azerbaijan, to a marine terminal at Supsa, Georgia.

Kazakhstan  Chevron has a 50 percent interest in the Tengizchevroil (TCO) affiliate and an 18 percent nonoperated working interest in the Karachaganak Field. Net oil-equivalent production in 2015 averaged 392,000 barrels per day, composed of 311,000 barrels of liquids and 486 million cubic feet of natural gas.

TCO is developing the Tengiz and Korolev crude oil fields in western Kazakhstan under a concession agreement that expires in 2033. Net daily production in 2015 from these fields averaged 257,000 barrels of crude oil, 348 million cubic feet of natural gas and 21,000 barrels of NGLs. The majority of TCO's crude oil production was exported through the Caspian Pipeline Consortium (CPC) Pipeline that runs from Tengiz in Kazakhstan to tanker-loading facilities at Novorossiysk on the Russian coast of the Black Sea. The balance of production was exported by rail to Black Sea ports and via the BTC Pipeline to the Mediterranean.

In 2015, work progressed on three projects. The Capacity and Reliability (CAR) Project is designed to reduce facility bottlenecks and increase plant capacity and reliability. Fabrication activities for the CAR Project progressed during 2015. The Wellhead Pressure Management Project (WPMP) is designed to maintain production capacity and extend the production plateau from existing assets. The Future Growth Project (FGP) is designed to increase total daily production by 250,000 to 300,000 barrels of liquids and to increase ultimate recovery from the reservoir. The FGP is planned to expand the utilization of sour gas injection technology proven in existing operations. The final investment decisions for the FGP and the WPMP are expected in mid-2016 following final alignment with partners on project costs and funding. Proved reserves have been recognized for the WPMP and the CAR Project.

The Karachaganak Field is located in northwest Kazakhstan, and operations are conducted under a PSC that expires in 2038. During 2015, net daily production averaged 33,000 barrels of liquids and 138 million cubic feet of natural gas. Access to the CPC Pipeline and Atyrau-Samara (Russia) Pipeline enabled most of the Karachaganak liquids to be exported and sold at world-market prices during 2015. The remaining liquids were sold into local and Russian markets. Work continues on identifying the optimal scope for the future expansion of the field. At year-end 2015, proved reserves had not been recognized for future expansion opportunities.

Kazakhstan/Russia  Chevron has a 15 percent interest in the CPC affiliate. During 2015, CPC transported an average of 927,000 barrels of crude oil per day, composed of 824,000 barrels per day from Kazakhstan and 103,000 barrels per day from Russia. In 2015, work continued on the expansion of the pipeline. By mid-2015, capacity from Kazakhstan had been increased to 925,000 barrels per day allowing 100 percent of TCO's production to be exported via the CPC Pipeline. Additional capacity is scheduled to be added through the end of 2016 to reach the design capacity of 1.4 million barrels per day. The expansion is expected to provide additional transportation capacity that accommodates a portion of the future growth in TCO production.

Bangladesh  Chevron operates and holds a 100 percent interest in Block 12 (Bibiyana Field) and Blocks 13 and 14 (Jalalabad and Moulavi Bazar fields). The rights to produce from Jalalabad expire in 2024, from Moulavi Bazar in 2028 and from Bibiyana in 2034. Net oil-equivalent production in 2015 averaged 123,000 barrels per day, composed of 720 million cubic feet of natural gas and 3,000 barrels of condensate.

The Bibiyana Expansion Project has an incremental design capacity of 300 million cubic feet of natural gas and 4,000 barrels of condensate per day. Start-up of the liquid recovery facility was achieved in first quarter 2015. The expected economic life of the project is the duration of the PSC. Activities continued on the Bibiyana Compression Project during 2015. The project is

expected to provide incremental production to offset field declines. A final investment decision is pending commercial negotiations. At the end of 2015, proved reserves had not been recognized for this project.

China  Chevron has operated and nonoperated working interests in several areas in China. The company's net production in 2015 averaged 24,000 barrels of crude oil per day.

The company operates the 49 percent-owned Chuandongbei Project, located onshore in the Sichuan Basin. The first stage of the project's development includes the Xuanhan Gas Plant's initial three gas processing trains with a design outlet capacity of 258 million cubic feet per day. Production commenced from the Xuanhan Plant in January 2016. The company continues to assess alternatives for the optimum development of the remaining Chuandongbei natural gas area. The PSC expires in 2038.

The company completed one exploration well in Block 15/10 in the South China Sea in May 2015. The results were unsuccessful, and the block was relinquished in September 2015. The company also relinquished Block 15/28 in September 2015.

The company also has nonoperated working interests of 24.5 percent in the QHD 32-6 Field and 16.2 percent in Block 11/19 in the Bohai Bay, and 32.7 percent in Block 16/19 in the Pearl River Mouth Basin. The PSCs for these producing assets expire between 2022 and 2028.

Indonesia  Chevron holds working interests through various PSCs in Indonesia. In Sumatra, the company holds a 100 percent-owned and operated interest in the Rokan PSC. Chevron also operates four PSCs in the Kutei Basin, located offshore eastern Kalimantan. These interests range from 62 percent to 92.5 percent. In addition, Chevron holds a 25 percent nonoperated working interest in Block B in the South Natuna Sea. Net oil-equivalent production in 2015 averaged 207,000 barrels per day, composed of 176,000 barrels of liquids and 185 million cubic feet of natural gas. In 2016, Chevron advised the government of Indonesia that it would not propose to extend the East Kalimantan PSC and intends to return the assets to the government upon PSC expiration in 2018.

