Edgar Filing: CHEVRON CORP

10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

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

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2015

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

SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 001-00368

Chevron Corporation

(Exact name of registrant as specified in its charter)



Delaware	94-0890210	6001 Bollinger Canyon Road, San Ramon, California 94583-2324
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)	(Address of principal executive offices) (Zip Code)

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

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



Title of Each Class		Name of Each Exchange on Which Registered
Common stock, par value $.75 per share		New York Stock Exchange, Inc.

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

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

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

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

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

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.



Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o (Do not check if a smaller reporting company)	Smaller reporting company o

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

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

THIS PAGE INTENTIONALLY LEFT BLANK

TABLE OF CONTENTS



ITEM		PAGE
PART I
1.	Business	3
	General Development of Business	3
	Description of Business and Properties	4
	Upstream	4
	Downstream	18
	Other Businesses	20
1A.	Risk Factors	21
1B.	Unresolved Staff Comments	23
2.	Properties	23
3.	Legal Proceedings	23
4.	Mine Safety Disclosures	24
PART II
5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	24
6.	Selected Financial Data	24
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
7A.	Quantitative and Qualitative Disclosures About Market Risk	24
8.	Financial Statements and Supplementary Data	24
9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	24
9A.	Controls and Procedures	25
9B.	Other Information	25
PART III
10.	Directors, Executive Officers and Corporate Governance	26
11.	Executive Compensation	27
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	27
13.	Certain Relationships and Related Transactions, and Director Independence	27
14.	Principal Accounting Fees and Services	27
PART IV
15.	Exhibits, Financial Statement Schedules	28
	Schedule II — Valuation and Qualifying Accounts	28
	Signatures	29



EX-12.1	EX-31.1
EX-21.1	EX-31.2
EX-23.1	EX-32.1
EX-24.1	EX-32.2
EX-24.2	EX-95
EX-24.3	EX-99.1
EX-24.4	EX-101 INSTANCE DOCUMENT
EX-24.5	EX-101 SCHEMA DOCUMENT
EX-24.6	EX-101 CALCULATION LINKBASE DOCUMENT
EX-24.7	EX-101 LABELS LINKBASE DOCUMENT
EX-24.8	EX-101 PRESENTATION LINKBASE DOCUMENT
EX-24.9	EX-101 DEFINITION LINKBASE DOCUMENT
EX-24.10
EX-24.11

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.

PART I

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.

________________________________________________________

^* Incorporated in Delaware in 1926 as Standard Oil Company of California, the company adopted the name Chevron Corporation in 1984 and ChevronTexaco Corporation in 2001. In 2005, ChevronTexaco Corporation changed its name to Chevron Corporation. As used in this report, the term “Chevron” and such terms as “the company,” “the corporation,” “our,” “we” and “us” may refer to Chevron Corporation, one or more of its consolidated subsidiaries, or all of them taken as a whole, but unless stated otherwise they do not include “affiliates” of Chevron — i.e., those companies accounted for by the equity method (generally owned 50 percent or less) or investments accounted for by the cost method. All of these terms are used for convenience only and are not intended as a precise description of any of the separate companies, each of which manages its own affairs.

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:



	At December 31
	2015	2014	2013
Liquids — Millions of barrels
Consolidated Companies	4,262	4,285	4,303
Affiliated Companies	2,000	1,964	2,042
Total Liquids	6,262	6,249	6,345
Natural Gas — Billions of cubic feet
Consolidated Companies	25,946	25,707	25,670
Affiliated Companies	3,491	3,409	3,476
Total Natural Gas	29,437	29,116	29,146
Oil-Equivalent — Millions of barrels^*
Consolidated Companies	8,586	8,570	8,582
Affiliated Companies	2,582	2,532	2,621
Total Oil-Equivalent	11,168	11,102	11,203

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

________________________________________________________

As used in this report, the term “project” may describe new upstream development activity, individual phases in a multiphase development, maintenance activities, certain existing assets, new investments in downstream and chemicals capacity, investments in emerging and sustainable energy activities, and certain other activities. All of these terms are used for convenience only and are not intended as a precise description of the term “project” as it relates to any specific governmental law or regulation.

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.



			Components of Oil-Equivalent
	Oil-Equivalent		Liquids		Natural Gas
Thousands of barrels per day (MBPD)	(MBPD)¹		(MBPD)		(MMCFPD)
Millions of cubic feet per day (MMCFPD)	2015	2014	2015	2014	2015	2014
United States	720	664	501	456	1,310	1,250
Other Americas
Argentina	27	25	21	21	36	23
Brazil	18	21	17	20	5	6
Canada²	69	69	67	67	14	10
Colombia	27	31	—	—	161	186
Trinidad and Tobago	19	19	—	—	116	112
Total Other Americas	160	165	105	108	332	337
Africa
Angola	119	121	110	113	52	51
Chad³	—	8	—	8	—	2
Democratic Republic of the Congo	3	3	2	2	1	1
Nigeria	270	286	230	246	246	236
Republic of Congo	20	16	18	14	11	11
Total Africa	412	434	360	383	310	301
Asia
Azerbaijan	34	28	32	26	12	12
Bangladesh	123	109	3	2	720	643
China	24	16	24	16	—	—
Indonesia	207	185	176	149	185	214
Kazakhstan	56	53	34	31	138	126
Myanmar	20	16	—	—	117	99
Partitioned Zone⁴	28	81	27	78	5	18
Philippines	23	23	3	3	122	118
Thailand	238	238	66	63	1,033	1,046
Total Asia	753	749	365	368	2,332	2,276
Australia/Oceania
Australia	94	97	21	23	439	442
Total Australia/Oceania	94	97	21	23	439	442
Europe
Denmark	24	25	16	17	50	51
Netherlands³	—	7	—	2	—	34
Norway³	—	1	—	1	—	—
United Kingdom	59	47	40	32	115	88
Total Europe	83	80	56	52	165	173
Total Consolidated Companies	2,222	2,189	1,408	1,390	4,888	4,779
Affiliates^2,5	400	382	336	319	381	388
Total Including Affiliates⁶	2,622	2,571	1,744	1,709	5,269	5,167

¹Oil-equivalent conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of oil.
² Includes synthetic oil: Canada, net	47	43	47	43	—	—
Venezuelan affiliate, net	29	31	29	31	—	—
³ Producing fields in Chad, the Netherlands and Norway were sold in 2014.
⁴ Located between Saudi Arabia and Kuwait.
⁵Volumes represent Chevron’s share of production by affiliates, including Tengizchevroil in Kazakhstan; Petroboscan, Petroindependiente and Petropiar in Venezuela; and Angola LNG in Angola.
⁶ Volumes include natural gas consumed in operations of 496 million and 523million cubic feet per day in 2015 and 2014, respectively. Total “as sold” natural gas volumes were 4,773 million and 4,644 million cubic feet per day for 2015 and 2014, respectively.

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:



	At December 31, 2015
	Productive Oil Wells*		Productive Gas Wells *
	Gross	Net	Gross	Net
United States	50,808	33,457	13,528	7,186
Other Americas	1,122	734	87	49
Africa	1,853	704	17	7
Asia	14,676	12,712	3,654	2,172
Australia/Oceania	571	319	67	11
Europe	322	69	161	34
Total Consolidated Companies	69,352	47,995	17,514	9,459
Affiliates	1,411	490	7	2
Total Including Affiliates	70,763	48,485	17,521	9,461
Multiple completion wells included above	981	672	371	280
* Gross wells represent the total number of wells in which Chevron has an ownership interest. Net wells represent the sum of Chevron's ownership interest in gross wells.

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:



	Undeveloped²		Developed		Developed and Undeveloped
Thousands of acres¹	Gross	Net	Gross	Net	Gross	Net
United States	5,088	4,153	7,249	4,732	12,337	8,885
Other Americas	26,509	14,843	1,398	389	27,907	15,232
Africa	19,723	9,727	2,326	946	22,049	10,673
Asia	29,137	14,530	1,646	924	30,783	15,454
Australia/Oceania	23,357	15,601	1,843	676	25,200	16,277
Europe	2,918	2,445	407	53	3,325	2,498
Total Consolidated Companies	106,732	61,299	14,869	7,720	121,601	69,019
Affiliates	531	229	272	106	803	335
Total Including Affiliates	107,263	61,528	15,141	7,826	122,404	69,354
¹ Gross acres represent the total number of acres in which Chevron has an ownership interest. Net acres represent the sum of Chevron's ownership interest in gross acres.
²The gross undeveloped acres that will expire in 2016, 2017 and 2018 if production is not established by certain required dates are 8,217, 412 and 1,650, respectively.

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.



	Wells Drilling*		Net Wells Completed
	at 12/31/15		2015		2014		2013
	Gross	Net	Prod.	Dry	Prod.	Dry	Prod.	Dry
United States	131	71	873	3	1,085	8	1,101	4
Other Americas	40	17	99	—	81	—	127	—
Africa	22	4	9	—	9	—	20	1
Asia	24	10	828	5	1,025	4	535	5
Australia/Oceania	4	3	4	—	9	—	—	—
Europe	3	—	2	—	2	—	3	—
Total Consolidated Companies	224	105	1,815	8	2,211	12	1,786	10
Affiliates	36	15	26	—	25	1	25	—
Total Including Affiliates	260	120	1,841	8	2,236	13	1,811	10
* Gross wells represent the total number of wells in which Chevron has an ownership interest. Net wells represent the sum of Chevron's ownership interest in gross wells.

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.



	Wells Drilling*		Net Wells Completed
	at 12/31/15		2015		2014		2013
	Gross	Net	Prod.	Dry	Prod.	Dry	Prod.	Dry
United States	3	2	16	4	20	12	17	2
Other Americas	2	2	5	1	3	—	12	2
Africa	3	1	3	—	1	2	—	—
Asia	—	—	5	1	7	2	13	4
Australia/Oceania	—	—	1	4	3	—	3	—
Europe	—	—	3	—	3	—	2	2
Total Consolidated Companies	8	5	33	10	37	16	47	10
Affiliates	—	—	—	—	—	—	—	—
Total Including Affiliates	8	5	33	10	37	16	47	10
* Gross wells represent the total number of wells in which Chevron has an ownership interest. Net wells represent the sum of Chevron's ownership interest in gross wells.

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.

The 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



Capacities and inputs in thousands of barrels per day		December 31, 2015		Refinery Inputs
Locations		Number	Operable Capacity	2015	2014	2013
Pascagoula	Mississippi	1	330	322	329	304
El Segundo	California	1	269	258	221	235
Richmond	California	1	257	245	229	153
Kapolei	Hawaii	1	54	47	47	39
Salt Lake City	Utah	1	53	52	45	43
Total Consolidated Companies — United States		5	963	924	871	774
Map Ta Phut¹	Thailand	1	165	164	141	161
Cape Town²	South Africa	1	110	69	72	78
Burnaby, B.C.	Canada	1	55	46	49	42
Total Consolidated Companies — International		3	330	279	262	281
Affiliates³	Various Locations	3	542	499	557	583
Total Including Affiliates — International		6	872	778	819	864
Total Including Affiliates — Worldwide		11	1,835	1,702	1,690	1,638


¹	Chevron holds a controlling interest in the Star Petroleum Refining Public Company Limited. Chevron's ownership in this refinery was reduced to 60.6 percent following the December 2015 new share issuance and listing by Star Petroleum Refining Public Company Limited in Thailand.


²	Chevron holds a 75 percent controlling interest in the shares issued by Chevron South Africa (Pty) Limited, which owns the Cape Town Refinery. A consortium of South African partners, along with the employees of Chevron South Africa (Pty) Limited, own the remaining 25 percent.


³	In 2015, the company sold its interests in affiliates in Australia and New Zealand, which included operable capacities of 55,000 and 12,000 barrels per day, respectively.

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



Thousands of barrels per day	2015	2014	2013
United States
Gasoline	621	615	613
Jet Fuel	232	222	215
Gas Oil and Kerosene	215	217	195
Residual Fuel Oil	59	63	69
Other Petroleum Products¹	101	93	90
Total United States	1,228	1,210	1,182
International²
Gasoline	389	403	398
Jet Fuel	271	249	245
Gas Oil and Kerosene	478	498	510
Residual Fuel Oil	159	162	179
Other Petroleum Products¹	210	189	197
Total International	1,507	1,501	1,529
Total Worldwide²	2,735	2,711	2,711
¹ Principally naphtha, lubricants, asphalt and coke.
² Includes share of affiliates’ sales:	420	475	471

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.

PART II

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



	Total Number	Average		Total Number of Shares	Maximum Number of Shares
	of Shares	Price Paid		Purchased as Part of Publicly	That May Yet be Purchased
Period	Purchased^1,2	per Share		Announced Program	Under the Program²
Oct. 1 – Oct. 31, 2015	1,341		$78.31	—	—
Nov. 1 – Nov. 30, 2015	—	—		—	—
Dec. 1 – Dec. 31, 2015	3,201		$92.49	—	—
Total Oct. 1 – Dec. 31, 2015	4,542		$88.30	—	—


¹	Includes common shares repurchased from company employees for required personal income tax withholdings on the exercise of the stock options and shares delivered or attested to in satisfaction of the exercise price by holders of the employee stock options. The options were issued to and exercised by management under Chevron long-term incentive plans.

In July 2010, the Board of Directors approved an ongoing share repurchase program with no set term or monetary limits, under which common shares would be acquired by the company through open market purchases or in negotiated transactions at prevailing prices, as permitted by securities laws and other legal requirements and subject to market conditions and other factors. From inception of the program through 2014, the company had purchased 180,886,291 shares under this program (some pursuant to a Rule 10b5-1 plan and some pursuant to accelerated share repurchase plans) for $20 billion at an average price of approximately $111 per share. The company did not acquire any shares under the program in 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.

PART III

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:



Name	Age	Current and Prior Positions (up to five years)	Current Areas of Responsibility
J.S. Watson	59	Chairman of the Board and Chief Executive Officer (since 2010)	Chairman of the Board and Chief Executive Officer
J.W. Johnson	56	Executive Vice President, Upstream (since 2015) Senior Vice President, Upstream (2014) President, Europe, Eurasia and Middle East Exploration and Production (2011 through 2013) Managing Director, Eurasia Business Unit (2008 to 2011)	Worldwide Exploration and Production Activities
P.R. Breber	51	Executive Vice President, Downstream (since 2016) Corporate Vice President and President, Gas and Midstream (2014 through 2015) Managing Director, Asia South Business Unit (2012 through 2013) Deputy Managing Director, Asia South Business Unit (2011) Vice President and Treasurer (2009 to 2011)	Worldwide Refining, Marketing and Lubricants; Chemicals
M.K. Wirth	55	Executive Vice President, Midstream and Development (since 2016) Executive Vice President, Downstream (2006 through 2015)	Corporate Strategy; Corporate Business Development; Worldwide Natural Gas Commercialization; Supply and Trading Activities; Shipping; Pipeline; Power and Energy Management
J.C. Geagea	56	Executive Vice President, Technology, Projects and Services (since 2015) Senior Vice President, Technology, Projects and Services (2014) Corporate Vice President and President, Gas and Midstream (2012 through 2013) Managing Director, Asia South Business Unit (2008 through 2011)	Technology; Health, Environment and Safety; Project Resources Company; Procurement
P.E. Yarrington	59	Vice President and Chief Financial Officer (since 2009)	Finance
R.H. Pate	53	Vice President and General Counsel (since 2009)	Law, Governance and Compliance

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.

PART IV

Item 15. Exhibits, Financial Statement Schedules


(a)	The following documents are filed as part of this report:

(1) Financial Statements:



	Page(s)
Report of Independent Registered Public Accounting Firm — PricewaterhouseCoopers LLP	FS--22
Consolidated Statement of Income for the three years ended December 31, 2015	FS--23
Consolidated Statement of Comprehensive Income for the three years ended December 31, 2015	FS--24
Consolidated Balance Sheet at December 31, 2015 and 2014	FS--25
Consolidated Statement of Cash Flows for the three years ended December 31, 2015	FS--26
Consolidated Statement of Equity for the three years ended December 31, 2015	FS--27
Notes to the Consolidated Financial Statements	FS-28 to FS-60

(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



	Year ended December 31
Millions of Dollars	2015			2014			2013
Employee Termination Benefits
Balance at January 1	$	49		$	14		$	30
Additions (reductions) charged to expense	342			53			(6		)
Payments	(83		)	(18		)	(10		)
Balance at December 31	$	308		$	49		$	14
Allowance for Doubtful Accounts
Balance at January 1	$	194		$	95		$	155
Additions to expense	251			119			1
Bad debt write-offs	(16		)	(20		)	(61		)
Balance at December 31	$	429		$	194		$	95
Deferred Income Tax Valuation Allowance^*
Balance at January 1	$	16,292		$	17,171		$	15,443
Additions to deferred income tax expense	1,440			1,192			2,665
Reduction of deferred income tax expense	(2,320		)	(2,071		)	(937		)
Balance at December 31	$	15,412		$	16,292		$	17,171

^*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.



	Chevron Corporation
By	/s/ JOHN S. WATSON
	John S. Watson, Chairman of the Board and Chief Executive Officer

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

Principal Executive Officer

(and Director)

/s/ JOHN S. WATSON
John S. Watson, Chairman of the
Board and Chief Executive Officer

Principal Financial Officer

/s/ PATRICIA E. YARRINGTON
Patricia E. Yarrington, Vice President
and Chief Financial Officer

Principal Accounting Officer

/s/ JEANETTE L. OURADA
Jeanette L. Ourada, Vice President
and Comptroller

^*By: /s/ MARY A. FRANCIS
Mary A. Francis,
Attorney-in-Fact

Directors

ALEXANDER B. CUMMINGS, JR.^*
Alexander B. Cummings, Jr.

LINNET F. DEILY^*
Linnet F. Deily

ROBERT E. DENHAM^*
Robert E. Denham

ALICE P. GAST^*
Alice P. Gast

ENRIQUE HERNANDEZ, JR.^*
Enrique Hernandez, Jr.

JON M. HUNTSMAN, JR.^*
Jon M. Huntsman, Jr.