The largest producing field is Duri, located in the Rokan PSC. Duri has been under steamflood since 1985 and is one of the world's largest steamflood developments. The company continues to implement projects designed to sustain production from existing reservoirs. The Duri Field Area 13 steamflood expansion was completed in 2015 with all wells on production and injection by year-end. Infill drilling and workover programs also continued in 2015. The Rokan PSC expires in 2021.

There are two deepwater natural gas development projects in the Kutei Basin progressing under a single plan of development. Collectively, these projects are referred to as the Indonesia Deepwater Development. One of these projects, Bangka, has a design capacity of 115 million cubic feet of natural gas and 4,000 barrels of condensate per day. The company's interest is 62 percent. Installation of subsea facilities and completion of the two development wells continues to progress, with first gas planned for second-half 2016. Proved reserves have been recognized for this project.

The other project, Gendalo-Gehem, has a planned design capacity of 1.1 billion cubic feet of natural gas and 47,000 barrels of condensate per day. The company's interest is approximately 63 percent. The company continues to work toward a final investment decision, subject to the timing of government approvals, including extension of the associated PSCs, and securing new LNG sales contracts. At the end of 2015, proved reserves have not been recognized for this project.

In West Java, the company operates the Darajat geothermal field and holds a 95 percent interest in two power plants. The field supplies steam to a power plant with a total operating capacity of 270 megawatts. Chevron also operates and holds a 100 percent interest in the Salak geothermal field in West Java, which supplies steam to a six-unit power plant, three of which are company owned, with a total operating capacity of 377 megawatts.

Myanmar  Chevron has a 28.3 percent nonoperated working interest in a PSC for the production of natural gas from the Yadana and Sein fields, within Blocks M5 and M6, in the Andaman Sea. The PSC expires in 2028. The company also has a 28.3 percent nonoperated interest in a pipeline company that transports most of the natural gas to the Myanmar-Thailand border for delivery to power plants in Thailand. Net natural gas production in 2015 averaged 117 million cubic feet per day.

The Badamyar-Low Compression Platform is an expansion project in Block M5 designed to maintain production from the Yadana Field by lowering wellhead pressure. Fabrication activities progressed in 2015 with first production expected in 2017. Proved reserves have been recognized for this project.

In second quarter 2015, Chevron signed a PSC to explore for oil and gas in Block A5. The company holds a 99 percent interest in and operates this block. A 3-D seismic survey was completed in December 2015.

Philippines  The company holds a 45 percent nonoperated working interest in the Malampaya natural gas field, offshore Palawan. Net oil-equivalent production in 2015 averaged 23,000 barrels per day, composed of 122 million cubic feet of natural gas and 3,000 barrels of condensate. The Malampaya Phase 2 Project was completed in September 2015. The infill wells and compression facilities have maintained production and delivered contract volumes to customers.

Chevron holds a 40 percent interest in an affiliate that develops and produces geothermal steam resources in southern Luzon, which supplies steam to third-party power generation facilities with a combined operating capacity of 692 megawatts. The renewable energy service contract expires in 2038. Chevron also has an interest in the Kalinga geothermal prospect area in northern Luzon.

Thailand  Chevron holds operated interests in the Pattani Basin, located in the Gulf of Thailand, with ownership ranging from 35 percent to 80 percent. Concessions for producing areas within this basin expire between 2020 and 2035. Chevron also has a 16 percent nonoperated working interest in the Arthit Field located in the Malay Basin. Concessions for the producing areas within this basin expire between 2036 and 2040. Net oil-equivalent production in 2015 averaged 238,000 barrels per day, composed of 66,000 barrels of crude oil and condensate and 1 billion cubic feet of natural gas.

In the Pattani Basin, the development concept of the 35 percent-owned and operated Ubon Project includes facilities and wells to develop resources in Block12/27. The company continues to assess alternatives for the optimum development of the Ubon Field. At the end of 2015, proved reserves had not been recognized for this project.

During 2015, the company drilled three exploration and three delineation wells in the Pattani Basin, with all wells successful. In addition, two successful exploration wells were drilled in the Arthit Field. The company also holds exploration interests in the Thailand-Cambodia overlapping claim area that are inactive, pending resolution of border issues between Thailand and Cambodia.

Vietnam  In June 2015, Chevron completed the sale of its entire interest in Vietnam, which included a 42.4 percent working interest in Blocks B and 48/95, a 43.4 percent working interest in Block 52/97, and a 28.7 percent nonoperated interest in a pipeline project.

Kurdistan Region of Iraq The company operates and holds 80 percent contractor interests in the Sarta and Qara Dagh PSCs. In first quarter 2015, the company resumed operations and testing programs at the Sarta wells and restarted the seismic data acquisition program at the Qara Dagh Block, which was completed in second quarter 2015. The company drilled a second exploration well in the Sarta Block in second-half 2015, and as of early 2016, the results are under evaluation. The company relinquished its interest in the Rovi Block in fourth quarter 2015.

Partitioned Zone  Chevron holds a concession to operate the Kingdom of Saudi Arabia's 50 percent interest in the hydrocarbon resources in the onshore area of the Partitioned Zone between Saudi Arabia and Kuwait. The concession expires in 2039. During 2015, net oil-equivalent production averaged 28,000 barrels per day, composed of 27,000 barrels of crude oil and 5 million cubic feet of natural gas. Beginning in May 2015, production in the Partitioned Zone was shut in as a result of continued difficulties in securing work and equipment permits. As of early 2016, production remains shut-in and the exact timing of a production restart is uncertain and dependent on dispute resolution between Saudi Arabia and Kuwait.