CHARLES W. MOORMAN IV^*
Charles W. Moorman IV

JOHN G. STUMPF^*

John G. Stumpf

RONALD D. SUGAR^*

Ronald D. Sugar

INGE G. THULIN^*
Inge G. Thulin

CARL WARE^*
Carl Ware

THIS PAGE INTENTIONALLY LEFT BLANK

Financial Table of Contents




	FS-2

	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Key Financial Results FS-2
	Earnings by Major Operating Area FS-2
	Business Environment and Outlook FS-2
	Operating Developments FS-5
	Results of Operations FS-6
	Consolidated Statement of Income FS-9
	Selected Operating Data FS-11
	Liquidity and Capital Resources FS-12
	Financial Ratios FS-14
	Off-Balance-Sheet Arrangements, Contractual Obligations, Guarantees and Other Contingencies FS-14
	Financial and Derivative Instrument Market Risk FS-15
	Transactions With Related Parties FS-15
	Litigation and Other Contingencies FS-16
	Environmental Matters FS-16
	Critical Accounting Estimates and Assumptions FS-17
	New Accounting Standards FS-20
	Quarterly Results and Stock Market Data FS-20


	FS-21
	FS-21

	Consolidated Financial Statements
	Reports of Management FS-21
	Report of Independent Registered Public Accounting Firm FS-22
	Consolidated Statement of Income FS-23
	Consolidated Statement of Comprehensive Income FS-24
	Consolidated Balance Sheet FS-25
	Consolidated Statement of Cash Flows FS-26
	Consolidated Statement of Equity FS-27




FS-28

Notes to the Consolidated Financial Statements
Note 1	Summary of Significant Accounting Policies FS-28
Note 2	Changes in Accumulated Other Comprehensive Losses FS-30
Note 3	Noncontrolling Interests FS-30
Note 4	Information Relating to the Consolidated
	Statement of Cash Flows FS-31
Note 5	New Accounting Standards FS-32
Note 6	Lease Commitments FS-32
Note 7	Summarized Financial Data – Chevron U.S.A. Inc. FS-33
Note 8	Summarized Financial Data – Tengizchevroil LLP FS-34
Note 9	Fair Value Measurements FS-34
Note 10	Financial and Derivative Instruments FS-35
Note 11	Assets Held for Sale FS-36
Note 12	Equity FS-37
Note 13	Earnings Per Share FS-37
Note 14	Operating Segments and Geographic Data FS-37
Note 15	Investments and Advances FS-40
Note 16	Properties, Plant and Equipment FS-41
Note 17	Litigation FS-42
Note 18	Taxes FS-45
Note 19	Short-Term Debt FS-48
Note 20	Long-Term Debt FS-49
Note 21	Accounting for Suspended Exploratory Wells FS-49
Note 22	Stock Options and Other Share-Based Compensation FS-50
Note 23	Employee Benefit Plans FS-51
Note 24	Other Contingencies and Commitments FS-57
Note 25	Asset Retirement Obligations FS-59
Note 26	Restructuring and Reorganization Costs FS-59
Note 27	Other Financial Information FS-59


Five-Year Financial Summary FS-60
Supplemental Information on Oil and Gas Producing Activities FS-61

FS--1

Management's Discussion and Analysis of Financial Condition and Results of Operations

Key Financial Results



Millions of dollars, except per-share amounts	2015			2014			2013
Net Income Attributable to Chevron Corporation	$	4,587		$	19,241		$	21,423
Per Share Amounts:
Net Income Attributable to Chevron Corporation
– Basic	$	2.46		$	10.21		$	11.18
– Diluted	$	2.45		$	10.14		$	11.09
Dividends	$	4.28		$	4.21		$	3.90
Sales and Other Operating Revenues	$	129,925		$	200,494		$	220,156
Return on:
Capital Employed	2.5		%	10.9		%	13.5		%
Stockholders’ Equity	3.0		%	12.7		%	15.0		%
Earnings by Major Operating Area
Millions of dollars	2015			2014			2013
Upstream
United States	$	(4,055	)	$	3,327		$	4,044
International	2,094			13,566			16,765
Total Upstream	(1,961		)	16,893			20,809
Downstream
United States	3,182			2,637			787
International	4,419			1,699			1,450
Total Downstream	7,601			4,336			2,237
All Other	(1,053		)	(1,988		)	(1,623		)
Net Income Attributable to Chevron Corporation^1,2	$	4,587		$	19,241		$	21,423
¹ Includes foreign currency effects:	$	769		$	487		$	474
²Income net of tax, also referred to as “earnings” in the discussions that follow.

Refer to the “Results of Operations” section beginning on page FS-6 for a discussion of financial results by major operating area for the three years ended December 31, 2015.

Business Environment and Outlook

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

Earnings of the company depend mostly on the profitability of its upstream business segment. The biggest factor affecting the results of operations for the upstream segment is the price of crude oil. The price of crude oil has fallen significantly since mid-year 2014, reflecting persistently high global crude oil inventories and production. The downturn in the price of crude oil has impacted, and, depending upon its duration, will continue to significantly impact the company's results of operations, cash flows, leverage, capital and exploratory investment program and production outlook. The company is responding with reductions in operating expenses, including employee reductions, reductions in capital and exploratory expenditures in 2016 and future periods, and increased asset sales. The company anticipates that crude oil prices will increase in the future, as continued growth in demand and a slowing in supply growth should bring global markets into balance; however, the timing of any such increase is unknown. In the company's downstream business, crude oil is the largest cost component of refined products.

Refer to the "Cautionary Statement Relevant to Forward-Looking Information" on page 2 and to "Risk Factors" in Part I, Item 1A, on pages 21 through 23 for a discussion of some of the inherent risks that could materially impact the company's results of operations or financial condition.

The company continually evaluates opportunities to dispose of assets that are not expected to provide sufficient long-term value or to acquire assets or operations complementary to its asset base to help augment the company’s financial performance and growth. Refer to the “Results of Operations” section beginning on page FS-6 for discussions of net gains on asset sales during 2015. Asset dispositions and restructurings may also occur in future periods and could result in significant gains or losses.

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

FS--2

Management's Discussion and Analysis of Financial Condition and Results of Operations

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

Upstream Earnings for the upstream segment are closely aligned with industry prices for crude oil and natural gas. Crude oil and natural gas prices are subject to external factors over which the company has no control, including product demand connected with global economic conditions, industry inventory levels, technology advancements, production quotas or other actions imposed by the Organization of Petroleum Exporting Countries (OPEC), actions of regulators, weather-related damage and disruptions, competing fuel prices, and regional supply interruptions or fears thereof that may be caused by military conflicts, civil unrest or political uncertainty. Any of these factors could also inhibit the company’s production capacity in an affected region. The company closely monitors developments in the countries in which it operates and holds investments, and seeks to manage risks in operating its facilities and businesses. The longer-term trend in earnings for the upstream segment is also a function of other factors, including the company’s ability to find or acquire and efficiently produce crude oil and natural gas, changes in fiscal terms of contracts, and changes in tax laws and regulations.

The company continues to actively manage its schedule of work, contracting, procurement and supply-chain activities to effectively manage costs. However, price levels for capital and exploratory costs and operating expenses associated with the production of crude oil and natural gas can be subject to external factors beyond the company’s control including, among other things, the general level of inflation, commodity prices and prices charged by the industry’s material and service providers, which can be affected by the volatility of the industry’s own supply-and-demand conditions for such materials and services. In recent years, Chevron and the oil and gas industry generally experienced an increase in certain costs that exceeded the general trend of inflation in many areas of the world. As a result of the decline in prices of crude oil and other commodities since mid-2014, these cost pressures have softened. Capital and exploratory expenditures and operating expenses can also be affected by damage to production facilities caused by severe weather or civil unrest, delays in construction, or other factors.

The chart above shows the trend in benchmark prices for Brent crude oil, West Texas Intermediate (WTI) crude oil and U.S. Henry Hub natural gas. The Brent price averaged $52 per barrel for the full-year 2015, compared to $99 in 2014. As of mid-February 2016, the Brent price was $31 per barrel. The majority of the company’s equity crude production is priced based on the Brent benchmark. Prices firmed in the first half of 2015, but declined in the remainder of the year amid persistently high global crude oil inventories and production.

The WTI price averaged $49 per barrel for the full-year 2015, compared to $93 in 2014. As of mid-February 2016, the WTI price was $29 per barrel. WTI traded at a discount to Brent throughout 2015 due to high inventories and excess crude supply in the U.S. market. With the lifting of the U.S. crude oil export ban in December 2015, the spread between WTI and Brent narrowed substantially and WTI traded around parity into February 2016.

A differential in crude oil prices exists between high-quality (high-gravity, low-sulfur) crudes and those of lower quality (low-gravity, high-sulfur). The amount of the differential in any period is associated with the relative supply/demand balances for each crude type, which are functions of the capacity of refineries that are able to process each as feedstock into high-value light products (motor gasoline, jet fuel, aviation gasoline and diesel fuel). In second-half 2015, the differential expanded in North America as Canadian heavy crude production recovered from earlier planned and unplanned outages, while light sweet crude prices in the U.S. were supported by reductions in the rig count and slowing domestic production growth. Outside of North

FS--3

Management's Discussion and Analysis of Financial Condition and Results of Operations

America, high refinery runs in Europe and Asia supported pricing for light sweet crude from the Atlantic Basin, while increased output from Iraq and other Middle East producers pressured values of heavier, more sour crudes.

Chevron produces or shares in the production of heavy crude oil in California, Indonesia, the Partitioned Zone between Saudi Arabia and Kuwait, Venezuela and in certain fields in Angola, China and the United Kingdom sector of the North Sea. (See page FS-11 for the company’s average U.S. and international crude oil realizations.)

In contrast to price movements in the global market for crude oil, price changes for natural gas in many regional markets are more closely aligned with supply-and-demand conditions in those markets. Fluctuations in the price of natural gas in the United States are closely associated with customer demand relative to the volumes produced and stored in North America. In the United States, prices at Henry Hub averaged $2.62 per thousand cubic feet (MCF) during 2015, compared with $4.28 during 2014. As of mid-February 2016, the Henry Hub spot price was $1.92 per MCF.

Outside the United States, price changes for natural gas depend on a wide range of supply, demand and regulatory circumstances. Chevron sells natural gas into the domestic pipeline market in most locations. In some locations, Chevron is investing in long-term projects to install infrastructure to produce and liquefy natural gas for transport by tanker to other markets. The company's long-term contract prices for liquefied natural gas (LNG) are typically linked to crude oil prices. Approximately 85 percent of the equity LNG offtake from the operated Australian LNG projects is targeted to be sold into binding long-term contracts, with the remainder to be sold in the Asian spot LNG market. The Asian spot market reflects the supply and demand for LNG in the Pacific Basin and is not directly linked to crude oil prices. International natural gas realizations averaged $4.53 per MCF during 2015, compared with $5.78 per MCF during 2014. (See page FS-11 for the company’s average natural gas realizations for the U.S. and international regions.)

The company’s worldwide net oil-equivalent production in 2015 averaged 2.622 million barrels per day. About one-fifth of the company’s net oil-equivalent production in 2015 occurred in the OPEC-member countries of Angola, Nigeria, Venezuela and the Partitioned Zone between Saudi Arabia and Kuwait. OPEC quotas had no effect on the company’s net crude oil production in 2015 or 2014. At their December 2015 meeting, members of OPEC did not agree on a target production level, and in January 2016 western sanctions on Iran were lifted. As such, OPEC output is now considered likely to increase from recent levels of approximately 31.5 million barrels per day as Iranian production and exports recover.

The company estimates that net oil-equivalent production in 2016 will be flat to 4 percent growth compared to 2015. This estimate is subject to many factors and uncertainties, including the duration of the low price environment that began in second-half 2014; quotas or other actions that may be imposed by OPEC; price effects on entitlement volumes; changes in fiscal terms or restrictions on the scope of company operations; delays in construction, start-up or ramp-up of projects; fluctuations in demand for natural gas in various markets; weather conditions that may shut in production; civil unrest; changing geopolitics; delays in completion of maintenance turnarounds; greater-than-expected declines in production from mature fields; or other disruptions

FS--4

Management's Discussion and Analysis of Financial Condition and Results of Operations

to operations. The outlook for future production levels is also affected by the size and number of economic investment opportunities and, for new, large-scale projects, the time lag between initial exploration and the beginning of production. Investments in upstream projects generally begin well in advance of the start of the associated crude oil and natural gas production. A significant majority of Chevron’s upstream investment is made outside the United States.

In the Partitioned Zone between Saudi Arabia and Kuwait, production was shut-in beginning in May 2015 as a result of difficulties in securing work and equipment permits. Net oil-equivalent production in the Partitioned Zone in 2014 was 81,000 barrels per day. During 2015, net oil-equivalent production averaged 28,000 barrels per day. 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 financial effects from the loss of production in 2015 were not significant and are not expected to be significant in 2016.

Net proved reserves for consolidated companies and affiliated companies totaled 11.2 billion barrels of oil-equivalent at year-end 2015, an increase of 1 percent from year-end 2014. The reserve replacement ratio in 2015 was 107 percent. Refer to Table V beginning on page FS-65 for a tabulation of the company’s proved net oil and gas reserves by geographic area, at the beginning of 2013 and each year-end from 2013 through 2015, and an accompanying discussion of major changes to proved reserves by geographic area for the three-year period ending December 31, 2015.

Refer to the “Results of Operations” section on pages FS-6 through FS-8 for additional discussion of the company’s upstream business.

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

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

The company’s most significant marketing areas are the West Coast of North America, the U.S. Gulf Coast, Asia and southern Africa. Chevron operates or has significant ownership interests in refineries in each of these areas.

Refer to the “Results of Operations” section on pages FS-6 through FS-8 for additional discussion of the company’s downstream operations.

All Other consists of worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities and technology companies.

Operating Developments

Key operating developments and other events during 2015 and early 2016 included the following:

Upstream

Angola-Republic of Congo Joint Development Area Achieved first production from the Lianzi Project.

Australia Progressed LNG Train 1 commissioning and start-up activities for the Gorgon Project, with first cargo lifting expected in March 2016. All Train 2 modules are installed, and all remaining Train 3 modules were delivered as of January 2016.

Progressed construction of the Wheatstone Project. Major milestones reached include the installation of the offshore platform and topsides, and all of the subsea pipelines and structures, along with the delivery of all LNG Train 1 and common modules.

Announced a natural gas discovery, Isosceles, in the Carnarvon Basin in 50 percent-owned Block WA-392-P.

Bangladesh Achieved first liquids from the Bibiyana Expansion Liquid Recovery Unit.

China Achieved first production from the Chuandongbei Project in early 2016.

FS--5

Management's Discussion and Analysis of Financial Condition and Results of Operations

Republic of Congo Announced start of production from the first phase of the Moho Nord Project.

United States Announced a successful appraisal well at the Anchor prospect in the deepwater Gulf of Mexico.

Downstream

Australia Completed the sale of the company’s 50 percent interest in Caltex Australia Limited.

New Zealand Completed the sale of the company’s interest in The New Zealand Refining Company Limited and reached agreement to sell the company’s marketing operations.

Other

Common Stock Dividends The 2015 annual dividend was $4.28 per share, making 2015 the 28th consecutive year that the company increased its annual dividend payout.

Results of Operations

The following section presents the results of operations and variances on an after-tax basis for the company’s business segments – Upstream and Downstream – as well as for “All Other.” Earnings are also presented for the U.S. and international geographic areas of the Upstream and Downstream business segments. Refer to Note 14, beginning on page FS-37, for a discussion of the company’s “reportable segments.” This section should also be read in conjunction with the discussion in “Business Environment and Outlook” on pages FS-2 through FS-5.

U.S. Upstream



Millions of dollars	2015			2014		2013
Earnings	$	(4,055	)	$	3,327	$	4,044

U.S. upstream operations incurred a loss of $4.06 billion in 2015 compared to earnings of $3.33 billion from 2014. The decrease was primarily due to lower crude oil and natural gas realizations of $4.86 billion and $570 million, respectively, higher depreciation expenses of $2.19 billion and higher exploration expenses of $650 million. The increase in depreciation and exploration expenses was primarily due to impairments and project cancellations. Lower gains on asset sales also contributed to the decrease with current year gains of $110 million compared with $700 million in 2014. Partially offsetting these effects were higher crude oil production of $900 million and lower operating expenses of $450 million.

U.S. upstream earnings of $3.33 billion in 2014 decreased $717 million from 2013, primarily due to lower crude oil prices of $950 million. Higher depreciation expenses of $440 million and higher operating expenses of $210 million also contributed to the decline. Partially offsetting the decrease were gains on asset sales of $700 million in 2014 compared with $60 million in 2013, higher natural gas realizations of $150 million and higher crude oil production of $100 million.

FS--6

Management's Discussion and Analysis of Financial Condition and Results of Operations

The company’s average realization for U.S. crude oil and natural gas liquids in 2015 was $42.70 per barrel, compared with $84.13 in 2014 and $93.46 in 2013. The average natural gas realization was $1.92 per thousand cubic feet in 2015, compared with $3.90 in 2014 and $3.37 in 2013.

Net oil-equivalent production in 2015 averaged 720,000 barrels per day, up 8 percent from 2014 and 10 percent from 2013. Between 2015 and 2014, production increases due to project ramp-ups in the Gulf of Mexico and the Permian Basin in Texas and New Mexico were partially offset by the effect of asset sales and normal field declines. Between 2014 and 2013, production increases in the Permian Basin in Texas and New Mexico and the Marcellus Shale in western Pennsylvania were partially offset by normal field declines.

The net liquids component of oil-equivalent production for 2015 averaged 501,000 barrels per day, up 10 percent from 2014 and 12 percent from 2013. Net natural gas production averaged about 1.3 billion cubic feet per day in 2015, up 5 percent from 2014 and 2013. Refer to the “Selected Operating Data” table on page FS-11 for a three-year comparison of production volumes in the United States.

International Upstream



Millions of dollars	2015		2014		2013
Earnings^*	$	2,094	$	13,566	$	16,765

^*Includes foreign currency effects:	$	725	$	597	$	559

International upstream earnings were $2.09 billion in 2015 compared with $13.57 billion in 2014. The decrease between periods was primarily due to lower crude oil and natural gas realizations of $10.57 billion and $880 million, respectively, and higher depreciation expenses of $1.11 billion, primarily reflecting impairments. Lower gains on asset sales also contributed to the decrease with current year gains of $370 million compared with $1.10 billion in 2014. Partially offsetting the decrease were higher crude oil sales volumes of $590 million and lower operating expenses of $510 million. Foreign currency effects increased earnings by $725 million in 2015, compared with an increase of $597 million a year earlier.

International upstream earnings were $13.57 billion in 2014 compared with $16.77 billion in 2013. The decrease between periods was primarily due to lower crude oil prices and sales volumes of $1.97 billion and $400 million, respectively. Also contributing to the decrease were higher depreciation expenses of $1.02 billion, mainly related to impairments and other asset write-offs, and higher operating and tax expenses of $340 million and $310 million, respectively. Partially offsetting these items were gains on asset sales of $1.10 billion in 2014, compared with $140 million in 2013. Foreign currency effects increased earnings by $597 million in 2014, compared with a decrease of $559 million a year earlier.

The company’s average realization for international crude oil and natural gas liquids in 2015 was $46.52 per barrel, compared with $90.42 in 2014 and $100.26 in 2013. The average natural gas realization was $4.53 per thousand cubic feet in 2015, compared with $5.78 and $5.91 in 2014 and 2013, respectively.

International net oil-equivalent production was 1.90 million barrels per day in 2015, essentially unchanged from 2014 and down 2 percent from 2013. Between 2015 and 2014, production increases from entitlement effects in several locations and project ramp-ups in Bangladesh and other areas were offset by the Partitioned Zone shut-in, normal field declines and the effect of asset sales. Between 2014 and 2013, production increases due to project ramp-ups in Nigeria, Argentina and Brazil were more than offset by normal field declines, production entitlement effects in several locations and the effect of asset sales.

The net liquids component of international oil-equivalent production was 1.24 million barrels per day in 2015, a decrease of approximately 1 percent from 2014 and a decrease of approximately 3 percent from 2013. International net natural gas production of 4.0 billion cubic feet per day in 2015 was up 1 percent from 2014 and unchanged from 2013.

Refer to the “Selected Operating Data” table, on page FS-11, for a three-year comparison of international production volumes.

FS--7

Management's Discussion and Analysis of Financial Condition and Results of Operations

U.S. Downstream



Millions of dollars	2015		2014		2013
Earnings	$	3,182	$	2,637	$	787

U.S. downstream operations earned $3.18 billion in 2015, compared with $2.64 billion in 2014. The increase was due to higher margins on refined product sales of $1.51 billion, partially offset by the absence of 2014 asset sale gains of $960 million.

U.S. downstream operations earned $2.64 billion in 2014, compared with $787 million in 2013. The increase in earnings was mainly due to higher margins on refined product sales of $830 million. Gains from asset sales were $960 million in 2014, compared with $250 million in 2013. Higher earnings from 50 percent-owned Chevron Phillips Chemical Company, LLC (CPChem) of $160 million and lower operating expenses of $80 million also contributed to the earnings increase.

Refined product sales of 1.23 million barrels per day in 2015 increased 1 percent, mainly reflecting higher sales of jet fuel. Sales volumes of refined products were 1.21 million barrels per day in 2014, an increase of 2 percent from 2013, mainly reflecting higher gas oil sales. U.S. branded gasoline sales of 522,000 barrels per day in 2015 increased 1 percent from 2014 and 2013.

Refer to the “Selected Operating Data” table on page FS-11 for a three-year comparison of sales volumes of gasoline and other refined products and refinery input volumes.

International Downstream



Millions of dollars	2015		2014			2013
Earnings^*	$	4,419	$	1,699		$	1,450

^*Includes foreign currency effects:	$	47	$	(112	)	$	(76	)

International downstream earned $4.42 billion in 2015, compared with $1.70 billion in 2014. The increase was primarily due to a $1.6 billion gain from the sale of the company’s interest in Caltex Australia Limited in second quarter 2015 and higher margins on refined product sales of $690 million. Foreign currency effects increased earnings by $47 million in 2015, compared to a decrease of $112 million a year earlier.

International downstream earned $1.70 billion in 2014, compared with $1.45 billion in 2013. The increase was mainly due to a favorable change in the effects on derivative instruments of $640 million. The increase was partially offset by the economic buyout of a legacy pension obligation of $160 million in the 2014 period, lower margins on refined product sales of $130 million and higher tax expenses of $110 million. Foreign currency effects decreased earnings by $112 million in 2014, compared with a decrease of $76 million a year earlier.

Total refined product sales of 1.51 million barrels per day in 2015 were essentially unchanged from 2014. Excluding the effects of the Caltex Australia Limited divestment, refined product sales were up 107,000 barrels per day, primarily reflecting higher sales of jet fuel, gasoline and gas oil. Sales of 1.50 million barrels per day in 2014 declined 2 percent from 2013, mainly reflecting lower gas oil sales.

Refer to the “Selected Operating Data” table, on page FS-11, for a three-year comparison of sales volumes of gasoline and other refined products and refinery input volumes.

All Other



Millions of dollars	2015			2014			2013
Net charges^*	$	(1,053	)	$	(1,988	)	$	(1,623	)

^*Includes foreign currency effects:	$	(3	)	$	2		$	(9	)

All Other consists of worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, and technology companies.

Net charges in 2015 decreased $935 million from 2014, mainly due to lower corporate tax items and the absence of 2014 charges related to mining assets, partially offset by higher charges related to reductions in corporate staffs. Net charges in 2014 increased $365 million from 2013, mainly due to higher environmental reserve additions, asset impairments and additional asset retirement obligations for mining assets, as well as higher corporate tax items. These increases were partially offset by the absence of 2013 impairments of power-related affiliates and lower other corporate charges.

FS--8

Management's Discussion and Analysis of Financial Condition and Results of Operations

Consolidated Statement of Income

Comparative amounts for certain income statement categories are shown below:



Millions of dollars	2015		2014		2013
Sales and other operating revenues	$	129,925	$	200,494	$	220,156

Sales and other operating revenues decreased in 2015 primarily due to lower refined product and crude oil prices, partially offset by an increase in refined product and crude oil volumes. The decrease between 2014 and 2013 was mainly due to lower crude oil volumes, and lower refined product and crude oil prices.



Millions of dollars	2015		2014		2013
Income from equity affiliates	$	4,684	$	7,098	$	7,527

Income from equity affiliates decreased in 2015 from 2014 mainly due to lower earnings from Tengizchevroil in Kazakhstan, CPChem, Angola LNG and the effect of the sale of Caltex Australia Limited in second quarter 2015. Partially offsetting these effects were higher earnings from GS Caltex in South Korea and Petropiar in Venezuela.

Income from equity affiliates decreased in 2014 from 2013 mainly due to lower upstream-related earnings from Tengizchevroil in Kazakhstan, Petropiar and Petroboscan in Venezuela, and Angola LNG. Partially offsetting these effects were higher downstream-related earnings from GS Caltex in South Korea, higher earnings from CPChem and the absence of 2013 impairments of power-related affiliates.

Refer to Note 15, beginning on page FS-40, for a discussion of Chevron’s investments in affiliated companies.



Millions of dollars	2015		2014		2013
Other income	$	3,868	$	4,378	$	1,165

Other income of $3.9 billion in 2015 included net gains from asset sales of $3.2 billion before-tax. Other income in 2014 and 2013 included net gains from asset sales of $3.6 billion and $710 million before-tax, respectively. Interest income was approximately $119 million in 2015, $145 million in 2014 and $136 million in 2013. Foreign currency effects increased other income by $82 million in 2015, $277 million in 2014 and $103 million in 2013.



Millions of dollars	2015		2014		2013
Purchased crude oil and products	$	69,751	$	119,671	$	134,696

Crude oil and product purchases of $69.8 billion were down in 2015 mainly due to lower crude oil and refined product prices, partially offset by an increase in crude oil volumes. Crude oil and product purchases in 2014 decreased by $15.0 billion from the prior year, mainly due to lower crude oil and refined product prices, along with lower crude oil volumes.



Millions of dollars	2015		2014		2013
Operating, selling, general and administrative expenses	$	27,477	$	29,779	$	29,137

Operating, selling, general and administrative expenses decreased $2.3 billion between 2015 and 2014. The decrease included lower fuel costs of $920 million. Also contributing to the decrease were lower expenses for construction, repair and maintenance of $300 million, contract labor of $270 million, and research, technical and professional services of $200 million.

Operating, selling, general and administrative expenses increased $642 million between 2014 and 2013. The increase included higher employee compensation and benefit costs of $360 million, primarily related to a buyout of a legacy pension obligation. Also contributing to the increase was higher transportation costs of $350 million, primarily reflecting the economic buyout of a long-term contractual obligation, and higher environmental expenses related to a mining asset of $300 million. Partially offsetting the increase were lower fuel expenses of $360 million.



Millions of dollars	2015		2014		2013
Exploration expense	$	3,340	$	1,985	$	1,861

Exploration expenses in 2015 increased from 2014 mainly due to higher charges for well write-offs largely related to project cancellations. Exploration expenses in 2014 increased from 2013 mainly due to higher charges for well write-offs, partially offset by lower geological and geophysical expenses.

FS--9

Management's Discussion and Analysis of Financial Condition and Results of Operations



Millions of dollars	2015		2014		2013
Depreciation, depletion and amortization	$	21,037	$	16,793	$	14,186

Depreciation, depletion and amortization expenses increased in 2015 from 2014 mainly due to impairments of oil and gas producing fields of about $3.5 billion in 2015 compared with $900 million in 2014. Also contributing to the increase were higher depreciation rates and higher production levels for certain oil and gas producing fields. The increase in 2014 from 2013 was mainly due to higher depreciation rates and impairments for certain oil and gas producing fields, and the impairment of a mining asset.



Millions of dollars	2015		2014		2013
Taxes other than on income	$	12,030	$	12,540	$	13,063

Taxes other than on income decreased in 2015 from 2014 mainly due to lower crude oil and refined product prices. Taxes other than on income decreased in 2014 from 2013 primarily due to a decrease in duty expense in South Africa along with lower consumer excise taxes in Thailand, reflecting lower sales volumes at both locations.



Millions of dollars	2015		2014		2013
Income tax expense	$	132	$	11,892	$	14,308

Effective income tax rates were 3 percent in 2015, 38 percent in 2014 and 40 percent in 2013. The decrease in the effective tax rate between 2015 and 2014 primarily resulted from the impacts of jurisdictional mix, one-time tax benefits, foreign currency remeasurement, equity earnings and a reduction in statutory tax rates in the United Kingdom, partially offset by the effects of valuation allowances recognized on deferred tax assets and the sale of the company's interest in Caltex Australia Limited.

The rate decreased between 2014 and 2013 primarily due to the impact of changes in jurisdictional mix and equity earnings, and the tax effects related to the 2014 sale of interests in Chad and Cameroon, partially offset by other one-time and ongoing tax charges.

FS--10

Management's Discussion and Analysis of Financial Condition and Results of Operations

Selected Operating Data^1,2



	2015		2014		2013
U.S. Upstream
Net Crude Oil and Natural Gas Liquids Production (MBPD)	501		456		449
Net Natural Gas Production (MMCFPD)³	1,310		1,250		1,246
Net Oil-Equivalent Production (MBOEPD)	720		664		657
Sales of Natural Gas (MMCFPD)	3,913		3,995		5,483
Sales of Natural Gas Liquids (MBPD)	26		20		17
Revenues From Net Production
Liquids ($/Bbl)	$	42.70	$	84.13	$	93.46
Natural Gas ($/MCF)	$	1.92	$	3.90	$	3.37
International Upstream
Net Crude Oil and Natural Gas Liquids Production (MBPD)⁴	1,243		1,253		1,282
Net Natural Gas Production (MMCFPD)³	3,959		3,917		3,946
Net Oil-Equivalent Production (MBOEPD)⁴	1,902		1,907		1,940
Sales of Natural Gas (MMCFPD)	4,299		4,304		4,251
Sales of Natural Gas Liquids (MBPD)	24		28		26
Revenues From Liftings
Liquids ($/Bbl)	$	46.52	$	90.42	$	100.26
Natural Gas ($/MCF)	$	4.53	$	5.78	$	5.91
Worldwide Upstream
Net Oil-Equivalent Production (MBOEPD)⁴
United States	720		664		657
International	1,902		1,907		1,940
Total	2,622		2,571		2,597
U.S. Downstream
Gasoline Sales (MBPD)⁵	621		615		613
Other Refined Product Sales (MBPD)	607		595		569
Total Refined Product Sales (MBPD)	1,228		1,210		1,182
Sales of Natural Gas Liquids (MBPD)	127		121		125
Refinery Input (MBPD)	924		871		774
International Downstream
Gasoline Sales (MBPD)⁵	389		403		398
Other Refined Product Sales (MBPD)	1,118		1,098		1,131
Total Refined Product Sales (MBPD)⁶	1,507		1,501		1,529
Sales of Natural Gas Liquids (MBPD)	65		58		62
Refinery Input (MBPD)⁷	778		819		864



¹Includes company share of equity affiliates.
²MBPD – thousands of barrels per day; MMCFPD – millions of cubic feet per day; MBOEPD – thousands of barrels of oil-equivalents per day; Bbl – Barrel; MCF - Thousands of cubic feet. Oil-equivalent gas (OEG) conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of oil.
³ Includes natural gas consumed in operations (MMCFPD):
United States	66	71	72
International	430	452	458
⁴ Includes net production of synthetic oil:
Canada	47	43	43
Venezuela affiliate	29	31	25
⁵ Includes branded and unbranded gasoline.
⁶ Includes sales of affiliates (MBPD):	420	475	471
⁷ In 2015, the company sold its interests in affiliates in Australia and New Zealand, which included operable capacities of 55,000 and 12,000 barrels per day, respectively.

FS--11

Management's Discussion and Analysis of Financial Condition and Results of Operations

Liquidity and Capital Resources

Cash, Cash Equivalents, Time Deposits and Marketable Securities Total balances were $11.3 billion and $13.2 billion at December 31, 2015 and 2014, respectively. Cash provided by operating activities in 2015 was $19.5 billion, compared with $31.5 billion in 2014 and $35.0 billion in 2013. Cash provided by operating activities was net of contributions to employee pension plans of approximately $0.9 billion, $0.4 billion and $1.2 billion in 2015, 2014 and 2013, respectively. Cash provided by investing activities included proceeds and deposits related to asset sales of $5.7 billion in 2015, $5.7 billion in 2014, and $1.1 billion in 2013.

Restricted cash of $1.1 billion and $1.5 billion at December 31, 2015 and 2014, respectively, was held in cash and short-term marketable securities and recorded as “Deferred charges and other assets” on the Consolidated Balance Sheet. These amounts are generally associated with upstream abandonment activities, tax payments, and funds held in escrow for tax-deferred exchanges and asset acquisitions and divestitures.

Dividends Dividends paid to common stockholders were $8.0 billion in 2015, $7.9 billion in 2014 and $7.5 billion in 2013.

Debt and Capital Lease Obligations Total debt and capital lease obligations were $38.6 billion at December 31, 2015, up from $27.8 billion at year-end 2014.

The $10.8 billion increase in total debt and capital lease obligations during 2015 was primarily due to funding the company’s capital investment program, which included several large projects in the construction phase. The company completed bond issuances of $6 billion and $5 billion in March and November 2015, respectively. The company’s debt and capital lease obligations due within one year, consisting primarily of commercial paper, redeemable long-term obligations and the current portion of long-term debt, totaled $12.9 billion at December 31, 2015, compared with $11.8 billion at year-end 2014. Of these amounts, $8.0 billion was reclassified to long-term at the end of both periods. At year-end 2015, settlement of these obligations was not expected to require the use of working capital in 2016, as the company had the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis.

Chevron has an automatic shelf registration statement that expires in August 2018 for an unspecified amount of nonconvertible debt securities issued or guaranteed by the company.

The major debt rating agencies routinely evaluate the company’s debt, and the company’s cost of borrowing can increase or decrease depending on these debt ratings. The company has outstanding public bonds issued by Chevron Corporation and Texaco Capital Inc. All of these securities are the obligations of, or guaranteed by, Chevron Corporation. In February 2016, Standard & Poor's Corporation changed its rating for these securities from AA to AA-. These securities are rated Aa1 by Moody’s Investors

FS--12

Management's Discussion and Analysis of Financial Condition and Results of Operations

Service. The company’s U.S. commercial paper is rated A-1+ by Standard & Poor’s and P-l by Moody’s. All of these ratings denote high-quality, investment-grade securities.

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

Committed Credit Facilities Information related to committed credit facilities is included in Note 19 to the Consolidated Financial Statements, Short-Term Debt, on page FS-48.

Common Stock Repurchase Program In July 2010, the Board of Directors approved an ongoing share repurchase program with no set term or monetary limits. The company did not acquire any shares under the program in 2015. From the inception of the program through 2014, the company had purchased 180.9 million shares for $20.0 billion.

Capital and Exploratory Expenditures

Capital and exploratory expenditures by business segment for 2015, 2014 and 2013 are as follows:



	2015						2014						2013
Millions of dollars	U.S.		Int’l.		Total		U.S.		Int’l.		Total		U.S.		Int’l.		Total
Upstream	$	7,582	$	23,535	$	31,117	$	8,799	$	28,316	$	37,115	$	8,480	$	29,378	$	37,858
Downstream	1,923		513		2,436		1,649		941		2,590		1,986		1,189		3,175
All Other	418		8		426		584		27		611		821		23		844
Total	$	9,923	$	24,056	$	33,979	$	11,032	$	29,284	$	40,316	$	11,287	$	30,590	$	41,877
Total, Excluding Equity in Affiliates	$	8,579	$	22,003	$	30,582	$	10,011	$	26,838	$	36,849	$	10,562	$	28,617	$	39,179

Total expenditures for 2015 were $34.0 billion, including $3.4 billion for the company’s share of equity-affiliate expenditures, which did not require cash outlays by the company. In 2014 and 2013, expenditures were $40.3 billion and $41.9 billion, respectively, including the company’s share of affiliates’ expenditures of $3.5 billion and $2.7 billion, respectively.

Of the $34.0 billion of expenditures in 2015, 92 percent, or $31.1 billion, was related to upstream activities. Approximately 92 percent and 90 percent was expended for upstream operations in 2014 and 2013, respectively. International upstream accounted for 76 percent of the worldwide upstream investment in 2015, 76 percent in 2014 and 78 percent in 2013.

The company estimates that 2016 capital and exploratory expenditures will be $26.6 billion, including $4.5 billion of spending by affiliates. This planned reduction, compared to 2015 expenditures, is in response to current crude oil market conditions. Approximately 90 percent of the total, or $24.0 billion, is budgeted for exploration and production activities. Approximately $9 billion of planned upstream capital spending is for existing base producing assets, which include shale and tight resource investments. Approximately $11 billion is related to major capital projects currently underway, and approximately $3 billion relates to projects yet to be sanctioned. Global exploration funding accounts for approximately $1 billion. The company will continue to monitor crude oil market conditions, and will further restrict capital outlays should current oil price conditions persist.

Worldwide downstream spending in 2016 is estimated at $2.2 billion, with $1.6 billion for projects in the United States.

Investments in technology companies and other corporate businesses in 2016 are budgeted at $0.4 billion.

Noncontrolling Interests The company had noncontrolling interests of $1.2 billion at both December 31, 2015, and December 31, 2014. Distributions to noncontrolling interests totaled $128 million and $47 million in 2015 and 2014, respectively.

Pension Obligations Information related to pension plan contributions is included on page FS-56 in Note 23 to the Consolidated Financial Statements under the heading “Cash Contributions and Benefit Payments.”

FS--13

Management's Discussion and Analysis of Financial Condition and Results of Operations

Financial Ratios



	At December 31
	2015		2014		2013
Current Ratio	1.3		1.3		1.5
Interest Coverage Ratio	9.9		87.2		126.2
Debt Ratio	20.2	%	15.2	%	12.1	%

Current Ratio Current assets divided by current liabilities, which indicates the company’s ability to repay its short-term liabilities with short-term assets. The current ratio in all periods was adversely affected by the fact that Chevron’s inventories are valued on a last-in, first-out basis. At year-end 2015, the book value of inventory was lower than replacement costs, based on average acquisition costs during the year, by approximately $3.7 billion.

Interest Coverage Ratio Income before income tax expense, plus interest and debt expense and amortization of capitalized interest, less net income attributable to noncontrolling interests, divided by before-tax interest costs. This ratio indicates the company’s ability to pay interest on outstanding debt. The company’s interest coverage ratio in 2015 was lower than 2014 and 2013 due to lower income.