The shut-in also impacted plans for both the Wafra Steamflood Stage 1 Project, a full-field steamflood application in the Wafra Field First Eocene carbonate reservoir with a planned design capacity of 100,000 barrels of crude oil per day, and the Central Gas Utilization Project, a facility construction project intended to increase natural gas utilization while eliminating natural gas flaring at the Wafra Field. Both projects have been deferred pending dispute resolution between Saudi Arabia and Kuwait. At the end of 2015, proved reserves had not been recognized for these two projects.

In 2015, the company continued to progress a 3-D seismic survey covering the entire onshore Partitioned Zone.

Australia/Oceania

In Australia/Oceania, the company is engaged in upstream activities in Australia and New Zealand. During 2015, net oil-equivalent production averaged 94,000 barrels per day, all from Australia.

Australia Upstream activities in Australia are concentrated offshore Western Australia, where the company is the operator of two major LNG projects, Gorgon and Wheatstone, and has a nonoperated working interest in the North West Shelf (NWS) Venture and exploration acreage in the Browse Basin and the Carnarvon Basin. The company also holds exploration acreage in the Bight Basin offshore South Australia. During 2015, the company's production averaged 21,000 barrels of liquids and 439 million cubic feet of natural gas per day.

Chevron holds a 47.3 percent interest in and is the operator of the Gorgon Project, which includes the development of the Gorgon and Jansz-Io fields. The project includes a three-train, 15.6 million-metric-ton-per-year LNG facility, a carbon dioxide injection facility and a domestic gas plant, which are located on Barrow Island, off Western Australia. The total production capacity for the project is approximately 2.6 billion cubic feet of natural gas and 20,000 barrels of condensate per day. Work on the project continued to progress. LNG Train 1 commissioning and start-up activities progressed, with first cargo lifting expected in March

2016. Trains 2 and 3 are expected to start up sequentially at approximately six-month intervals after LNG Train 1. The project's estimated economic life exceeds 40 years.

Chevron is the operator of the Wheatstone Project, which includes a two-train, 8.9 million-metric-ton-per-year LNG facility and a domestic gas plant, both located at Ashburton North, on the coast of Western Australia. The company plans to supply natural gas to the facilities from the Wheatstone and Iago fields. Chevron holds an 80.2 percent interest in the offshore licenses and a 64.1 percent interest in the LNG facilities. The total production capacity for the Wheatstone and Iago fields and nearby third party fields is expected to be approximately 1.6 billion cubic feet of natural gas and 30,000 barrels of condensate per day. Construction and fabrication continue to progress. Start-up of the first LNG train is targeted for mid-2017. Proved reserves have been recognized for this project. The project's estimated economic life exceeds 30 years from the time of start-up.

Chevron has a 16.7 percent nonoperated working interest in the North West Shelf (NWS) Venture in Western Australia. The concession for the NWS Venture expires in 2034.

Approximately 85 percent of the equity LNG offtake from the Gorgon and Wheatstone projects is targeted to be sold into binding long-term contracts, with the remainder to be sold in the Asian spot LNG market. In December 2015, Chevron signed a nonbinding Heads of Agreement (HOA) for delivery of up to 1 million metric tons per annum (MTPA) of LNG over 10 years starting in 2020. In early 2016, the company announced the signing of a nonbinding HOA for the delivery of up to 0.5 MTPA of LNG over 10 years, with deliveries starting in 2018 or 2019. Assuming these HOAs are converted to binding sales agreements, more than 80 percent of Chevron's equity LNG offtake from these projects would be covered under binding agreements during the time of these agreements. Chevron also has binding, long-term agreements for delivery of natural gas to customers in Western Australia and continues to market additional pipeline natural gas quantities from the projects. In the NWS Venture, approximately 70 percent of Chevron's equity LNG offtake is committed under binding, long-term sales agreements with major utilities in Asia. The company also sells natural gas to the domestic market in Western Australia.

During 2015, the company made one natural gas discovery in the Carnarvon Basin. The discovery at the Isosceles prospect contributes to the resources available to extend and expand Chevron's LNG projects in the region.

T he company holds nonoperated working interests ranging from 24.8 percent to 50 percent in three exploration blocks in the Browse Basin.

The company operates and holds a 100 percent interest in offshore Blocks EPP44 and EPP45 in the Bight Basin off the South Australian coast. In 2015, the company completed its second 3-D seismic survey in this area with processing and interpretation of the seismic data planned to continue through 2016.

In March 2015, the company withdrew from its interest in the Nappamerri Trough area in South Australia and Queensland.

New Zealand In April 2015, Chevron became operator of three deepwater exploration permits in the offshore Pegasus and East Coast basins. Chevron holds a 50 percent interest in the three exploration permits. Acquisition of 2-D and 3-D seismic data is scheduled to commence in late 2016.

Europe

In Europe, the company is engaged in upstream activities in Denmark and the United Kingdom. Net oil-equivalent production averaged 83,000 barrels per day during 2015.

Denmark  Chevron holds a 12 percent nonoperated working interest in the Danish Underground Consortium (DUC), which produces crude oil and natural gas from 13 North Sea fields. The concession expires in 2042. Net oil-equivalent production in 2015 averaged 24,000 barrels per day, composed of 16,000 barrels of crude oil and 50 million cubic feet of natural gas.

Norway The company relinquished its interest in PL 527 and PL 598 exploration licenses in May 2015.

Poland  In 2015, the company relinquished its remaining exploration licenses.

Romania  The company relinquished the Barlad concession in northeast Romania, and as of early 2016, the relinquishment is pending government approval. In addition, the company is pursuing relinquishment of its remaining concessions in southeast Romania.

United Kingdom  The company's net oil-equivalent production in 2015 averaged 59,000 barrels per day, composed of 40,000 barrels of liquids and 115 million cubic feet of natural gas. Most of the company's production was from three fields: the 85 percent-owned and operated Captain Field, the 23.4 percent-owned and operated Alba Field, and the 32.4 percent-owned and nonoperated Britannia Field.

The 73.7 percent-owned and operated Alder Project is being developed as a tieback to the existing Britannia platform, and has a design capacity of 14,000 barrels of condensate and 110 million cubic feet of natural gas per day. Flowline and topsides installations were completed in first quarter 2015 and drilling of the development well commenced in third quarter 2015. First production is expected in second-half 2016. Proved reserves have been recognized for this project.

The Captain Enhanced Oil Recovery Project is the next development phase of the Captain Field and is designed to increase field recovery by injecting polymerized water. FEED activities continued to progress in 2015 and are planned to continue in 2016 as polymer performance is evaluated. At the end of 2015, proved reserves had not been recognized for this project.

During 2015, fabrication and installation activities continued for the Clair Ridge Project, located west of the Shetland Islands, in which the company has a 19.4 percent nonoperated working interest. The project is the second development phase of the Clair Field. The design capacity of the project is 120,000 barrels of crude oil and 100 million cubic feet of natural gas per day. Production is scheduled to begin in 2017. The Clair Field has an estimated production life until 2050. Proved reserves have been recognized for the Clair Ridge Project.

At the 40 percent-owned and operated Rosebank Project northwest of the Shetland Islands, the company continued to progress FEED activities for a 17-well subsea development tied back to an FPSO with natural gas exported via pipeline. The design capacity of the project is 100,000 barrels of crude oil and 80 million cubic feet of natural gas per day. At the end of 2015, proved reserves had not been recognized for this project.

Sales of Natural Gas and Natural Gas Liquids

The company sells natural gas and natural gas liquids (NGLs) from its producing operations under a variety of contractual arrangements. In addition, the company also makes third-party purchases and sales of natural gas and NGLs in connection with its supply and trading activities.

During 2015 , U.S. and international sales of natural gas averaged 3.9  billion and 4.3  billion cubic feet per day, respectively, which includes the company's share of equity affiliates' sales. Outside the United States, substantially all of the natural gas sales from the company's producing interests are from operations in Australia, Bangladesh, Europe, Kazakhstan, Indonesia, Latin America, Myanmar, Nigeria, the Philippines and Thailand.

U.S. and international sales of NGLs averaged 153,000 and 89,000 barrels per day, respectively, in 2015 . Substantially all of the international sales of NGLs from the company's producing interests are from operations in Africa, Australia, Canada, Indonesia and the United Kingdom.

Refer to "Selected Operating Data," on page FS-11 in Management's Discussion and Analysis of Financial Condition and Results of Operations, for further information on the company's sales volumes of natural gas and natural gas liquids. Refer also to "Delivery Commitments" beginning on page 6 for information related to the company's delivery commitments for the sale of crude oil and natural gas.

Downstream

Refining Operations

At the end of 2015 , the company had a refining network capable of processing over 1.8 million barrels of crude oil per day. Operable capacity at December 31, 2015 , and daily refinery inputs for 2013 through 2015 for the company and affiliate refineries are summarized in the table below.

Average crude oil distillation capacity utilization during 2015 was 90 percent, compared with 87 percent in 2014 . At the U.S. refineries, crude oil distillation capacity utilization averaged 96 percent in 2015 , compared with 91 percent in 2014 . Chevron processes both imported and domestic crude oil in its U.S. refining operations. Imported crude oil accounted for about 74 percent and 73 percent of Chevron's U.S. refinery inputs in 2015 and 2014 , respectively.

In the United States, the company continued work on projects to improve refinery flexibility, reliability and capability to process lower cost feedstocks. At the Richmond, California refinery, the company received all remaining regulatory approvals in 2015 to resume construction of its modernization project. Engineering is being finalized, and construction activity is expected to restart in 2016. In addition, Chevron is pursuing the possible divestment of the Hawaii Refinery and related assets.

Outside the United States, the Singapore Refining Company, Chevron's 50 percent-owned joint venture, progressed construction of a gasoline desulfurization facility and a cogeneration plant. This investment is expected to increase the refinery's capability to produce higher value gasoline and to improve energy efficiency. The company sold its 50 percent interest in Caltex Australia Limited in April 2015. In June 2015, the company sold its interest in a refinery in New Zealand. The company has signed an agreement for the sale of its interest in a refinery in Pakistan, which is pending government approval. The company is also evaluating the sale of its interests in the Cape Town Refinery in South Africa.

Petroleum Refineries: Locations, Capacities and Inputs

Marketing Operations

The company markets petroleum products under the principal brands of "Chevron," "Texaco" and "Caltex" throughout many parts of the world. The following table identifies the company's and affiliates' refined products sales volumes, excluding intercompany sales, for the three years ended December 31, 2015 .

Refined Products Sales Volumes

In the United States, the company markets under the Chevron and Texaco brands. At year-end 2015 , the company supplied directly or through retailers and marketers approximately 7,860 Chevron- and Texaco-branded motor vehicle service stations, primarily in the southern and western states. Approximately 370 of these outlets are company-owned or -leased stations.