Debt Ratio Total debt as a percentage of total debt plus Chevron Corporation Stockholders' Equity, which indicates the company’s leverage. The company's debt ratio in 2015 was higher than 2014 and 2013 as the company took on more debt to finance its ongoing investment program.

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

Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements The company and its subsidiaries have certain contingent liabilities with respect to long-term unconditional purchase obligations and commitments, including throughput and take-or-pay agreements, some of which relate to suppliers’ financing arrangements. The agreements typically provide goods and services, such as pipeline and storage capacity, drilling rigs, utilities, and petroleum products, to be used or sold in the ordinary course of the company’s business. The aggregate approximate amounts of required payments under these various commitments are: 2016 – $2.1 billion; 2017 – $1.9 billion; 2018 – $1.7 billion; 2019 – $1.5 billion; 2020 – $1.1 billion; 2020 and after – $3.1 billion. A portion of these commitments may ultimately be shared with project partners. Total payments under the agreements were approximately $1.9 billion in 2015, $3.7 billion in 2014 and $3.6 billion in 2013.

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



	Payments Due by Period
Millions of dollars	Total¹		2016		2017-2018		2019-2020		After 2020
On Balance Sheet:²
Short-Term Debt³	$	4,928	$	4,928	$	—	$	—	$	—
Long-Term Debt³	33,584		—		20,023		6,704		6,857
Noncancelable Capital Lease Obligations	150		23		40		25		62
Interest	3,052		563		994		615		880
Off Balance Sheet:
Noncancelable Operating Lease Obligations	3,348		846		1,243		731		528
Throughput and Take-or-Pay Agreements⁴	6,042		634		1,352		1,294		2,762
Other Unconditional Purchase Obligations⁴	5,293		1,480		2,228		1,276		309


¹	Excludes contributions for pensions and other postretirement benefit plans. Information on employee benefit plans is contained in Note 23 beginning on page FS-51.


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


³	$8.0 billion of short-term debt that the company expects to refinance is included in long-term debt. The repayment schedule above reflects the projected repayment of the entire amounts in the 2017–2018 period.


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

FS--14

Management's Discussion and Analysis of Financial Condition and Results of Operations

Direct Guarantees



	Commitment Expiration by Period
Millions of dollars	Total	2016	2017-2018	2019-2020	After 2020
Guarantee of nonconsolidated affiliate or joint-venture obligations	$447	$38	$76	$76	$257

The company’s guarantee of $447 million is associated with certain payments under a terminal use agreement entered into by an equity affiliate. Over the approximate 12-year remaining term of the guarantee, the maximum guarantee amount will be reduced as certain fees are paid by the affiliate. There are numerous cross-indemnity agreements with the affiliate and the other partners to permit recovery of amounts paid under the guarantee. Chevron has recorded no liability for its obligation under this guarantee.

Indemnifications Information related to indemnifications is included on page FS-57 in Note 24 to the Consolidated Financial Statements under the heading “Indemnifications.”

Financial and Derivative Instrument Market Risk

The market risk associated with the company’s portfolio of financial and derivative instruments is discussed below. The estimates of financial exposure to market risk do not represent the company’s projection of future market changes. The actual impact of future market changes could differ materially due to factors discussed elsewhere in this report, including those set forth under the heading “Risk Factors” in Part I, Item 1A, of the company’s 2015 Annual Report on Form 10-K.

Derivative Commodity Instruments Chevron is exposed to market risks related to the price volatility of crude oil, refined products, natural gas, natural gas liquids, liquefied natural gas and refinery feedstocks. The company uses derivative commodity instruments to manage these exposures on a portion of its activity, including firm commitments and anticipated transactions for the purchase, sale and storage of crude oil, refined products, natural gas, natural gas liquids and feedstock for company refineries. The company also uses derivative commodity instruments for limited trading purposes. The results of these activities were not material to the company’s financial position, results of operations or cash flows in 2015.

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

Derivatives beyond those designated as normal purchase and normal sale contracts are recorded at fair value on the Consolidated Balance Sheet with resulting gains and losses reflected in income. Fair values are derived principally from published market quotes and other independent third-party quotes. The change in fair value of Chevron’s derivative commodity instruments in 2015 was not material to the company's results of operations.

The company uses the Monte Carlo simulation method with a 95 percent confidence level as its Value-at-Risk (VaR) model to estimate the maximum potential loss in fair value from the effect of adverse changes in market conditions on derivative commodity instruments held or issued. A one-day holding period is used on the assumption that market-risk positions can be liquidated or hedged within one day. Based on these inputs, the VaR for the company's primary risk exposures in the area of derivative commodity instruments at December 31, 2015 and 2014 was not material to the company's cash flows or results of operations.

Foreign Currency The company may enter into foreign currency derivative contracts to manage some of its foreign currency exposures. These exposures include revenue and anticipated purchase transactions, including foreign currency capital expenditures and lease commitments. The foreign currency derivative contracts, if any, are recorded at fair value on the balance sheet with resulting gains and losses reflected in income. There were no open foreign currency derivative contracts at December 31, 2015.

Interest Rates The company may enter into interest rate swaps from time to time as part of its overall strategy to manage the interest rate risk on its debt. Interest rate swaps, if any, are recorded at fair value on the balance sheet with resulting gains and losses reflected in income. At year-end 2015, the company had no interest rate swaps.

Transactions With Related Parties

Chevron enters into a number of business arrangements with related parties, principally its equity affiliates. These arrangements include long-term supply or offtake agreements and long-term purchase agreements. Refer to “Other Information” in Note 15 of the Consolidated Financial Statements, page FS-41, for further discussion. Management believes these agreements have been negotiated on terms consistent with those that would have been negotiated with an unrelated party.

FS--15

Management's Discussion and Analysis of Financial Condition and Results of Operations

Litigation and Other Contingencies

MTBE Information related to methyl tertiary butyl ether (MTBE) matters is included on page FS-42 in Note 17 to the Consolidated Financial Statements under the heading “MTBE.”

Ecuador Information related to Ecuador matters is included in Note 17 to the Consolidated Financial Statements under the heading “Ecuador,” beginning on page FS-42.

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



Millions of dollars	2015			2014			2013
Balance at January 1	$	1,683		$	1,456		$	1,403
Net Additions	365			636			488
Expenditures	(470		)	(409		)	(435		)
Balance at December 31	$	1,578		$	1,683		$	1,456

The company records asset retirement obligations when there is a legal obligation associated with the retirement of long-lived assets and the liability can be reasonably estimated. These asset retirement obligations include costs related to environmental issues. The liability balance of approximately $15.6 billion for asset retirement obligations at year-end 2015 related primarily to upstream properties.

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

Refer to the discussion below for additional information on environmental matters and their impact on Chevron, and on the company's 2015 environmental expenditures. Refer to Note 24 on page FS-58 for additional discussion of environmental remediation provisions and year-end reserves. Refer also to Note 25 on page FS-59 for additional discussion of the company's asset retirement obligations.

Suspended Wells Information related to suspended wells is included in Note 21 to the Consolidated Financial Statements, Accounting for Suspended Exploratory Wells, beginning on page FS-49.

Income Taxes Information related to income tax contingencies is included on pages FS-45 through FS-48 in Note 18 and page FS-57 in Note 24 to the Consolidated Financial Statements under the heading “Income Taxes.”

Other Contingencies Information related to other contingencies is included on page FS-58 in Note 24 to the Consolidated Financial Statements under the heading “Other Contingencies.”

Environmental Matters

The company is subject to various international, federal, state and local environmental, health and safety laws, regulations and market-based programs. These laws, regulations and programs continue to evolve and are expected to increase in both number and complexity over time and govern not only the manner in which the company conducts its operations, but also the products it sells. For example, 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 greenhouse gas (GHG) emissions are currently in various stages of discussion or implementation. Consideration of GHG issues and the responses to those issues through international agreements and national, regional or state legislation or regulation are integrated into the company’s strategy, planning and capital investment reviews, 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. In addition, legislation and regulations intended to address hydraulic fracturing also continue to evolve at the international, national and state levels. Refer to “Risk Factors” in Part I, Item 1A, on pages 21 through 23 for a discussion of some of the inherent risks of increasingly restrictive environmental and other regulation that could materially impact the company’s results of operations or financial condition.

FS--16

Management's Discussion and Analysis of Financial Condition and Results of Operations

Most of the costs of complying with existing laws and regulations pertaining to company operations and products are embedded in the normal costs of doing business. However, it is not possible to predict with certainty the amount of additional investments in new or existing technology or facilities or the amounts of increased operating costs to be incurred in the future to: prevent, control, reduce or eliminate releases of hazardous materials into the environment; remediate and restore areas damaged by prior releases of nitrogen oxide, sulfur oxide, or other hazardous materials; or comply with new environmental laws or regulations. Although these costs may be significant to the results of operations in any single period, the company does not presently expect them to have a material adverse effect on the company's liquidity or financial position.

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

Using definitions and guidelines established by the American Petroleum Institute, Chevron estimated its worldwide environmental spending in 2015 at approximately $2.7 billion for its consolidated companies. Included in these expenditures were approximately $0.9 billion of environmental capital expenditures and $1.8 billion of costs associated with the prevention, control, abatement or elimination of hazardous substances and pollutants from operating, closed or divested sites, and the abandonment and restoration of sites.

For 2016, total worldwide environmental capital expenditures are estimated at $0.6 billion. These capital costs are in addition to the ongoing costs of complying with environmental regulations and the costs to remediate previously contaminated sites.

Critical Accounting Estimates and Assumptions

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

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


1.	the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters, or the susceptibility of such matters to change; and


2.	the impact of the estimates and assumptions on the company’s financial condition or operating performance is material.

The development and selection of accounting estimates and assumptions, including those deemed “critical,” and the associated disclosures in this discussion have been discussed by management with the Audit Committee of the Board of Directors. The areas of accounting and the associated “critical” estimates and assumptions made by the company are as follows:

Oil and Gas Reserves Crude oil and natural gas reserves are estimates of future production that impact certain asset and expense accounts included in the Consolidated Financial Statements. Proved reserves are the estimated quantities of oil and gas that geoscience and engineering data demonstrate with reasonable certainty to be economically producible in the future under existing economic conditions, operating methods and government regulations. Proved reserves include both developed and undeveloped volumes. Proved developed reserves represent volumes expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are volumes expected to be recovered from new wells on undrilled proved acreage, or from existing wells where a relatively major expenditure is required for recompletion. Variables impacting Chevron's estimated volumes of crude oil and natural gas reserves include field performance, available technology, commodity prices, and development and production costs.

The estimates of crude oil and natural gas reserves are important to the timing of expense recognition for costs incurred and to the valuation of certain oil and gas producing assets. Impacts of oil and gas reserves on Chevron's Consolidated Financial Statements, using the successful efforts method of accounting, include the following:


1.	Amortization - Capitalized exploratory drilling and development costs are depreciated on a unit-of-production (UOP) basis using proved developed reserves. Acquisition costs of proved properties are amortized on a UOP basis using total proved reserves. During 2015, Chevron's UOP Depreciation, Depletion and Amortization (DD&A) for

FS--17

Management's Discussion and Analysis of Financial Condition and Results of Operations

oil and gas properties was $13.9 billion, and proved developed reserves at the beginning of 2015 were 4.7 billion barrels for consolidated companies. If the estimates of proved reserves used in the UOP calculations for consolidated operations had been lower by 5 percent across all oil and gas properties, UOP DD&A in 2015 would have increased by approximately $730 million.

Impairment - Oil and gas reserves are used in assessing oil and gas producing properties for impairment. A significant reduction in the estimated reserves of a property would trigger an impairment review. Proved reserves (and, in some cases, a portion of unproved resources) are used to estimate future production volumes in the cash flow model. For a further discussion of estimates and assumptions used in impairment assessments, see Impairment of Properties, Plant and Equipment and Investments in Affiliates below.

Refer to Table V, “Reserve Quantity Information,” beginning on page FS-65, for the changes in proved reserve estimates for the three years ending December 31, 2015, and to Table VII, “Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves” on page FS-71 for estimates of proved reserve values for each of the three years ended December 31, 2015.

This Oil and Gas Reserves commentary should be read in conjunction with the Properties, Plant and Equipment section of Note 1 to the Consolidated Financial Statements, beginning on page FS-28, which includes a description of the “successful efforts” method of accounting for oil and gas exploration and production activities.

Impairment of Properties, Plant and Equipment and Investments in Affiliates The company assesses its properties, plant and equipment (PP&E) for possible impairment whenever events or changes in circumstances indicate that the carrying value of the assets may not be recoverable. If the carrying value of an asset exceeds the future undiscounted cash flows expected from the asset, an impairment charge is recorded for the excess of carrying value of the asset over its estimated fair value.

Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters, such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles, and the outlook for global or regional market supply-and-demand conditions for crude oil, natural gas, commodity chemicals and refined products. However, the impairment reviews and calculations are based on assumptions that are generally consistent with the company’s business plans and long-term investment decisions. Refer also to the discussion of impairments of properties, plant and equipment in Note 16 beginning on page FS-41 and to the section on Properties, Plant and Equipment in Note 1, "Summary of Significant Accounting Policies," beginning on page FS-28.

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

Investments in common stock of affiliates that are accounted for under the equity method, as well as investments in other securities of these equity investees, are reviewed for impairment when the fair value of the investment falls below the company’s carrying value. When this occurs, a determination must be made as to whether this loss is other-than-temporary, in which case the investment is impaired. Because of the number of differing assumptions potentially affecting whether an investment is impaired in any period or the amount of the impairment, a sensitivity analysis is not practicable.

The company reported impairments for certain oil and gas properties during 2015 primarily as a result of downward revisions in the company's longer-term crude oil price outlook. The impairments were primarily in Brazil and the United States. No material individual impairments of PP&E or Investments were recorded for the years 2014 and 2013. A sensitivity analysis of the impact on earnings for these periods if other assumptions had been used in impairment reviews and impairment calculations is not practicable, given the broad range of the company’s PP&E and the number of assumptions involved in the estimates. That is, favorable changes to some assumptions might have avoided the need to impair any assets in these periods, whereas unfavorable changes might have caused an additional unknown number of other assets to become impaired, or resulted in larger impacts on impaired assets.

FS--18

Management's Discussion and Analysis of Financial Condition and Results of Operations

Asset Retirement Obligations In the determination of fair value for an asset retirement obligation (ARO), the company uses various assumptions and judgments, including such factors as the existence of a legal obligation, estimated amounts and timing of settlements, discount and inflation rates, and the expected impact of advances in technology and process improvements. A sensitivity analysis of the ARO impact on earnings for 2015 is not practicable, given the broad range of the company's long-lived assets and the number of assumptions involved in the estimates. That is, favorable changes to some assumptions would have reduced estimated future obligations, thereby lowering accretion expense and amortization costs, whereas unfavorable changes would have the opposite effect. Refer to Note 25 on page FS-59 for additional discussions on asset retirement obligations.

Pension and Other Postretirement Benefit Plans Note 23, beginning on page FS-51, includes information on the funded status of the company’s pension and other postretirement benefit (OPEB) plans reflected on the Consolidated Balance Sheet; the components of pension and OPEB expense reflected on the Consolidated Statement of Income; and the related underlying assumptions.

The determination of pension plan expense and obligations is based on a number of actuarial assumptions. Two critical assumptions are the expected long-term rate of return on plan assets and the discount rate applied to pension plan obligations. Critical assumptions in determining expense and obligations for OPEB plans, which provide for certain health care and life insurance benefits for qualifying retired employees and which are not funded, are the discount rate and the assumed health care cost-trend rates. Information related to the Company’s processes to develop these assumptions is included on page FS-54 in Note 23 under the relevant headings. Actual rates may vary significantly from estimates because of unanticipated changes in the world's financial markets.

For 2015, the company used an expected long-term rate of return of 7.5 percent and a discount rate of 3.7 percent for U.S. pension plans. The actual return for 2015 was slightly negative due to a broad decline in financial markets in the second half of the year. For the 10 years ending December 31, 2015, actual asset returns averaged 5.0 percent for the plan. Additionally, with the exception of three years within this 10-year period, actual asset returns for this plan equaled or exceeded 7.5 percent during each year.

Total pension expense for 2015 was $1.2 billion. An increase in the expected long-term return on plan assets or the discount rate would reduce pension plan expense, and vice versa. As an indication of the sensitivity of pension expense to the long-term rate of return assumption, a 1 percent increase in this assumption for the company’s primary U.S. pension plan, which accounted for about 61 percent of companywide pension expense, would have reduced total pension plan expense for 2015 by approximately $95 million. A 1 percent increase in the discount rate for this same plan would have reduced pension expense for 2015 by approximately $221 million.

The aggregate funded status recognized at December 31, 2015, was a net liability of approximately $4.5 billion. An increase in the discount rate would decrease the pension obligation, thus changing the funded status of a plan. At December 31, 2015, the company used a discount rate of 4.0 percent to measure the obligations for the U.S. pension plans. As an indication of the sensitivity of pension liabilities to the discount rate assumption, a 0.25 percent increase in the discount rate applied to the company’s primary U.S. pension plan, which accounted for about 63 percent of the companywide pension obligation, would have reduced the plan obligation by approximately $384 million, which would have decreased the plan’s underfunded status from approximately $1.7 billion to $1.3 billion.

For the company’s OPEB plans, expense for 2015 was $271 million, and the total liability, which reflected the unfunded status of the plans at the end of 2015, was $3.3 billion. For the main U.S. OPEB plan, the company used a 4.1 percent discount rate to measure expense in 2015, and a 4.5 percent discount rate to measure the benefit obligations at December 31, 2015. Discount rate changes, similar to those used in the pension sensitivity analysis, resulted in an immaterial impact on 2015 OPEB expense and OPEB liabilities at the end of 2015. For information on the sensitivity of the health care cost-trend rate, refer to page FS-54 in Note 23 under the heading “Other Benefit Assumptions.”

Differences between the various assumptions used to determine expense and the funded status of each plan and actual experience are included in actuarial gain/loss. Refer to page FS-53 in Note 23 for a description of the method used to amortize the $6.3 billion of before-tax actuarial losses recorded by the company as of December 31, 2015, and an estimate of the costs to be recognized in expense during 2016. In addition, information related to company contributions is included on page FS-56 in Note 23 under the heading “Cash Contributions and Benefit Payments.”

Contingent Losses Management also makes judgments and estimates in recording liabilities for claims, litigation, tax matters and environmental remediation. Actual costs can frequently vary from estimates for a variety of reasons. For example, the costs for settlement of claims and litigation can vary from estimates based on differing interpretations of laws, opinions on culpability

FS--19

Management's Discussion and Analysis of Financial Condition and Results of Operations

and assessments on the amount of damages. Similarly, liabilities for environmental remediation are subject to change because of changes in laws, regulations and their interpretation, the determination of additional information on the extent and nature of site contamination, and improvements in technology.