Outside the United States, Chevron supplied directly or through retailers and marketers approximately 6,090 branded service stations, including affiliates. In British Columbia, Canada, the company markets under the Chevron brand. The company markets in Latin America using the Texaco brand. In the Asia-Pacific region, southern Africa and the Middle East, the company uses the Caltex brand. The company also operates through affiliates under various brand names. In South Korea, the company operates through its 50 percent-owned affiliate, GS Caltex. Divestments of fuels marketing operations in 2015 include those owned by Caltex Australia Limited, as well as company-owned operations in Pakistan. The company expects to complete the sale of its New Zealand marketing operations in second quarter 2016, pending government approval. The company is also pursuing the sale of its marketing and lubricants businesses in southern Africa.

Chevron markets commercial aviation fuel at approximately 100 airports worldwide. The company also markets an extensive line of lubricant and coolant products under the product names Havoline, Delo, Ursa, Meropa, Rando, Clarity and Taro in the United States and worldwide under the three brands: Chevron, Texaco and Caltex.

Chemicals Operations

Chevron owns a 50 percent interest in its Chevron Phillips Chemical Company LLC (CPChem) affiliate. CPChem produces olefins, polyolefins and alpha olefins and is a supplier of aromatics and polyethylene pipe, in addition to participating in the specialty chemical and specialty plastics markets. At the end of 2015 , CPChem owned or had joint-venture interests in 34 manufacturing facilities and two research and development centers around the world.

In second quarter 2015, CPChem completed construction and started commercial operations of a 100,000 metric-ton-per-year expansion of normal alpha olefins production capacity at its Cedar Bayou Plant in Baytown, Texas. In 2015, construction advanced on the U.S. Gulf Coast Petrochemicals Project, which is expected to capitalize on advantaged feedstock sourced from shale gas development in North America. The project includes an ethane cracker with an annual design capacity of 1.5 million metric tons of ethylene to be located at the Cedar Bayou facility and two polyethylene units to be located in Old Ocean, Texas, with a combined annual design capacity of one million metric tons. Start-up is expected in 2017.

Chevron Oronite Company develops, manufactures and markets performance additives for lubricating oils and fuels and conducts research and development for additive component and blended packages. At the end of 2015, the company manufactured, blended or conducted research at 10 locations around the world. In 2015, the company progressed construction on a carboxylate plant in Singapore with expected start-up in 2017. In addition, an investment agreement was signed to build an additive manufacturing plant in Ningbo, China. The plant design is under development, with a final investment decision expected by 2018.

Chevron also maintains a role in the petrochemical business through the operations of GS Caltex, a 50 percent-owned affiliate. GS Caltex manufactures aromatics, including benzene, toluene and xylene. These base chemicals are used to produce a range of products, including adhesives, plastics and textile fibers. GS Caltex also produces polypropylene, which is used to make food packaging, laboratory equipment and textiles.

Transportation

Pipelines  Chevron owns and operates a network of crude oil, natural gas, natural gas liquid, refined product and chemical pipelines and other infrastructure assets in the United States. In addition, Chevron operates pipelines for its 50 percent-owned CPChem affiliate. The company also has direct and indirect interests in other U.S. and international pipelines.

Refer to pages 12 and 13 in the Upstream section for information on the West African Gas Pipeline, the Baku-Tbilisi-Ceyhan Pipeline, the Western Route Export Pipeline and the Caspian Pipeline Consortium.

Shipping  The company's marine fleet includes both U.S. and foreign-flagged vessels. The U.S.-flagged vessels are engaged primarily in transporting refined products, primarily in the coastal waters of the United States. The foreign-flagged vessels are engaged primarily in transporting crude oil from the Middle East, Southeast Asia, the Black Sea, South America, Mexico and West Africa to ports in the United States, Europe, Australia and Asia, as well as refined products and feedstocks to and from various locations worldwide.

In 2015, the company took delivery of two additional LNG carriers in support of its developing LNG portfolio. Together with 2014 deliveries, four of six new LNG vessels have been delivered to the fleet.

Other Businesses

Research and Technology Chevron's energy technology organization supports upstream and downstream businesses. The company conducts research, develops and qualifies technology, and provides technical services and competency development. The disciplines cover earth sciences, reservoir and production engineering, drilling and completions, facilities engineering, manufacturing, process technology, catalysis, technical computing and health, environment and safety.

Chevron's information technology organization integrates computing, telecommunications, data management, cybersecurity and network technology to provide a digital infrastructure to enable Chevron's global operations and business processes.

Chevron's technology ventures company supports Chevron's upstream and downstream businesses by bridging the gap between business unit needs and emerging technology solutions developed externally in areas of emerging materials, water management, information technology, power systems and production enhancement.

Some of the investments the company makes in the areas described above are in new or unproven technologies and business processes, and ultimate technical or commercial successes are not certain. Refer to Note 27 beginning on page FS-59 for a summary of the company's research and development expenses.

Environmental Protection The company designs, operates and maintains its facilities to avoid potential spills or leaks and to minimize the impact of those that may occur. Chevron requires its facilities and operations to have operating standards and processes and emergency response plans that address all credible and significant risks identified through site-specific risk and impact assessments. Chevron also requires that sufficient resources be available to execute these plans. In the unlikely event that a major spill or leak occurs, Chevron also maintains a Worldwide Emergency Response Team comprised of employees who are trained in various aspects of emergency response, including post-incident remediation.