Under the accounting rules, a liability is generally recorded for these types of contingencies if management determines the loss to be both probable and estimable. The company generally reports these losses as “Operating expenses” or “Selling, general and administrative expenses” on the Consolidated Statement of Income. An exception to this handling is for income tax matters, for which benefits are recognized only if management determines the tax position is “more likely than not” (i.e., likelihood greater than 50 percent) to be allowed by the tax jurisdiction. For additional discussion of income tax uncertainties, refer to Note 24 beginning on page FS-57. Refer also to the business segment discussions elsewhere in this section for the effect on earnings from losses associated with certain litigation, environmental remediation and tax matters for the three years ended December 31, 2015.

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

New Accounting Standards

Refer to Note 5 on page FS-32 for information regarding new accounting standards.

Quarterly Results and Stock Market Data

Unaudited



	2015									2014
Millions of dollars, except per-share amounts	4th Q			3rd Q		2nd Q		1st Q			4th Q		3rd Q		2nd Q		1st Q
Revenues and Other Income
Sales and other operating revenues¹	$	28,014		$	32,767	$	36,829	$	32,315		$	42,111	$	51,822	$	55,583	$	50,978
Income from equity affiliates	919			1,195		1,169		1,401			1,555		1,912		1,709		1,922
Other income	314			353		2,359		842			2,422		945		646		365
Total Revenues and Other Income	29,247			34,315		40,357		34,558			46,088		54,679		57,938		53,265
Costs and Other Deductions
Purchased crude oil and products	14,570			17,447		20,541		17,193			24,263		30,741		33,844		30,823
Operating expenses	5,970			5,592		6,077		5,395			6,572		6,403		6,287		6,023
Selling, general and administrative expenses	1,303			1,026		1,170		944			1,368		1,122		1,077		927
Exploration expenses	1,358			315		1,075		592			510		366		694		415
Depreciation, depletion and amortization	5,400			4,268		6,958		4,411			4,873		3,948		3,842		4,130
Taxes other than on income¹	2,856			2,883		3,173		3,118			3,118		3,236		3,167		3,019
Total Costs and Other Deductions	31,457			31,531		38,994		31,653			40,704		45,816		48,911		45,337
Income (Loss) Before Income Tax Expense	(2,210		)	2,784		1,363		2,905			5,384		8,863		9,027		7,928
Income Tax Expense (Benefit)	(1,655		)	727		755		305			1,912		3,236		3,337		3,407
Net Income (Loss)	$	(555	)	$	2,057	$	608	$	2,600		$	3,472	$	5,627	$	5,690	$	4,521
Less: Net income attributable to noncontrolling interests	33			20		37		33			1		34		25		9
Net Income (Loss) Attributable to Chevron Corporation	$	(588	)	$	2,037	$	571	$	2,567		$	3,471	$	5,593	$	5,665	$	4,512
Per Share of Common Stock
Net Income (Loss) Attributable to Chevron Corporation
– Basic	$(0.31)			$1.09		$0.30		$1.38			$1.86		$2.97		$3.00		$2.38
– Diluted	$(0.31)			$1.09		$0.30		$1.37			$1.85		$2.95		$2.98		$2.36
Dividends	$1.07			$1.07		$1.07		$1.07			$1.07		$1.07		$1.07		$1.00
Common Stock Price Range – High²	$	98.64		$96.67		$112.20		$113.00			$120.17		$135.10		$133.57		$125.32
– Low²	$	77.31		$69.58		$96.22		$98.88			$100.15		$118.66		$116.50		$109.27
¹ Includes excise, value-added and similar taxes:	$	1,717		$	1,800	$	1,965	$	1,877		$	2,004	$	2,116	$	2,120	$	1,946
² Intraday price.
The company’s common stock is listed on the New York Stock Exchange (trading symbol: CVX). As of February 15, 2016, stockholders of record numbered approximately 145,000. There are no restrictions on the company’s ability to pay dividends.

FS--20




Management’s Responsibility for Financial Statements

To the Stockholders of Chevron Corporation Management of Chevron Corporation is responsible for preparing the accompanying consolidated financial statements and the related information appearing in this report. The statements were prepared in accordance with accounting principles generally accepted in the United States of America and fairly represent the transactions and financial position of the company. The financial statements include amounts that are based on management’s best estimates and judgments. As stated in its report included herein, the independent registered public accounting firm of PricewaterhouseCoopers LLP has audited the company’s consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). The Board of Directors of Chevron has an Audit Committee composed of directors who are not officers or employees of the company. The Audit Committee meets regularly with members of management, the internal auditors and the independent registered public accounting firm to review accounting, internal control, auditing and financial reporting matters. Both the internal auditors and the independent registered public accounting firm have free and direct access to the Audit Committee without the presence of management. The company's management has evaluated, with the participation of the Chief Executive Officer and Chief Financial Officer, the effectiveness of the company's disclosure controls and procedures (as defined in the Exchange Act Rules 13a-15(e) and 15d-15(e)) as of December 31, 2015. Based on that evaluation, management concluded that the company's disclosure controls are effective in ensuring that information required to be recorded, processed, summarized and reported, are done within the time periods specified in the U.S. Securities and Exchange Commission's rules and forms.

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 defined in the Exchange Act Rules 13a-15(f) and 15d-15(f). The company’s management, including the Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of the company’s internal control over financial reporting based on the Internal Control – Integrated Framework (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 herein.

/s/ JOHN S. WATSON	/s/ PATRICIA E. YARRINGTON	/s/ JEANETTE L. OURADA

John S. Watson	Patricia E. Yarrington	Jeanette L. Ourada
Chairman of the Board	Vice President	Vice President
and Chief Executive Officer	and Chief Financial Officer	and Comptroller

February 25, 2016

FS--21




	Report of Independent Registered Public Accounting Firm
	To the Stockholders and the Board of Directors of Chevron Corporation: In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, equity and of cash flows present fairly, in all material respects, the financial position of Chevron Corporation and its subsidiaries at December 31, 2015, and December 31, 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

	/s/ PRICEWATERHOUSECOOPERS LLP
	San Francisco, California
	February 25, 2016

FS--22

Consolidated Statement of Income

Millions of dollars, except per-share amounts




	Year ended December 31
	2015		2014		2013
Revenues and Other Income
Sales and other operating revenues^*	$	129,925	$	200,494	$	220,156
Income from equity affiliates	4,684		7,098		7,527
Other income	3,868		4,378		1,165
Total Revenues and Other Income	138,477		211,970		228,848
Costs and Other Deductions
Purchased crude oil and products	69,751		119,671		134,696
Operating expenses	23,034		25,285		24,627
Selling, general and administrative expenses	4,443		4,494		4,510
Exploration expenses	3,340		1,985		1,861
Depreciation, depletion and amortization	21,037		16,793		14,186
Taxes other than on income^*	12,030		12,540		13,063
Total Costs and Other Deductions	133,635		180,768		192,943
Income Before Income Tax Expense	4,842		31,202		35,905
Income Tax Expense	132		11,892		14,308
Net Income	4,710		19,310		21,597
Less: Net income attributable to noncontrolling interests	123		69		174
Net Income Attributable to Chevron Corporation	$	4,587	$	19,241	$	21,423
Per Share of Common Stock
Net Income Attributable to Chevron Corporation
- Basic	$	2.46	$	10.21	$	11.18
- Diluted	$	2.45	$	10.14	$	11.09
^*Includes excise, value-added and similar taxes.	$	7,359	$	8,186	$	8,492
See accompanying Notes to the Consolidated Financial Statements.

FS--23

Consolidated Statement of Comprehensive Income

Millions of dollars



	Year ended December 31
	2015			2014			2013
Net Income	$	4,710		$	19,310		$	21,597
Currency translation adjustment
Unrealized net change arising during period	(44		)	(73		)	42
Unrealized holding loss on securities
Net loss arising during period	(21		)	(2		)	(7		)
Derivatives
Net derivatives loss on hedge transactions	—			(66		)	(111		)
Reclassification to net income of net realized gain	—			(17		)	(1		)
Income taxes on derivatives transactions	—			29			39
Total	—			(54		)	(73		)
Defined benefit plans
Actuarial gain (loss)
Amortization to net income of net actuarial loss and settlements	794			757			866
Actuarial gain (loss) arising during period	109			(2,730		)	3,379
Prior service credits (cost)
Amortization to net income of net prior service costs (credits) and curtailments	30			26			(27		)
Prior service credits (costs) arising during period	6			(6		)	60
Defined benefit plans sponsored by equity affiliates	30			(99		)	164
Income taxes on defined benefit plans	(336		)	901			(1,614		)
Total	633			(1,151		)	2,828
Other Comprehensive Gain (Loss), Net of Tax	568			(1,280		)	2,790
Comprehensive Income	5,278			18,030			24,387
Comprehensive income attributable to noncontrolling interests	(123		)	(69		)	(174		)
Comprehensive Income Attributable to Chevron Corporation	$	5,155		$	17,961		$	24,213
See accompanying Notes to the Consolidated Financial Statements.

FS--24

Consolidated Balance Sheet

Millions of dollars, except per-share amount




	At December 31
	2015			2014
Assets
Cash and cash equivalents	$	11,022		$	12,785
Time deposits	—			8
Marketable securities	310			422
Accounts and notes receivable (less allowance: 2015 - $313; 2014 - $59)	12,860			16,736
Inventories:
Crude oil and petroleum products	3,535			3,854
Chemicals	490			467
Materials, supplies and other	2,309			2,184
Total inventories	6,334			6,505
Prepaid expenses and other current assets	4,821			5,776
Total Current Assets	35,347			42,232
Long-term receivables, net	2,412			2,817
Investments and advances	27,110			26,912
Properties, plant and equipment, at cost	340,277			327,289
Less: Accumulated depreciation, depletion and amortization	151,881			144,116
Properties, plant and equipment, net	188,396			183,173
Deferred charges and other assets	6,801			6,299
Goodwill	4,588			4,593
Assets held for sale	1,449			—
Total Assets	$	266,103		$	266,026
Liabilities and Equity
Short-term debt	$	4,928		$	3,790
Accounts payable	13,516			19,000
Accrued liabilities	4,833			5,328
Federal and other taxes on income	2,069			2,575
Other taxes payable	1,118			1,233
Total Current Liabilities	26,464			31,926
Long-term debt	33,584			23,960
Capital lease obligations	80			68
Deferred credits and other noncurrent obligations	23,465			23,549
Noncurrent deferred income taxes	20,689			21,920
Noncurrent employee benefit plans	7,935			8,412
Total Liabilities	112,217			109,835
Preferred stock (authorized 100,000,000 shares; $1.00 par value; none issued)	—			—
Common stock (authorized 6,000,000,000 shares; $0.75 par value; 2,442,676,580 shares issued at December 31, 2015 and 2014)	1,832			1,832
Capital in excess of par value	16,330			16,041
Retained earnings	181,578			184,987
Accumulated other comprehensive loss	(4,291		)	(4,859		)
Deferred compensation and benefit plan trust	(240		)	(240		)
Treasury stock, at cost (2015 - 559,862,580 shares; 2014 - 563,027,772 shares)	(42,493		)	(42,733		)
Total Chevron Corporation Stockholders' Equity	152,716			155,028
Noncontrolling interests	1,170			1,163
Total Equity	153,886			156,191
Total Liabilities and Equity	$	266,103		$	266,026

See accompanying Notes to the Consolidated Financial Statements.

FS--25

Consolidated Statement of Cash Flows

Millions of dollars




	Year ended December 31
	2015			2014			2013
Operating Activities
Net Income	$	4,710		$	19,310		$	21,597
Adjustments
Depreciation, depletion and amortization	21,037			16,793			14,186
Dry hole expense	2,309			875			683
Distributions less than income from equity affiliates	(760		)	(2,202		)	(1,178		)
Net before-tax gains on asset retirements and sales	(3,215		)	(3,540		)	(639		)
Net foreign currency effects	(82		)	(277		)	(103		)
Deferred income tax provision	(1,861		)	1,572			1,876
Net increase in operating working capital	(1,979		)	(540		)	(1,331		)
(Increase) decrease in long-term receivables	(59		)	(9		)	183
Decrease (increase) in other deferred charges	25			263			(321		)
Cash contributions to employee pension plans	(868		)	(392		)	(1,194		)
Other	199			(378		)	1,243
Net Cash Provided by Operating Activities	19,456			31,475			35,002
Investing Activities
Capital expenditures	(29,504		)	(35,407		)	(37,985		)
Proceeds and deposits related to asset sales	5,739			5,729			1,143
Net maturities of time deposits	8			—			700
Net sales (purchases) of marketable securities	122			(148		)	3
Net (borrowing) repayment of loans by equity affiliates	(217		)	140			314
Net sales (purchases) of other short-term investments	44			(207		)	216
Net Cash Used for Investing Activities	(23,808		)	(29,893		)	(35,609		)
Financing Activities
Net (repayments) borrowings of short-term obligations	(335		)	3,431			2,378
Proceeds from issuances of long-term debt	11,091			4,000			6,000
Repayments of long-term debt and other financing obligations	(32		)	(43		)	(132		)
Cash dividends - common stock	(7,992		)	(7,928		)	(7,474		)
Distributions to noncontrolling interests	(128		)	(47		)	(99		)
Net sales (purchases) of treasury shares	211			(4,412		)	(4,494		)
Net Cash Provided by (Used for) Financing Activities	2,815			(4,999		)	(3,821		)
Effect of Exchange Rate Changes on Cash and Cash Equivalents	(226		)	(43		)	(266		)
Net Change in Cash and Cash Equivalents	(1,763		)	(3,460		)	(4,694		)
Cash and Cash Equivalents at January 1	12,785			16,245			20,939
Cash and Cash Equivalents at December 31	$	11,022		$	12,785		$	16,245
See accompanying Notes to the Consolidated Financial Statements.

FS--26

Consolidated Statement of Equity

Shares in thousands; amounts in millions of dollars




	2015					2014					2013
	Shares		Amount			Shares		Amount			Shares		Amount
Preferred Stock	—		$	—		—		$	—		—		$	—
Common Stock	2,442,677		$	1,832		2,442,677		$	1,832		2,442,677		$	1,832
Capital in Excess of Par
Balance at January 1			$	16,041				$	15,713				$	15,497
Treasury stock transactions			289					328					216
Balance at December 31			$	16,330				$	16,041				$	15,713
Retained Earnings
Balance at January 1			$	184,987				$	173,677				$	159,730
Net income attributable to Chevron Corporation			4,587					19,241					21,423
Cash dividends on common stock			(7,992		)			(7,928		)			(7,474		)
Stock dividends			(3		)			(3		)			(3		)
Tax (charge) benefit from dividends paid on unallocated ESOP shares and other			(1		)			—					1
Balance at December 31			$	181,578				$	184,987				$	173,677
Accumulated Other Comprehensive Loss
Currency translation adjustment
Balance at January 1			$	(96	)			$	(23	)			$	(65	)
Change during year			(44		)			(73		)			42
Balance at December 31			$	(140	)			$	(96	)			$	(23	)
Unrealized net holding (loss) gain on securities
Balance at January 1			$	(8	)			$	(6	)			$	1
Change during year			(21		)			(2		)			(7		)
Balance at December 31			$	(29	)			$	(8	)			$	(6	)
Net derivatives (loss) gain on hedge transactions
Balance at January 1			$	(2	)			$	52				$	125
Change during year			—					(54		)			(73		)
Balance at December 31			$	(2	)			$	(2	)			$	52
Pension and other postretirement benefit plans
Balance at January 1			$	(4,753	)			$	(3,602	)			$	(6,430	)
Change during year			633					(1,151		)			2,828
Balance at December 31			$	(4,120	)			$	(4,753	)			$	(3,602	)
Balance at December 31			$	(4,291	)			$	(4,859	)			$	(3,579	)
Deferred Compensation and Benefit Plan Trust
Deferred Compensation
Balance at January 1			$	—				$	—				$	(42	)
Net reduction of ESOP debt and other			—					—					42
Balance at December 31			$	—				$	—				$	—
Benefit Plan Trust (Common Stock)	14,168		(240		)	14,168		(240		)	14,168		(240		)
Balance at December 31	14,168		$	(240	)	14,168		$	(240	)	14,168		$	(240	)
Treasury Stock at Cost
Balance at January 1	563,028		$	(42,733	)	529,074		$	(38,290	)	495,979		$	(33,884	)
Purchases	15		(2		)	41,592		(5,006		)	41,676		(5,004		)
Issuances - mainly employee benefit plans	(3,180	)	242			(7,638	)	563			(8,581	)	598
Balance at December 31	559,863		$	(42,493	)	563,028		$	(42,733	)	529,074		$	(38,290	)
Total Chevron Corporation Stockholders' Equity at December 31			$	152,716				$	155,028				$	149,113
Noncontrolling Interests			$	1,170				$	1,163				$	1,314
Total Equity			$	153,886				$	156,191				$	150,427
See accompanying Notes to the Consolidated Financial Statements.

FS--27

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Note 1

Summary of Significant Accounting Policies

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

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

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

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

Fair Value Measurements The three levels of the fair value hierarchy of inputs the company uses to measure the fair value of an asset or a liability are as follows. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Level 3 inputs are inputs that are not observable in the market.

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

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

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

Properties, Plant and Equipment The successful efforts method is used for crude oil and natural gas exploration and production activities. All costs for development wells, related plant and equipment, proved mineral interests in crude oil and natural gas properties, and related asset retirement obligation (ARO) assets are capitalized. Costs of exploratory wells are capitalized pending

FS--28

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

determination of whether the wells found proved reserves. Costs of wells that are assigned proved reserves remain capitalized. Costs also are capitalized for exploratory wells that have found crude oil and natural gas reserves even if the reserves cannot be classified as proved when the drilling is completed, provided the exploratory well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project. All other exploratory wells and costs are expensed. Refer to Note 21, beginning on page FS-49, for additional discussion of accounting for suspended exploratory well costs.

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

Long-lived assets that are held for sale are evaluated for possible impairment by comparing the carrying value of the asset with its fair value less the cost to sell. If the net book value exceeds the fair value less cost to sell, the asset is considered impaired and adjusted to the lower value. Refer to Note 9, beginning on page FS-34, relating to fair value measurements. The fair value of a liability for an ARO is recorded as an asset and a liability when there is a legal obligation associated with the retirement of a long-lived asset and the amount can be reasonably estimated. Refer also to Note 25, on page FS-59, relating to AROs.

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

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

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

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

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

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

Liabilities related to future remediation costs are recorded when environmental assessments or cleanups or both are probable and the costs can be reasonably estimated. For crude oil, natural gas and mineral-producing properties, a liability for an ARO is made in accordance with accounting standards for asset retirement and environmental obligations. Refer to Note 25, on page FS-59, for a discussion of the company’s AROs.

For federal Superfund sites and analogous sites under state laws, the company records a liability for its designated share of the probable and estimable costs, and probable amounts for other potentially responsible parties when mandated by the regulatory agencies because the other parties are not able to pay their respective shares. The gross amount of environmental liabilities is based on the company’s best estimate of future costs using currently available technology and applying current regulations and the company’s own internal environmental policies. Future amounts are not discounted. Recoveries or reimbursements are recorded as assets when receipt is reasonably assured.