To complement the company's capabilities, Chevron maintains active membership in international oil spill response cooperatives, including the Marine Spill Response Corporation, which operates in U.S. territorial waters, and Oil Spill Response, Ltd., which operates globally. The company is a founding member of the Marine Well Containment Company, whose primary mission is to expediently deploy containment equipment and systems to capture and contain crude oil in the unlikely event of a future loss of control of a deepwater well in the Gulf of Mexico. In addition, the company is a member of the Subsea Well Response Project (SWRP). SWRP's objective is to further develop the industry's capability to contain and shut in subsea well control incidents in different regions of the world.

Refer to Management's Discussion and Analysis of Financial Condition and Results of Operations on page FS-16 for additional information on environmental matters and their impact on Chevron, and on the company's 2015 environmental expenditures. Refer to page FS-16 and Note 24 on page FS-57 for a discussion of environmental remediation provisions and year-end reserves. Refer also to Item 1A. Risk Factors on pages 21 through 23 for a discussion of greenhouse gas regulation and climate change.

Item 1A. Risk Factors

Chevron is a global energy company and its operating and financial results are subject to a variety of risks inherent in the global oil, gas, and petrochemical businesses. Many of these risks are not within the company's control and could materially impact the company's results of operations and financial condition.

Chevron is exposed to the effects of changing commodity prices Chevron is primarily in a commodities business that has a history of price volatility. The single largest variable that affects the company's results of operations is the price of crude oil, which can be influenced by general economic conditions, industry inventory levels, technology advancements, production quotas or other actions that might be imposed by the Organization of Petroleum Exporting Countries (OPEC), weather-related damage and disruptions, competing fuel prices, and geopolitical risks. Chevron evaluates the risk of changing commodity prices as part of its business planning process. An investment in the company carries significant exposure to fluctuations in global crude oil prices.

Extended periods of low prices for crude oil can have a material adverse impact on the company's results of operations, financial condition and liquidity. Among other things, the company's upstream earnings, cash flows, and capital and exploratory expenditure programs could be negatively affected, as could its production and proved reserves. Upstream assets may also become impaired. Downstream earnings could be negatively affected because they depend upon the supply and demand for refined products and the associated margins on refined product sales. A significant or sustained decline in liquidity could adversely affect the company's credit ratings, potentially increase financing costs and reduce access to debt markets. The company may be unable to realize anticipated cost savings, expenditure reductions and asset sales that are intended to compensate for such downturns. In some cases, liabilities associated with divested assets may return to the company when an acquirer of those assets subsequently declares bankruptcy. In addition, extended periods of low commodity prices can have a material adverse impact on the results of operations, financial condition and liquidity of the company's suppliers, vendors, partners and equity affiliates upon which the company's own results of operations and financial condition depends.

The scope of Chevron's business will decline if the company does not successfully develop resources The company is in an extractive business; therefore, if it is not successful in replacing the crude oil and natural gas it produces with good prospects for future production or through acquisitions, the company's business will decline. Creating and maintaining an inventory of projects depends on many factors, including obtaining and renewing rights to explore, develop and produce hydrocarbons; drilling success; ability to bring long-lead-time, capital-intensive projects to completion on budget and on schedule; and efficient and profitable operation of mature properties.

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

Chevron's risk management systems are designed to assess potential physical and other risks to its operations and assets and to plan for their resiliency. While capital investment reviews and decisions involve uncertainty analysis, which incorporates potential ranges of physical risks such as storm severity and frequency, sea level rise, air and water temperature, precipitation, fresh water access, wind speed, and earthquake severity, among other factors, it is difficult to predict with certainty the timing, frequency or severity of such events, any of which could have a material adverse effect on the company's results of operations or financial condition.

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

Chevron's business subjects the company to liability risks from litigation or government action The company produces, transports, refines and markets materials with potential toxicity, and it purchases, handles and disposes of other potentially toxic

materials in the course of its business. Chevron's operations also produce byproducts, which may be considered pollutants. Often these operations are conducted through joint ventures over which the company may have limited influence and control. Any of these activities could result in liability or significant delays in operations arising from private litigation or government action, either as a result of an accidental, unlawful discharge or as a result of new conclusions about the effects of the company's operations on human health or the environment. In addition, to the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to the company's causation of or contribution to the asserted damage, or to other mitigating factors.

For information concerning some of the litigation in which the company is involved, including information relating to Ecuador matters, see Note 17 to the Consolidated Financial Statements, beginning on page FS-42.

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

Political instability and significant changes in the regulatory environment could harm Chevron's business The company's operations, particularly exploration and production, can be affected by changing economic, regulatory and political environments in the various countries in which it operates. As has occurred in the past, actions could be taken by governments to increase public ownership of the company's partially or wholly owned businesses or to impose additional taxes or royalties. In certain locations, governments have proposed or imposed restrictions on the company's operations, export and exchange controls, burdensome taxes, and public disclosure requirements that might harm the company's competitiveness or relations with other governments or third parties. In other countries, political conditions have existed that may threaten the safety of employees and the company's continued presence in those countries, and internal unrest, acts of violence or strained relations between a government and the company or other governments may adversely affect the company's operations. Those developments have, at times, significantly affected the company's operations and results and are carefully considered by management when evaluating the level of current and future activity in such countries. In addition, changes in national or state environmental regulations, including those related to the use of hydraulic fracturing, could adversely affect the company's current or anticipated future operations and profitability.

Regulation of greenhouse gas (GHG) emissions could increase Chevron's operational costs and reduce demand for Chevron's hydrocarbon and other products Continued attention to issues concerning GHG emissions and climate change and potential mitigation through legislation and regulation could have a material impact on the company's operations and financial results.

International agreements (e.g., the Paris Accord and the Kyoto Protocol) and national (e.g., carbon tax, cap-and-trade or efficiency standards), regional and state legislation (e.g., California's AB32 or other low carbon fuel standards) and regulatory measures (e.g., the U.S. Environmental Protection Agency's methane performance standards) to limit or reduce GHG emissions are currently in various stages of discussion or implementation and it is difficult to predict with certainty their timing and outcome. These and other GHG emissions-related laws and regulations and the effects of operating in a potentially carbon-constrained environment may result in increased and substantial capital, compliance, operating and maintenance costs and could, among other things, reduce demand for hydrocarbons and the company's hydrocarbon-based products, make the company's products more expensive, and adversely affect the company's sales volumes, revenues and margins. GHG emissions, including carbon dioxide and methane, that could be regulated include, among others, those arising from the company's exploration and production of hydrocarbons such as crude oil and natural gas; the upgrading of production from oil sands into synthetic oil; power generation; the conversion of crude oil and natural gas into refined hydrocarbon products; the processing, liquefaction and regasification of natural gas; the transportation of crude oil, natural gas and related products and consumers' or customers' use of the company's hydrocarbon products. Some of these activities, such as consumers' and customers' use of the company's products, as well as actions taken by the company's competitors in response to such laws and regulations, are beyond the company's control.

Consideration of GHG issues and the responses to those issues through international agreements and national, regional or state legislation or regulations are integrated into the company's strategy and planning, capital investment reviews, and risk management tools and processes, where applicable. They are also factored into the company's long-range supply, demand and energy price forecasts. These forecasts reflect long-range effects from renewable fuel penetration, energy efficiency standards, climate-related policy actions, and demand response to oil and natural gas prices. The actual level of expenditure required to comply with new or potential GHG emissions laws and regulations and amount of additional investments in new or existing technology or facilities, such as carbon dioxide injection, is difficult to predict with certainty and is expected to vary depending on the actual laws and regulations enacted in a jurisdiction, the company's activities in it and market conditions.

The ultimate effect of international agreements and national, regional and state legislation and regulatory measures to limit GHG emissions on the company's financial performance will depend on a number of factors including, among others, the sectors covered, the greenhouse gas emissions reductions required, the extent to which Chevron would be entitled to receive emission allowance allocations or would need to purchase compliance instruments on the open market or through auctions, the price and availability of emission allowances and credits, and the company's ability to recover the costs incurred through the pricing of the company's products.

Changes in management's estimates and assumptions may have a material impact on the company's consolidated financial statements and financial or operational performance in any given period In preparing the company's periodic reports under the Securities Exchange Act of 1934, including its financial statements, Chevron's management is required under applicable rules and regulations to make estimates and assumptions as of a specified date. These estimates and assumptions are based on management's best estimates and experience as of that date and are subject to substantial risk and uncertainty. Materially different results may occur as circumstances change and additional information becomes known. Areas requiring significant estimates and assumptions by management include measurement of benefit obligations for pension and other postretirement benefit plans; estimates of crude oil and natural gas recoverable reserves; accruals for estimated liabilities, including litigation reserves; and impairments to property, plant and equipment. Changes in estimates or assumptions or the information underlying the assumptions, such as changes in the company's business plans, general market conditions or changes in commodity prices, could affect reported amounts of assets, liabilities or expenses.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

The location and character of the company's crude oil and natural gas properties and its refining, marketing, transportation and chemicals facilities are described on page 3 under Item 1. Business. Information required by Subpart 1200 of Regulation S-K ("Disclosure by Registrants Engaged in Oil and Gas Producing Activities") is also contained in Item 1 and in Tables I through VII on pages FS-61 through FS-71. Note 16, "Properties, Plant and Equipment," to the company's financial statements is on page FS-41.

Item 3. Legal Proceedings

Governmental Proceedings As initially disclosed in the Annual Report on Form 10-K for the year ended December 31, 2013, filed on February 21, 2014, on August 6, 2012, a piping failure and fire occurred at the Chevron U.S.A. Inc. refinery in Richmond, California. Various federal, state, and local agencies initiated investigations as a result of the incident. Based on its civil investigation, the United States Environmental Protection Agency (EPA) issued a Finding of Violations (FOV) to Chevron on December 17, 2013, which includes 62 findings of alleged noncompliance at the refinery. The majority of these findings relate to the August 2012 fire and alleged violations of chemical-accident-prevention laws, but the FOV also addresses a number of release-reporting issues, some of which are unrelated to the fire. Resolution of the alleged violations may result in the payment of a civil penalty of $100,000 or more.

As initially disclosed in the Annual Report on Form 10-K for the year ended December 31, 2013, filed on February 21, 2014, in July 2009, the Hawaii Department of Health (DOH) alleged that Chevron is obligated to pay stipulated civil penalties in conjunction with commitments Chevron undertook to install and operate certain air emission control equipment at its Hawaii Refinery pursuant to a Clean Air Act settlement with the United States Environmental Protection Agency (EPA) and the DOH. The company reached a settlement agreement with the EPA and the DOH and paid civil penalties totaling $230,958 to resolve the alleged violations.