FS--29

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

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

Revenue Recognition Revenues associated with sales of crude oil, natural gas, petroleum and chemicals products, and all other sources are recorded when title passes to the customer, net of royalties, discounts and allowances, as applicable. Revenues from natural gas production from properties in which Chevron has an interest with other producers are generally recognized using the entitlement method. Excise, value-added and similar taxes assessed by a governmental authority on a revenue-producing transaction between a seller and a customer are presented on a gross basis. The associated amounts are shown as a footnote to the Consolidated Statement of Income, on page FS-23. Purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another (including buy/sell arrangements) are combined and recorded on a net basis and reported in “Purchased crude oil and products” on the Consolidated Statement of Income.

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

Note 2

Changes in Accumulated Other Comprehensive Losses

The change in Accumulated Other Comprehensive Losses (AOCL) presented on the Consolidated Balance Sheet and the impact of significant amounts reclassified from AOCL on information presented in the Consolidated Statement of Income for the year ending December 31, 2015, are reflected in the table below.



	Year Ended December 31, 2015¹
	Currency Translation Adjustment			Unrealized Holding Gains (Losses) on Securities			Derivatives			Defined Benefit Plans			Total
Balance at January 1	$	(96	)	$	(8	)	$	(2	)	$	(4,753	)	$	(4,859	)
Components of Other Comprehensive Income (Loss):
Before Reclassifications	(44		)	(21		)	—			126			61
Reclassifications²	—			—			—			507			507
Net Other Comprehensive Income (Loss)	(44		)	(21		)	—			633			568
Balance at December 31	$	(140	)	$	(29	)	$	(2	)	$	(4,120	)	$	(4,291	)


¹	All amounts are net of tax.


²	Refer to Note 23 beginning on page FS-51, for reclassified components totaling $824 that are included in employee benefit costs for the year ending December 31, 2015. Related income taxes for the same period, totaling $317, are reflected in Income Tax Expense on the Consolidated Statement of Income. All other reclassified amounts were insignificant.

Note 3

Noncontrolling Interests

Ownership interests in the company’s subsidiaries held by parties other than the parent are presented separately from the parent’s equity on the Consolidated Balance Sheet. The amount of consolidated net income attributable to the parent and the noncontrolling interests are both presented on the face of the Consolidated Statement of Income. The term “earnings” is defined as “Net Income Attributable to Chevron Corporation.”

FS--30

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Activity for the equity attributable to noncontrolling interests for 2015, 2014 and 2013 is as follows:



	2015			2014			2013
Balance at January 1	$	1,163		$	1,314		$	1,308
Net income	123			69			174
Distributions to noncontrolling interests	(128		)	(47		)	(99		)
Other changes, net	12			(173		)	(69		)
Balance at December 31	$	1,170		$	1,163		$	1,314

Note 4

Information Relating to the Consolidated Statement of Cash Flows



	Year ended December 31
	2015			2014			2013
Net increase in operating working capital was composed of the following:
Decrease (increase) in accounts and notes receivable	$	3,631		$	4,491		$	(1,101	)
Decrease (increase) in inventories	85			(146		)	(237		)
Decrease (increase) in prepaid expenses and other current assets	713			(407		)	834
(Decrease) increase in accounts payable and accrued liabilities	(5,769		)	(3,737		)	160
Decrease in income and other taxes payable	(639		)	(741		)	(987		)
Net increase in operating working capital	$	(1,979	)	$	(540	)	$	(1,331	)
Net cash provided by operating activities includes the following cash payments for income taxes:
Income taxes	$	4,645		$	10,562		$	12,898
Net sales (purchases) of marketable securities consisted of the following gross amounts:
Marketable securities purchased	$	(6	)	$	(162	)	$	(7	)
Marketable securities sold	128			14			10
Net sales (purchases) of marketable securities	$	122		$	(148	)	$	3
Net maturities of time deposits consisted of the following gross amounts:
Investments in time deposits	$	—		$	(317	)	$	(2,317	)
Maturities of time deposits	8			317			3,017
Net maturities of time deposits	$	8		$	—		$	700
Net (repayments) borrowings of short-term obligations consisted of the following gross and net amounts:
Proceeds from issuances of short-term obligations	$	13,805		$	9,070		$	1,551
Repayments of short-term obligations	(16,379		)	(4,612		)	(375		)
Net borrowings (repayments) of short-term obligations with three months or less maturity	2,239			(1,027		)	1,202
Net (repayments) borrowings of short-term obligations	$	(335	)	$	3,431		$	2,378

The “Net increase in operating working capital” includes reductions of $17, $58 and $79 for excess income tax benefits associated with stock options exercised during 2015, 2014 and 2013, respectively. These amounts are offset by an equal amount in “Net sales (purchases) of treasury shares.” "Other" includes changes in postretirement benefits obligations and other long-term liabilities.

The “Net sales (purchases) of treasury shares” represents the cost of common shares acquired less the cost of shares issued for share-based compensation plans. Purchases totaled $2, $5,006 and $5,004 in 2015, 2014 and 2013, respectively. No purchases were made under the company's share repurchase program in 2015. In 2014 and 2013, the company purchased 41.5 million and 41.6 million common shares for $5,000 and $5,000 under its share repurchase program, respectively.

In 2015, 2014 and 2013, “Net sales (purchases) of other short-term investments” generally consisted of restricted cash associated with upstream abandonment activities, tax payments, and funds held in escrow for tax-deferred exchanges and asset acquisitions and divestitures that was invested in cash and short-term securities and reclassified from “Cash and cash equivalents” to “Deferred charges and other assets” on the Consolidated Balance Sheet.

The Consolidated Statement of Cash Flows excludes changes to the Consolidated Balance Sheet that did not affect cash. "Depreciation, depletion and amortization," "Dry hole expense" and "Deferred income tax provision" collectively include approximately $3,700 in non-cash reductions to properties, plant and equipment recorded in 2015 relating to impairments and project suspensions and associated adverse tax effects, primarily as a result of downward revisions in the company's longer-term crude oil price outlook.

FS--31

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Refer also to Note 25, on page FS-59, for a discussion of revisions to the company’s AROs that also did not involve cash receipts or payments for the three years ending December 31, 2015.

The major components of “Capital expenditures” and the reconciliation of this amount to the reported capital and exploratory expenditures, including equity affiliates, are presented in the following table:



	Year ended December 31
	2015		2014			2013
Additions to properties, plant and equipment ^*	$	28,213	$	34,393		$	36,550
Additions to investments	555		526			934
Current-year dry hole expenditures	736		504			594
Payments for other liabilities and assets, net	—		(16		)	(93		)
Capital expenditures	29,504		35,407			37,985
Expensed exploration expenditures	1,031		1,110			1,178
Assets acquired through capital lease obligations and other financing obligations	47		332			16
Capital and exploratory expenditures, excluding equity affiliates	30,582		36,849			39,179
Company's share of expenditures by equity affiliates	3,397		3,467			2,698
Capital and exploratory expenditures, including equity affiliates	$	33,979	$	40,316		$	41,877


^*	Excludes noncash additions of $1,362 in 2015, $2,310 in 2014 and $1,661 in 2013.

Note 5

New Accounting Standards

Revenue Recognition (Topic 606), Revenue from Contracts with Customers (ASU 2014-09) In July 2015, the FASB approved a one-year deferral of the effective date of ASU 2014-09, which becomes effective for the company January 1, 2018. Early adoption is permitted at the original effective date of January 1, 2017. The standard provides a single comprehensive revenue recognition model for contracts with customers, eliminates most industry-specific revenue recognition guidance, and expands disclosure requirements. The company is evaluating the effect of the standard on its consolidated financial statements. The company does not intend to proceed with early adoption.

Income Taxes (Topic 740), Balance Sheet Classification of Deferred Taxes (ASU 2015-17) In November 2015, FASB issued ASU 2015-17, which becomes effective for the company January 1, 2017. Early adoption is permitted. The standard provides that all deferred income taxes be classified as noncurrent on the balance sheet. The current requirement is to classify most deferred tax assets and liabilities based on the classification of the underlying asset or liability. Adoption of the standard will not have an impact on the company's results of operations or liquidity.

Note 6

Lease Commitments

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



	At December 31
	2015		2014
Upstream	$	800	$	765
Downstream	98		97
All Other	—		—
Total	898		862
Less: Accumulated amortization	448		381
Net capitalized leased assets	$	450	$	481

FS--32

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Rental expenses incurred for operating leases during 2015, 2014 and 2013 were as follows:



	Year ended December 31
	2015		2014		2013
Minimum rentals	$	1,041	$	1,080	$	1,049
Contingent rentals	2		1		1
Total	1,043		1,081		1,050
Less: Sublease rental income	9		14		25
Net rental expense	$	1,034	$	1,067	$	1,025

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

At December 31, 2015, the estimated future minimum lease payments (net of noncancelable sublease rentals) under operating and capital leases, which at inception had a noncancelable term of more than one year, were as follows:



		At December 31
		Operating Leases		Capital Leases
Year	2016	$	846	$	23
	2017	689		21
	2018	554		19
	2019	420		19
	2020	311		6
	Thereafter	528		62
Total		$	3,348	$	150
Less: Amounts representing interest and executory costs				$	(53	)
Net present values				97
Less: Capital lease obligations included in short-term debt				(17		)
Long-term capital lease obligations				$	80

Note 7

Summarized Financial Data – Chevron U.S.A. Inc.

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



	Year ended December 31
	2015			2014		2013
Sales and other operating revenues	$	97,766		$	157,198	$	174,318
Total costs and other deductions	101,565			153,139		169,984
Net income (loss) attributable to CUSA	(1,054		)	3,849		3,714




	2015		2014
Current assets	$	9,732	$	13,724
Other assets	59,170		62,195
Current liabilities	13,664		16,191
Other liabilities	29,100		30,175
Total CUSA net equity	$	26,138	$	29,553

Memo: Total debt	$	14,462	$	14,473

FS--33

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Note 8

Summarized Financial Data – Tengizchevroil LLP

Chevron has a 50 percent equity ownership interest in Tengizchevroil LLP (TCO). Refer to Note 15, beginning on page FS-40, for a discussion of TCO operations. Summarized financial information for 100 percent of TCO is presented in the table below:



	Year ended December 31
	2015		2014		2013
Sales and other operating revenues	$	12,811	$	22,813	$	25,239
Costs and other deductions	7,257		10,275		11,173
Net income attributable to TCO	3,897		8,772		9,855



	At December 31
	2015		2014
Current assets	$	2,098	$	3,425
Other assets	17,094		14,810
Current liabilities	1,063		1,531
Other liabilities	2,266		2,375
Total TCO net equity	$	15,863	$	14,329

Note 9

Fair Value Measurements

The tables below and on the next page show the fair value hierarchy for assets and liabilities measured at fair value on a recurring and nonrecurring basis at December 31, 2015, and December 31, 2014.

Marketable Securities The company calculates fair value for its marketable securities based on quoted market prices for identical assets. The fair values reflect the cash that would have been received if the instruments were sold at December 31, 2015.

Derivatives The company records its derivative instruments – other than any commodity derivative contracts that are designated as normal purchase and normal sale – on the Consolidated Balance Sheet at fair value, with the offsetting amount to the Consolidated Statement of Income. Derivatives classified as Level 1 include futures, swaps and options contracts traded in active markets such as the New York Mercantile Exchange. Derivatives classified as Level 2 include swaps, options and forward contracts principally with financial institutions and other oil and gas companies, the fair values of which are obtained from third-party broker quotes, industry pricing services and exchanges. The company obtains multiple sources of pricing information for the Level 2 instruments. Since this pricing information is generated from observable market data, it has historically been very consistent. The company does not materially adjust this information.

Properties, Plant and Equipment The company reported impairments for certain oil and gas properties during 2015 primarily as a result of downward revisions in the company's longer-term crude oil price outlook. The impairments were primarily in Brazil and the United States. The company reported impairments for certain oil and gas properties and a mining asset in 2014.

Investments and Advances The company did not have any material investments and advances measured at fair value on a nonrecurring basis to report in 2015 or 2014.

Assets and Liabilities Measured at Fair Value on a Recurring Basis



	At December 31, 2015								At December 31, 2014
	Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3
Marketable securities	$	310	$	310	$	—	$	—	$	422	$	422	$	—	$	—
Derivatives	205		189		16		—		413		394		19		—
Total Assets at Fair Value	$	515	$	499	$	16	$	—	$	835	$	816	$	19	$	—
Derivatives	53		47		6		—		84		83		1		—
Total Liabilities at Fair Value	$	53	$	47	$	6	$	—	$	84	$	83	$	1	$	—

FS--34

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis



	At December 31										At December 31
									Before-Tax Loss										Before-Tax Loss
	Total		Level 1		Level 2		Level 3		Year 2015		Total		Level 1		Level 2		Level 3		Year 2014
Properties, plant and equipment, net (held and used)	$	3,051	$	—	$	239	$	2,812	$	3,222	$	947	$	—	$	213	$	734	$	1,249
Properties, plant and equipment, net (held for sale)	937		—		937		—		844		—		—		—		—		25
Investments and advances	75		—		75		—		28		11		—		—		11		41
Total Nonrecurring Assets at Fair Value	$	4,063	$	—	$	1,251	$	2,812	$	4,094	$	958	$	—	$	213	$	745	$	1,315

Assets and Liabilities Not Required to Be Measured at Fair Value The company holds cash equivalents and time deposits in U.S. and non-U.S. portfolios. The instruments classified as cash equivalents are primarily bank time deposits with maturities of 90 days or less and money market funds. “Cash and cash equivalents” had carrying/fair values of $11,022 and $12,785 at December 31, 2015, and December 31, 2014, respectively. The instruments held in “Time deposits” are bank time deposits with maturities greater than 90 days, and had carrying/fair values of zero and $8 at December 31, 2015, and December 31, 2014, respectively. The fair values of cash, cash equivalents and bank time deposits are classified as Level 1 and reflect the cash that would have been received if the instruments were settled at December 31, 2015.

"Cash and cash equivalents” do not include investments with a carrying/fair value of $1,100 and $1,474 at December 31, 2015, and December 31, 2014, respectively. At December 31, 2015, these investments are classified as Level 1 and include restricted funds related to upstream abandonment activities, tax payments, and funds held in escrow for tax-deferred exchanges and asset acquisitions and divestitures, which are reported in “Deferred charges and other assets” on the Consolidated Balance Sheet. Long-term debt of $25,584 and $15,960 at December 31, 2015, and December 31, 2014, had estimated fair values of $25,884 and $16,450, respectively. Long-term debt primarily includes corporate issued bonds. The fair value of corporate bonds is $25,117 and classified as Level 1. The fair value of the other bonds is $767 and classified as Level 2.

The carrying values of short-term financial assets and liabilities on the Consolidated Balance Sheet approximate their fair values. Fair value remeasurements of other financial instruments at December 31, 2015 and 2014, were not material.

Note 10

Financial and Derivative Instruments

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

The company uses derivative commodity instruments traded on the New York Mercantile Exchange and on electronic platforms of the Inter-Continental Exchange and Chicago Mercantile Exchange. In addition, the company enters into swap contracts and option contracts principally with major financial institutions and other oil and gas companies in the “over-the-counter” markets, which are governed by International Swaps and Derivatives Association agreements and other master netting arrangements. Depending on the nature of the derivative transactions, bilateral collateral arrangements may also be required.

Derivative instruments measured at fair value at December 31, 2015, December 31, 2014, and December 31, 2013, and their classification on the Consolidated Balance Sheet and Consolidated Statement of Income are on the next page:

FS--35

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

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



				At December 31
Type of Contract	Balance Sheet Classification	2015		2014
Commodity	Accounts and notes receivable, net	$	200	$	401
Commodity	Long-term receivables, net	5		12
Total Assets at Fair Value		$	205	$	413
Commodity	Accounts payable	$	51	$	57
Commodity	Deferred credits and other noncurrent obligations	2		27
Total Liabilities at Fair Value		$	53	$	84

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



		Gain/(Loss)
Type of Derivative	Statement of	Year ended December 31
Contract	Income Classification	2015			2014			2013
Commodity	Sales and other operating revenues	$	277		$	553		$	(108	)
Commodity	Purchased crude oil and products	30			(17		)	(77		)
Commodity	Other income	(3		)	(32		)	(9		)
		$	304		$	504		$	(194	)

The table below represents gross and net derivative assets and liabilities subject to netting agreements on the Consolidated Balance Sheet at December 31, 2015 and December 31, 2014.

Consolidated Balance Sheet: The Effect of Netting Derivative Assets and Liabilities



	Gross Amount Recognized		Gross Amounts Offset		Net Amounts Presented		Gross Amounts Not Offset		Net Amount
At December 31, 2015	Gross Amount Recognized		Gross Amounts Offset		Net Amounts Presented		Gross Amounts Not Offset		Net Amount
Derivative Assets	$	2,459	$	2,254	$	205	$	—	$	205
Derivative Liabilities	$	2,307	$	2,254	$	53	$	—	$	53
At December 31, 2014
Derivative Assets	$	4,004	$	3,591	$	413	$	7	$	406
Derivative Liabilities	$	3,675	$	3,591	$	84	$	—	$	84

Derivative assets and liabilities are classified on the Consolidated Balance Sheet as accounts and notes receivable, long-term receivables, accounts payable, and deferred credits and other noncurrent obligations. Amounts not offset on the Consolidated Balance Sheet represent positions that do not meet all the conditions for "a right of offset."

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

The trade receivable balances, reflecting the company’s diversified sources of revenue, are dispersed among the company’s broad customer base worldwide. As a result, the company believes concentrations of credit risk are limited. The company routinely assesses the financial strength of its customers. When the financial strength of a customer is not considered sufficient, alternative risk mitigation measures may be deployed, including requiring pre-payments, letters of credit or other acceptable collateral instruments to support sales to customers.

Note 11

Assets Held for Sale

At December 31, 2015, the company classified $1,449 of net properties, plant and equipment as “Assets held for sale” on the Consolidated Balance Sheet. These assets are associated with upstream and downstream operations that are anticipated to be sold in the next 12 months. The revenues and earnings contributions of these assets in 2015 were not material.

FS--36

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Note 12

Equity

Retained earnings at December 31, 2015 and 2014, included approximately $15,010 and $14,512, respectively, for the company’s share of undistributed earnings of equity affiliates.

At December 31, 2015, about 114 million shares of Chevron’s common stock remained available for issuance from the 260 million shares that were reserved for issuance under the Chevron Long-Term Incentive Plan. In addition, approximately 120,753 shares remain available for issuance from the 800,000 shares of the company’s common stock that were reserved for awards under the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan.

Note 13

Earnings Per Share

Basic earnings per share (EPS) is based upon “Net Income Attributable to Chevron Corporation” (“earnings”) and includes the effects of deferrals of salary and other compensation awards that are invested in Chevron stock units by certain officers and employees of the company. Diluted EPS includes the effects of these items as well as the dilutive effects of outstanding stock options awarded under the company’s stock option programs (refer to Note 22, “Stock Options and Other Share-Based Compensation,” beginning on page FS-50). The table below sets forth the computation of basic and diluted EPS:



	Year ended December 31
	2015		2014		2013
Basic EPS Calculation
Earnings available to common stockholders - Basic^*	$	4,587	$	19,241	$	21,423
Weighted-average number of common shares outstanding	1,867		1,883		1,916
Add: Deferred awards held as stock units	1		1		1
Total weighted-average number of common shares outstanding	1,868		1,884		1,917
Earnings per share of common stock - Basic	$	2.46	$	10.21	$	11.18
Diluted EPS Calculation
Earnings available to common stockholders - Diluted^*	$	4,587	$	19,241	$	21,423
Weighted-average number of common shares outstanding	1,867		1,883		1,916
Add: Deferred awards held as stock units	1		1		1
Add: Dilutive effect of employee stock-based awards	7		14		15
Total weighted-average number of common shares outstanding	1,875		1,898		1,932
Earnings per share of common stock - Diluted	$	2.45	$	10.14	$	11.09

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

Note 14

Operating Segments and Geographic Data

Although each subsidiary of Chevron is responsible for its own affairs, Chevron Corporation manages its investments in these subsidiaries and their affiliates. The investments are grouped into two business segments, Upstream and Downstream, representing the company’s “reportable segments” and “operating segments.” Upstream operations consist primarily of exploring for, developing and producing crude oil and natural gas; liquefaction, transportation and regasification associated with liquefied natural gas (LNG); transporting crude oil by major international oil export pipelines; processing, transporting, storage and marketing of natural gas; and a gas-to-liquids plant. Downstream operations consist primarily of refining of crude oil into petroleum products; marketing of crude oil and refined products; transporting of crude oil and refined products by pipeline, marine vessel, motor equipment and rail car; and manufacturing and marketing of commodity petrochemicals, plastics for industrial uses, and fuel and lubricant additives. All Other activities of the company include worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, and technology companies.

The company’s segments are managed by “segment managers” who report to the “chief operating decision maker” (CODM). The segments represent components of the company that engage in activities (a) from which revenues are earned and expenses are incurred; (b) whose operating results are regularly reviewed by the CODM, which makes decisions about resources to be allocated to the segments and assesses their performance; and (c) for which discrete financial information is available.

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

FS--37

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

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



	Year ended December 31
	2015			2014			2013
Upstream
United States	$	(4,055	)	$	3,327		$	4,044
International	2,094			13,566			16,765
Total Upstream	(1,961		)	16,893			20,809
Downstream
United States	3,182			2,637			787
International	4,419			1,699			1,450
Total Downstream	7,601			4,336			2,237
Total Segment Earnings	5,640			21,229			23,046
All Other
Interest income	65			77			80
Other	(1,118		)	(2,065		)	(1,703		)
Net Income Attributable to Chevron Corporation	$	4,587		$	19,241		$	21,423

Segment Assets Segment assets do not include intercompany investments or receivables. Assets at year-end 2015 and 2014 are as follows:



	At December 31
	2015		2014¹
Upstream
United States	$	46,407	$	49,343
International	163,217		152,736
Goodwill	4,588		4,593
Total Upstream	214,212		206,672
Downstream
United States	21,408		23,068
International	14,982		17,723
Total Downstream	36,390		40,791
Total Segment Assets	250,602		247,463
All Other
United States	5,076		6,603
International	10,425		11,960
Total All Other	15,501		18,563
Total Assets – United States	72,891		79,014
Total Assets – International	188,624		182,419
Goodwill	4,588		4,593
Total Assets	$	266,103	$	266,026

¹2014 conformed to 2015 presentation.

Segment Sales and Other Operating Revenues Operating segment sales and other operating revenues, including internal transfers, for the years 2015, 2014 and 2013, are presented in the table on the next page. Products are transferred between operating segments at internal product values that approximate market prices.

Revenues for the upstream segment are derived primarily from the production and sale of crude oil and natural gas, as well as the sale of third-party production of natural gas. Revenues for the downstream segment are derived from the refining and marketing of petroleum products such as gasoline, jet fuel, gas oils, lubricants, residual fuel oils and other products derived from crude oil. This segment also generates revenues from the manufacture and sale of fuel and lubricant additives and the transportation and trading of refined products and crude oil. "All Other" activities include revenues from insurance operations, real estate activities and technology companies.

FS--38

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts



	Year ended December 31
	2015			2014			2013
Upstream
United States	$	4,117		$	7,455		$	8,052
Intersegment	8,631			15,455			16,865
Total United States	12,748			22,910			24,917
International	15,587			23,808			17,607
Intersegment	11,492			23,107			33,034
Total International	27,079			46,915			50,641
Total Upstream^*	39,827			69,825			75,558
Downstream
United States	48,420			73,942			80,272
Excise and similar taxes	4,426			4,633			4,792
Intersegment	26			31			39
Total United States	52,872			78,606			85,103
International	54,296			86,848			105,373
Excise and similar taxes	2,933			3,553			3,699
Intersegment	1,528			8,839			859
Total International	58,757			99,240			109,931
Total Downstream^*	111,629			177,846			195,034
All Other
United States	141			252			358
Intersegment	1,372			1,475			1,524
Total United States	1,513			1,727			1,882
International	5			3			3
Intersegment	37			28			31
Total International	42			31			34
Total All Other	1,555			1,758			1,916
Segment Sales and Other Operating Revenues
United States	67,133			103,243			111,902
International	85,878			146,186			160,606
Total Segment Sales and Other Operating Revenues	153,011			249,429			272,508
Elimination of intersegment sales	(23,086		)	(48,935		)	(52,352		)
Total Sales and Other Operating Revenues	$	129,925		$	200,494		$	220,156


^*	Effective January 1, 2014, International Upstream prospectively includes selected amounts previously recognized in International Downstream, which are not material to the segments.

Segment Income Taxes Segment income tax expense for the years 2015, 2014 and 2013 is as follows:



	Year ended December 31
	2015			2014			2013
Upstream
United States	$	(2,041	)	$	2,043		$	2,333
International	1,214			9,217			12,470
Total Upstream	(827		)	11,260			14,803
Downstream
United States	1,320			1,302			364
International	1,313			467			389
Total Downstream	2,633			1,769			753
All Other	(1,674		)	(1,137		)	(1,248		)
Total Income Tax Expense	$	132		$	11,892		$	14,308

Other Segment Information Additional information for the segmentation of major equity affiliates is contained in Note 15, on page FS-40. Information related to properties, plant and equipment by segment is contained in Note 16, on page FS-41.

FS--39

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Note 15

Investments and Advances

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



Investments and Advances						Equity in Earnings
	At December 31*					Year ended December 31
	2015			2014		2015			2014			2013
Upstream
Tengizchevroil	$	8,077		$	7,319	$	1,939		$	4,392		$	4,957
Petropiar	679			794		180			26			339
Caspian Pipeline Consortium	1,342			1,487		162			191			113
Petroboscan	1,163			917		219			186			300
Angola LNG Limited	3,284			3,277		(417		)	(311		)	(111		)
Other	2,158			2,316		135			229			214
Total Upstream	16,703			16,110		2,218			4,713			5,812
Downstream
GS Caltex Corporation	3,620			2,867		824			420			132
Chevron Phillips Chemical Company LLC	5,196			5,116		1,367			1,606			1,371
Caltex Australia Ltd.	—			1,161		92			183			224
Other	1,077			1,048		186			180			199
Total Downstream	9,893			10,192		2,469			2,389			1,926
All Other
Other	(18		)	33		(3		)	(4		)	(211		)
Total equity method	$	26,578		$	26,335	$	4,684		$	7,098		$	7,527
Other at or below cost	532			577
Total investments and advances	$	27,110		$	26,912
Total United States	$	6,863		$	6,787	$	1,342		$	1,623		$	1,294
Total International	$	20,247		$	20,125	$	3,342		$	5,475		$	6,233

^*2014 conformed to 2015 presentation.

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

Tengizchevroil Chevron has a 50 percent equity ownership interest in Tengizchevroil (TCO), which operates the Tengiz and Korolev crude oil fields in Kazakhstan. At December 31, 2015, the company’s carrying value of its investment in TCO was about $150 higher than the amount of underlying equity in TCO’s net assets. This difference results from Chevron acquiring a portion of its interest in TCO at a value greater than the underlying book value for that portion of TCO’s net assets. See Note 8, on page FS-34, for summarized financial information for 100 percent of TCO.

Petropiar Chevron has a 30 percent interest in Petropiar, a joint stock company which operates the Hamaca heavy-oil production and upgrading project in Venezuela’s Orinoco Belt. At December 31, 2015, the company’s carrying value of its investment in Petropiar was approximately $160 less than the amount of underlying equity in Petropiar’s net assets. The difference represents the excess of Chevron’s underlying equity in Petropiar’s net assets over the net book value of the assets contributed to the venture.

Caspian Pipeline Consortium Chevron has a 15 percent interest in the Caspian Pipeline Consortium, a variable interest entity, which provides the critical export route for crude oil from both TCO and Karachaganak. The company has investments and advances totaling $1,342, which includes long-term loans of $1,098 at year-end 2015. The loans were provided to fund 30 percent of the initial pipeline construction. The company is not the primary beneficiary of the consortium because it does not direct activities of the consortium and only receives its proportionate share of the financial returns.

Petroboscan Chevron has a 39.2 percent interest in Petroboscan, a joint stock company which operates the Boscan Field in Venezuela. At December 31, 2015, the company’s carrying value of its investment in Petroboscan was approximately $140 higher than the amount of underlying equity in Petroboscan’s net assets. The difference reflects the excess of the net book value of the assets contributed by Chevron over its underlying equity in Petroboscan’s net assets.

Angola LNG Limited Chevron has a 36.4 percent interest in Angola LNG Limited, which processes and liquefies natural gas produced in Angola for delivery to international markets.

FS--40

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

GS Caltex Corporation Chevron owns 50 percent of GS Caltex Corporation, a joint venture with GS Energy. The joint venture imports, refines and markets petroleum products, petrochemicals and lubricants, predominantly in South Korea.

Chevron Phillips Chemical Company LLC Chevron owns 50 percent of Chevron Phillips Chemical Company LLC. The other half is owned by Phillips 66.

Caltex Australia Ltd. Chevron sold its 50 percent equity ownership interest in Caltex Australia Ltd. (CAL) in second quarter 2015.

Other Information “Sales and other operating revenues” on the Consolidated Statement of Income includes $4,850, $10,404 and $14,635 with affiliated companies for 2015, 2014 and 2013, respectively. “Purchased crude oil and products” includes $4,240, $6,735 and $7,063 with affiliated companies for 2015, 2014 and 2013, respectively.

“Accounts and notes receivable” on the Consolidated Balance Sheet includes $399 and $924 due from affiliated companies at December 31, 2015 and 2014, respectively. “Accounts payable” includes $286 and $345 due to affiliated companies at December 31, 2015 and 2014, respectively.

The following table provides summarized financial information on a 100 percent basis for all equity affiliates as well as Chevron’s total share, which includes Chevron's net loans to affiliates of $410, $874 and $1,129 at December 31, 2015, 2014 and 2013, respectively.



	Affiliates						Chevron Share
Year ended December 31	2015		2014		2013		2015		2014		2013
Total revenues	$	71,389	$	123,003	$	131,875	$	33,492	$	58,937	$	63,101
Income before income tax expense	13,129		20,609		24,075		6,279		9,968		11,108
Net income attributable to affiliates	10,649		14,758		15,594		4,691		7,237		7,845
At December 31
Current assets	$	27,162	$	35,662	$	39,713	$	10,657	$	13,465	$	15,156
Noncurrent assets	71,650		70,817		68,593		26,607		26,053		25,059
Current liabilities	20,559		25,308		29,642		7,351		9,588		11,587
Noncurrent liabilities	18,560		17,983		19,442		3,909		4,211		4,559
Total affiliates' net equity	$	59,693	$	63,188	$	59,222	$	26,004	$	25,719	$	24,069

Note 16

Properties, Plant and Equipment¹



	At December 31												Year ended December 31
	Gross Investment at Cost						Net Investment						Additions at Cost²						Depreciation Expense³
	2015		2014		2013		2015		2014		2013		2015		2014		2013		2015		2014		2013
Upstream
United States	$	93,848	$	96,850	$	89,555	$	43,125	$	45,864	$	41,831	$	6,586	$	9,688	$	8,188	$	8,545	$	5,127	$	4,412
International	208,395		192,637		169,623		127,459		118,926		104,100		19,993		24,920		27,383		10,803		9,688		8,336
Total Upstream	302,243		289,487		259,178		170,584		164,790		145,931		26,579		34,608		35,571		19,348		14,815		12,748
Downstream
United States	23,202		22,640		22,407		10,807		11,019		11,481		696		588		1,154		878		886		780
International	9,177		9,334		9,303		4,090		4,219		4,139		365		530		653		355		396		360
Total Downstream	32,379		31,974		31,710		14,897		15,238		15,620		1,061		1,118		1,807		1,233		1,282		1,140
All Other
United States	5,500		5,673		5,402		2,859		3,077		3,194		357		581		721		439		680		286
International	155		155		143		56		68		84		5		25		23		17		16		12
Total All Other	5,655		5,828		5,545		2,915		3,145		3,278		362		606		744		456		696		298
Total United States	122,550		125,163		117,364		56,791		59,960		56,506		7,639		10,857		10,063		9,862		6,693		5,478
Total International	217,727		202,126		179,069		131,605		123,213		108,323		20,363		25,475		28,059		11,175		10,100		8,708
Total	$	340,277	$	327,289	$	296,433	$	188,396	$	183,173	$	164,829	$	28,002	$	36,332	$	38,122	$	21,037	$	16,793	$	14,186


¹	Other than the United States, Australia and Nigeria, no other country accounted for 10 percent or more of the company’s net properties, plant and equipment (PP&E) in 2015. Australia had $49,205, $41,012 and $31,464 in 2015, 2014, and 2013, respectively. Nigeria had PP&E of $18,773, $19,214 and $18,429 for 2015, 2014 and 2013, respectively.


²	Net of dry hole expense related to prior years’ expenditures of $1,573, $371 and $89 in 2015, 2014 and 2013, respectively.


³	Depreciation expense includes accretion expense of $715, $882 and $627 in 2015, 2014 and 2013, respectively, and impairments of $4,066, $1,274 and $382 in 2015, 2014 and 2013, respectively.

FS--41

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Note 17

Litigation

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

Ecuador

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

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

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

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

FS--42

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

On February 14, 2011, the provincial court in Lago Agrio rendered an adverse judgment in the case. The court rejected Chevron’s defenses to the extent the court addressed them in its opinion. The judgment assessed approximately $8,600 in damages and approximately $900 as an award for the plaintiffs’ representatives. It also assessed an additional amount of approximately $8,600 in punitive damages unless the company issued a public apology within 15 days of the judgment, which Chevron did not do. On February 17, 2011, the plaintiffs appealed the judgment, seeking increased damages, and on March 11, 2011, Chevron appealed the judgment seeking to have the judgment nullified. On January 3, 2012, an appellate panel in the provincial court affirmed the February 14, 2011 decision and ordered that Chevron pay additional attorneys’ fees in the amount of “0.10% of the values that are derived from the decisional act of this judgment.” The plaintiffs filed a petition to clarify and amplify the appellate decision on January 6, 2012, and the court issued a ruling in response on January 13, 2012, purporting to clarify and amplify its January 3, 2012 ruling, which included clarification that the deadline for the company to issue a public apology to avoid the additional amount of approximately $8,600 in punitive damages was within 15 days of the clarification ruling, or February 3, 2012. Chevron did not issue an apology because doing so might be mischaracterized as an admission of liability and would be contrary to facts and evidence submitted at trial. On January 20, 2012, Chevron appealed (called a petition for cassation) the appellate panel’s decision to Ecuador’s National Court of Justice. As part of the appeal, Chevron requested the suspension of any requirement that Chevron post a bond to prevent enforcement under Ecuadorian law of the judgment during the cassation appeal. On February 17, 2012, the appellate panel of the provincial court admitted Chevron’s cassation appeal in a procedural step necessary for the National Court of Justice to hear the appeal. The provincial court appellate panel denied Chevron’s request for suspension of the requirement that Chevron post a bond and stated that it would not comply with the First and Second Interim Awards of the international arbitration tribunal discussed below. On March 29, 2012, the matter was transferred from the provincial court to the National Court of Justice, and on November 22, 2012, the National Court agreed to hear Chevron's cassation appeal. On August 3, 2012, the provincial court in Lago Agrio approved a court-appointed liquidator’s report on damages that calculated the total judgment in the case to be $19,100. On November 13, 2013, the National Court ratified the judgment but nullified the $8,600 punitive damage assessment, resulting in a judgment of $9,500. On December 23, 2013, Chevron appealed the decision to the Ecuador Constitutional Court, Ecuador's highest court. The reporting justice of the Constitutional Court heard oral arguments on the appeal on July 16, 2015.

On July 2, 2013, the provincial court in Lago Agrio issued an embargo order in Ecuador ordering that any funds to be paid by the Government of Ecuador to Chevron to satisfy a $96 award issued in an unrelated action by an arbitral tribunal presiding in the Permanent Court of Arbitration in The Hague under the Rules of the United Nations Commission on International Trade Law must be paid to the Lago Agrio plaintiffs. The award was issued by the tribunal under the United States-Ecuador Bilateral Investment Treaty in an action filed in 2006 in connection with seven breach of contract cases that Texpet filed against the Government of Ecuador between 1991 and 1993. The Government of Ecuador has moved to set aside the tribunal's award. On September 26, 2014, the Supreme Court of the Netherlands issued an opinion denying Ecuador’s set aside request. A Federal District Court for the District of Columbia confirmed the tribunal's award, and on August 4, 2015, a panel of the U.S. Court of Appeals for the District of Columbia Circuit affirmed the District Court's decision. On September 9, 2015, the Court of Appeals denied the Government of Ecuador's request for full appellate court review of the Federal District Court's decision.

Lago Agrio Plaintiffs' Enforcement Actions Chevron has no assets in Ecuador and the Lago Agrio plaintiffs' lawyers have stated in press releases and through other media that they will seek to enforce the Ecuadorian judgment in various countries and otherwise disrupt Chevron's operations. On May 30, 2012, the Lago Agrio plaintiffs filed an action against Chevron Corporation, Chevron Canada Limited, and Chevron Canada Finance Limited in the Ontario Superior Court of Justice in Ontario, Canada, seeking to recognize and enforce the Ecuadorian judgment. On May 1, 2013, the Ontario Superior Court of Justice held that the Court has jurisdiction over Chevron and Chevron Canada Limited for purposes of the action, but stayed the action due to the absence of evidence that Chevron Corporation has assets in Ontario. The Lago Agrio plaintiffs appealed that decision and on December 17, 2013, the Court of Appeals for Ontario affirmed the lower court’s decision on jurisdiction and set aside the stay, allowing the recognition and enforcement action to be heard in the Ontario Superior Court of Justice. Chevron appealed the decision to the Supreme Court of Canada and, on September 4, 2015, the Supreme Court dismissed the appeal and affirmed that the Ontario Superior Court of Justice has jurisdiction over Chevron and Chevron Canada Limited for purposes of the action. The recognition and enforcement proceeding and related preliminary motions are proceeding in the Ontario Superior Court of Justice.