As initially disclosed in the Quarterly Report on Form 10-Q for the period ended September 30, 2015, filed on November 6, 2015, on July 29, 2015, the United States Environmental Protection Agency (EPA) notified Chevron that certain Renewable Identification Number (RIN) credits it had submitted for compliance with the federal Renewable Fuel Standard for 2011 were invalid because they were fraudulently generated by a third party that sold the credits to Chevron.  On September 30, 2015, Chevron received a civil penalty demand of $175,923 from the EPA for the submission of the invalid RINs.  The company paid $175,923 in civil penalties to resolve the demand.

Other Proceedings Information related to other legal proceedings, including Ecuador, is included beginning on page FS-42 in Note 17 to the Consolidated Financial Statements.

Item 4. Mine Safety Disclosures

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

Item 5. Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

The information on Chevron's common stock market prices, dividends, principal exchanges on which the stock is traded and number of stockholders of record is contained in the Quarterly Results and Stock Market Data tabulations, on page FS-20.

Chevron Corporation Issuer Purchases of Equity Securities for Quarter Ended December 31, 2015

Item 6. Selected Financial Data

The selected financial data for years 2011 through 2015 are presented on page FS-60.

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

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

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

The company's discussion of interest rate, foreign currency and commodity price market risk is contained in Management's Discussion and Analysis of Financial Condition and Results of Operations - "Financial and Derivative Instrument Market Risk," on page FS-15 and in Note 10 to the Consolidated Financial Statements, "Financial and Derivative Instruments," beginning on page FS-35.

Item 8. Financial Statements and Supplementary Data

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

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

(a) Evaluation of Disclosure Controls and Procedures The company's management has evaluated, with the participation of the Chief Executive Officer and the Chief Financial Officer, the effectiveness of the company's disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the "Exchange Act")) as of the end of the period covered by this report. Based on this evaluation, management concluded that the company's disclosure controls and procedures were effective as of December 31, 2015 .

(b) 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) and 15d-15(f). The company's management, including the Chief Executive Officer and the 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 (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on the results of this evaluation, the company's management concluded that internal control over financial reporting was effective as of December 31, 2015 .

The effectiveness of the company's internal control over financial reporting as of December 31, 2015 , has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report included on page FS-22.

(c) Changes in Internal Control Over Financial Reporting During the quarter ended December 31, 2015 , there were no changes in the company's internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the company's internal control over financial reporting.

Item 9B. Other Information

None.

Item 10. Directors, Executive Officers and Corporate Governance

Executive Officers of the Registrant at February 25, 2016

Members of the Corporation's Executive Committee are the Executive Officers of the Corporation:

The information about directors required by Item 401 (a), (d), (e) and (f) of Regulation S-K and contained under the heading "Election of Directors" in the Notice of the 2016 Annual Meeting of Stockholders and 2016 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934 (the "Exchange Act"), in connection with the company's 2016 Annual Meeting (the " 2016 Proxy Statement"), is incorporated by reference into this Annual Report on Form 10-K.

The information required by Item 405 of Regulation S-K and contained under the heading "Stock Ownership Information - Section 16(a) Beneficial Ownership Reporting Compliance" in the 2016 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

The information required by Item 406 of Regulation S-K and contained under the heading "Corporate Governance - Business Conduct and Ethics Code" in the 2016 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

The information required by Item 407(d)(4) and (5) of Regulation S-K and contained under the heading "Corporate Governance - Board Committees" in the 2016 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

Item 11. Executive Compensation

The information required by Item 402 of Regulation S-K and contained under the headings "Executive Compensation" and "Director Compensation" in the 2016 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

The information required by Item 407(e)(4) of Regulation S-K and contained under the heading "Corporate Governance - Board Committees" in the 2016 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

The information required by Item 407(e)(5) of Regulation S-K and contained under the heading "Corporate Governance - Management Compensation Committee Report" in the 2016 Proxy Statement is incorporated herein by reference into this Annual Report on Form 10-K. Pursuant to the rules and regulations of the SEC under the Exchange Act, the information under such caption incorporated by reference from the 2016 Proxy Statement shall not be deemed to be "soliciting material," or to be "filed" with the Commission, or subject to Regulation 14A or 14C or the liabilities of Section 18 of the Exchange Act nor shall it be deemed incorporated by reference into any filing under the Securities Act of 1933.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information required by Item 403 of Regulation S-K and contained under the heading "Stock Ownership Information - Security Ownership of Certain Beneficial Owners and Management" in the 2016 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

The information required by Item 201(d) of Regulation S-K and contained under the heading "Equity Compensation Plan Information" in the 2016 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information required by Item 404 of Regulation S-K and contained under the heading "Corporate Governance - Related Person Transactions" in the 2016 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

The information required by Item 407(a) of Regulation S-K and contained under the heading "Corporate Governance - Director Independence" in the 2016 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

Item 14. Principal Accounting Fees and Services

The information required by Item 9(e) of Schedule 14A and contained under the heading "Board Proposal to Ratify PricewaterhouseCoopers LLP as Independent Auditor for 2016" in the 2016 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

Item 15. Exhibits, Financial Statement Schedules

(1) Financial Statements:

(2) Financial Statement Schedules:

Included below is Schedule II - Valuation and Qualifying Accounts.

(3) Exhibits:

The Exhibit Index on pages E-1 through E-2 lists the exhibits that are filed as part of this report.

Schedule II - Valuation and Qualifying Accounts

* See also Note 18 to the Consolidated Financial Statements, beginning on page FS-45.

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 25th day of February, 2016 .

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on the 25th day of February, 2016 .

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