On June 27, 2012, the Lago Agrio plaintiffs filed a complaint against Chevron Corporation in the Superior Court of Justice in Brasilia, Brazil, seeking to recognize and enforce the Ecuadorian judgment. Chevron has answered the complaint. In accordance with Brazilian procedure, the matter was referred to the public prosecutor for a nonbinding opinion of the issues raised in the complaint. On May 13, 2015, the public prosecutor issued its nonbinding opinion and recommended that the Superior Court of Justice reject the plaintiffs' recognition and enforcement request, finding, among other things, that the Lago Agrio judgment was

FS--43

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

procured through fraud and corruption and cannot be recognized in Brazil because it violates Brazilian and international public order.

On October 15, 2012, the provincial court in Lago Agrio issued an ex parte embargo order that purports to order the seizure of assets belonging to separate Chevron subsidiaries in Ecuador, Argentina and Colombia. On November 6, 2012, at the request of the Lago Agrio plaintiffs, a court in Argentina issued a Freeze Order against Chevron Argentina S.R.L. and another Chevron subsidiary, Ingeniero Norberto Priu, requiring shares of both companies to be "embargoed," requiring third parties to withhold 40 percent of any payments due to Chevron Argentina S.R.L. and ordering banks to withhold 40 percent of the funds in Chevron Argentina S.R.L. bank accounts. On December 14, 2012, the Argentinean court rejected a motion to revoke the Freeze Order but modified it by ordering that third parties are not required to withhold funds but must report their payments. The court also clarified that the Freeze Order relating to bank accounts excludes taxes. On January 30, 2013, an appellate court upheld the Freeze Order, but on June 4, 2013 the Supreme Court of Argentina revoked the Freeze Order in its entirety. On December 12, 2013, the Lago Agrio plaintiffs served Chevron with notice of their filing of an enforcement proceeding in the National Court, First Instance, of Argentina. Chevron filed its answer on February 27, 2014, to which the Lago Agrio plaintiffs responded on December 29, 2015.

Chevron continues to believe the provincial court’s judgment is illegitimate and unenforceable in Ecuador, the United States and other countries. The company also believes the judgment is the product of fraud, and contrary to the legitimate scientific evidence. Chevron cannot predict the timing or ultimate outcome of the appeals process in Ecuador or any enforcement action. Chevron expects to continue a vigorous defense of any imposition of liability in the Ecuadorian courts and to contest and defend any and all enforcement actions.

Company's Bilateral Investment Treaty Arbitration Claims Chevron and Texpet filed an arbitration claim in September 2009 against the Republic of Ecuador before an arbitral tribunal presiding in the Permanent Court of Arbitration in The Hague under the Rules of the United Nations Commission on International Trade Law. The claim alleges violations of the Republic of Ecuador’s obligations under the United States–Ecuador Bilateral Investment Treaty (BIT) and breaches of the settlement and release agreements between the Republic of Ecuador and Texpet (described above), which are investment agreements protected by the BIT. Through the arbitration, Chevron and Texpet are seeking relief against the Republic of Ecuador, including a declaration that any judgment against Chevron in the Lago Agrio litigation constitutes a violation of Ecuador’s obligations under the BIT. On February 9, 2011, the Tribunal issued an Order for Interim Measures requiring the Republic of Ecuador to take all measures at its disposal to suspend or cause to be suspended the enforcement or recognition within and without Ecuador of any judgment against Chevron in the Lago Agrio case pending further order of the Tribunal. On January 25, 2012, the Tribunal converted the Order for Interim Measures into an Interim Award. Chevron filed a renewed application for further interim measures on January 4, 2012, and the Republic of Ecuador opposed Chevron’s application and requested that the existing Order for Interim Measures be vacated on January 9, 2012. On February 16, 2012, the Tribunal issued a Second Interim Award mandating that the Republic of Ecuador take all measures necessary (whether by its judicial, legislative or executive branches) to suspend or cause to be suspended the enforcement and recognition within and without Ecuador of the judgment against Chevron and, in particular, to preclude any certification by the Republic of Ecuador that would cause the judgment to be enforceable against Chevron. On February 27, 2012, the Tribunal issued a Third Interim Award confirming its jurisdiction to hear Chevron's arbitration claims. On February 7, 2013, the Tribunal issued its Fourth Interim Award in which it declared that the Republic of Ecuador “has violated the First and Second Interim Awards under the [BIT], the UNCITRAL Rules and international law in regard to the finalization and enforcement subject to execution of the Lago Agrio Judgment within and outside Ecuador, including (but not limited to) Canada, Brazil and Argentina.” The Republic of Ecuador subsequently filed in the District Court of the Hague a request to set aside the Tribunal’s Interim Awards and the First Partial Award (described below), and on January 20, 2016, the District Court denied the Republic's request.

The Tribunal has divided the merits phase of the proceeding into three phases. On September 17, 2013, the Tribunal issued its First Partial Award from Phase One, finding that the settlement agreements between the Republic of Ecuador and Texpet applied to Texpet and Chevron, released Texpet and Chevron from claims based on "collective" or "diffuse" rights arising from Texpet's operations in the former concession area and precluded third parties from asserting collective/diffuse rights environmental claims relating to Texpet's operations in the former concession area but did not preclude individual claims for personal harm. The Tribunal held a hearing on April 29-30, 2014, to address remaining issues relating to Phase One, and on March 12, 2015, it issued a nonbinding decision that the Lago Agrio plaintiffs' complaint, on its face, includes claims not barred by the settlement agreement between the Republic of Ecuador and Texpet. In the same decision, the Tribunal deferred to Phase Two remaining issues from Phase One, including whether the Republic of Ecuador breached the 1995 settlement agreement and the remedies

FS--44

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

that are available to Chevron and Texpet as a result of that breach. Phase Two issues were addressed at a hearing held in April and May 2015. The Tribunal has not set a date for Phase Three, the damages phase of the arbitration.

Company's RICO Action Through a series of U.S. court proceedings initiated by Chevron to obtain discovery relating to the Lago Agrio litigation and the BIT arbitration, Chevron obtained evidence that it believes shows a pattern of fraud, collusion, corruption, and other misconduct on the part of several lawyers, consultants and others acting for the Lago Agrio plaintiffs. In February 2011, Chevron filed a civil lawsuit in the Federal District Court for the Southern District of New York against the Lago Agrio plaintiffs and several of their lawyers, consultants and supporters, alleging violations of the Racketeer Influenced and Corrupt Organizations Act and other state laws. Through the civil lawsuit, Chevron is seeking relief that includes a declaration that any judgment against Chevron in the Lago Agrio litigation is the result of fraud and other unlawful conduct and is therefore unenforceable. On March 7, 2011, the Federal District Court issued a preliminary injunction prohibiting the Lago Agrio plaintiffs and persons acting in concert with them from taking any action in furtherance of recognition or enforcement of any judgment against Chevron in the Lago Agrio case pending resolution of Chevron’s civil lawsuit by the Federal District Court. On May 31, 2011, the Federal District Court severed claims one through eight of Chevron’s complaint from the ninth claim for declaratory relief and imposed a discovery stay on claims one through eight pending a trial on the ninth claim for declaratory relief. On September 19, 2011, the U.S. Court of Appeals for the Second Circuit vacated the preliminary injunction, stayed the trial on Chevron’s ninth claim, a claim for declaratory relief, that had been set for November 14, 2011, and denied the defendants’ mandamus petition to recuse the judge hearing the lawsuit. The Second Circuit issued its opinion on January 26, 2012 ordering the dismissal of Chevron’s ninth claim for declaratory relief. On February 16, 2012, the Federal District Court lifted the stay on claims one through eight, and on October 18, 2012, the Federal District Court set a trial date of October 15, 2013. On March 22, 2013, Chevron settled its claims against Stratus Consulting, and on April 12, 2013 sworn declarations by representatives of Stratus Consulting were filed with the Court admitting their role and that of the plaintiffs' attorneys in drafting the environmental report of the mining engineer appointed by the provincial court in Lago Agrio. On September 26, 2013, the Second Circuit denied the defendants' Petition for Writ of Mandamus to recuse the judge hearing the case and to collaterally estop Chevron from seeking a declaration that the Lago Agrio judgment was obtained through fraud and other unlawful conduct.

The trial commenced on October 15, 2013 and concluded on November 22, 2013. On March 4, 2014, the Federal District Court entered a judgment in favor of Chevron, prohibiting the defendants from seeking to enforce the Lago Agrio judgment in the United States and further prohibiting them from profiting from their illegal acts. The defendants appealed the Federal District Court's decision, and, on April 20, 2015, a panel of the U.S. Court of Appeals for the Second Circuit heard oral arguments.

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

Note 18

Taxes



Income Taxes	Year ended December 31
	2015			2014		2013
Income tax expense (benefit)
U.S. federal
Current	$	(817	)	$	748	$	15
Deferred	(580		)	1,330		1,128
State and local
Current	(187		)	336		120
Deferred	(109		)	36		74
Total United States	(1,693		)	2,450		1,337
International
Current	2,997			9,235		12,296
Deferred	(1,172		)	207		675
Total International	1,825			9,442		12,971
Total income tax expense (benefit)	$	132		$	11,892	$	14,308

FS--45

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

In 2015, before-tax loss for U.S. operations, including related corporate and other charges, was $(2,877), compared with before-tax income of $6,296 and $4,672 in 2014 and 2013, respectively. For international operations, before-tax income was $7,719, $24,906 and $31,233 in 2015, 2014 and 2013, respectively. U.S. federal income tax expense was reduced by $35, $68 and $175 in 2015, 2014 and 2013, respectively, for business tax credits.

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



	Year ended December 31
	2015			2014			2013
U.S. statutory federal income tax rate	35.0		%	35.0		%	35.0		%
Effect of income taxes from international operations¹	(25.1	)		2.1			4.4
State and local taxes on income, net of U.S. federal income tax benefit	(1.5	)		0.7			0.6
Tax credits	(0.7	)		(0.2	)		(0.5	)
Other^1,2	(5.0	)		0.5			0.4
Effective tax rate	2.7		%	38.1		%	39.9		%

¹2013 and 2014 conformed to 2015 presentation.

² 2015 includes one-time tax benefits associated with changes in uncertain tax positions and provision-to-return adjustments.

The company’s effective tax rate decreased from 38.1 percent in 2014 to 2.7 percent in 2015. The decrease primarily resulted from the impacts of jurisdictional mix, one-time tax benefits, foreign currency remeasurement, equity earnings and a reduction in statutory tax rates in the United Kingdom, partially offset by the effects of valuation allowances recognized on deferred tax assets and the sale of the company's interest in Caltex Australia Limited.

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



	At December 31
	2015			2014
Deferred tax liabilities
Properties, plant and equipment	$	27,044		$	28,452
Investments and other	3,743			3,059
Total deferred tax liabilities	30,787			31,511
Deferred tax assets
Foreign tax credits	(10,534		)	(11,867		)
Abandonment/environmental reserves	(6,880		)	(6,686		)
Employee benefits	(4,801		)	(4,831		)
Deferred credits	(1,810		)	(1,828		)
Tax loss carryforwards	(2,748		)	(1,747		)
Other accrued liabilities	(525		)	(498		)
Inventory	(120		)	(153		)
Miscellaneous	(2,525		)	(2,128		)
Total deferred tax assets	(29,943		)	(29,738		)
Deferred tax assets valuation allowance	15,412			16,292
Total deferred taxes, net	$	16,256		$	18,065

Deferred tax liabilities at the end of 2015 decreased by approximately $700 from year-end 2014. The decrease was primarily related to decreased temporary differences related to property, plant and equipment. Deferred tax assets were essentially unchanged between periods. A reduction in U.S. foreign tax credits was substantially offset by an increase in foreign tax loss carryforwards.

The overall valuation allowance relates to deferred tax assets for U.S. foreign tax credit carryforwards, tax loss carryforwards and temporary differences. It reduces the deferred tax assets to amounts that are, in management’s assessment, more likely than not to be realized. At the end of 2015, the company had tax loss carryforwards of approximately $7,615 and tax credit carryforwards of approximately $1,249, primarily related to various international tax jurisdictions. Whereas some of these tax loss carryforwards do not have an expiration date, others expire at various times from 2016 through 2025. U.S. foreign tax credit carryforwards of $10,534 will expire between 2017 and 2024.

FS--46

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

At December 31, 2015 and 2014, deferred taxes were classified on the Consolidated Balance Sheet as follows:



	At December 31
	2015			2014
Prepaid expenses and other current assets	$	(917	)	$	(1,071	)
Deferred charges and other assets	(4,512		)	(3,597		)
Federal and other taxes on income	996			813
Noncurrent deferred income taxes	20,689			21,920
Total deferred income taxes, net	$	16,256		$	18,065

Income taxes are not accrued for unremitted earnings of international operations that have been or are intended to be reinvested indefinitely. Undistributed earnings of international consolidated subsidiaries and affiliates for which no deferred income tax provision has been made for possible future remittances totaled approximately $45,400 at December 31, 2015. This amount represents earnings reinvested as part of the company’s ongoing international business. It is not practicable to estimate the amount of taxes that might be payable on the possible remittance of earnings that are intended to be reinvested indefinitely. At the end of 2015, deferred income taxes were recorded for the undistributed earnings of certain international operations where indefinite reinvestment of the earnings is not planned. The company does not anticipate incurring significant additional taxes on remittances of earnings that are not indefinitely reinvested.

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

The following table indicates the changes to the company’s unrecognized tax benefits for the years ended December 31, 2015, 2014 and 2013. The term “unrecognized tax benefits” in the accounting standards for income taxes refers to the differences between a tax position taken or expected to be taken in a tax return and the benefit measured and recognized in the financial statements. Interest and penalties are not included.



	2015			2014			2013
Balance at January 1	$	3,552		$	3,848		$	3,071
Foreign currency effects	(27		)	(25		)	(58		)
Additions based on tax positions taken in current year	154			354			276
Additions/reductions resulting from current-year asset acquisitions/sales	—			(22		)	—
Additions for tax positions taken in prior years	218			37			1,164
Reductions for tax positions taken in prior years	(678		)	(561		)	(176		)
Settlements with taxing authorities in current year	(5		)	(50		)	(320		)
Reductions as a result of a lapse of the applicable statute of limitations	(172		)	(29		)	(109		)
Balance at December 31	$	3,042		$	3,552		$	3,848

The decrease in unrecognized tax benefits between December 31, 2014, and December 31, 2015 was primarily due to the resolution of numerous audit issues with various tax jurisdictions during the year.

Approximately 71 percent of the $3,042 of unrecognized tax benefits at December 31, 2015, would have an impact on the effective tax rate if subsequently recognized. Certain of these unrecognized tax benefits relate to tax carryforwards that may require a full valuation allowance at the time of any such recognition.

Tax positions for Chevron and its subsidiaries and affiliates are subject to income tax audits by many tax jurisdictions throughout the world. For the company’s major tax jurisdictions, examinations of tax returns for certain prior tax years had not been completed as of December 31, 2015. For these jurisdictions, the latest years for which income tax examinations had been finalized were as follows: United States – 2011, Nigeria – 2000, Angola – 2009, Saudi Arabia – 2012 and Kazakhstan – 2007.

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

FS--47

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

On the Consolidated Statement of Income, the company reports interest and penalties related to liabilities for uncertain tax positions as “Income tax expense.” As of December 31, 2015, accruals of $399 for anticipated interest and penalty obligations were included on the Consolidated Balance Sheet, compared with accruals of $233 as of year-end 2014. Income tax expense (benefit) associated with interest and penalties was $195, $4 and $(42) in 2015, 2014 and 2013, respectively.

Taxes Other Than on Income



	Year ended December 31
	2015		2014		2013
United States
Excise and similar taxes on products and merchandise	$	4,426	$	4,633	$	4,792
Import duties and other levies	4		6		4
Property and other miscellaneous taxes	1,367		1,002		1,036
Payroll taxes	270		273		255
Taxes on production	157		349		333
Total United States	6,224		6,263		6,420
International
Excise and similar taxes on products and merchandise	2,933		3,553		3,700
Import duties and other levies	40		45		41
Property and other miscellaneous taxes	2,548		2,277		2,486
Payroll taxes	161		172		168
Taxes on production	124		230		248
Total International	5,806		6,277		6,643
Total taxes other than on income	$	12,030	$	12,540	$	13,063

Note 19

Short-Term Debt



	At December 31
	2015			2014
Commercial paper^*	$	8,252		$	8,506
Notes payable to banks and others with originating terms of one year or less	20			104
Current maturities of long-term debt	1,487			—
Current maturities of long-term capital leases	17			22
Redeemable long-term obligations
Long-term debt	3,152			3,152
Capital leases	—			6
Subtotal	12,928			11,790
Reclassified to long-term debt	(8,000		)	(8,000		)
Total short-term debt	$	4,928		$	3,790


^*	Weighted-average interest rates at December 31, 2015 and 2014, were 0.26 percent and 0.12 percent, respectively.

Redeemable long-term obligations consist primarily of tax-exempt variable-rate put bonds that are included as current liabilities because they become redeemable at the option of the bondholders during the year following the balance sheet date.

The company may periodically enter into interest rate swaps on a portion of its short-term debt. At December 31, 2015, the company had no interest rate swaps on short-term debt.

At December 31, 2015, the company had $8,000 in committed credit facilities with various major banks that enable the refinancing of short-term obligations on a long-term basis. The credit facilities consist of a 364-day facility which enables borrowing of up to $6,000 and can be renewed for an additional 364-day period or the company can convert any amounts outstanding into a term loan for a period of up to one year, and a $2,000 five-year facility expiring in December 2020. These facilities support commercial paper borrowing and can also be used for general corporate purposes. The company’s practice has been to continually replace expiring commitments with new commitments on substantially the same terms, maintaining levels management believes appropriate. Any borrowings under the facilities would be unsecured indebtedness at interest rates based on the London Interbank Offered Rate or an average of base lending rates published by specified banks and on terms reflecting the company’s strong credit rating. No borrowings were outstanding under these facilities at December 31, 2015.

At both December 31, 2015 and 2014, the company classified $8,000 of short-term debt as long-term. Settlement of these obligations is not expected to require the use of working capital within one year, and the company has both the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis.

FS--48

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Note 20

Long-Term Debt

Total long-term debt, excluding capital leases, at December 31, 2015, was $33,584. The company’s long-term debt outstanding at year-end 2015 and 2014 was as follows:



	At December 31
	2015			2014
3.191% notes due 2023	$	2,250		$	2,250
Floating rate notes due 2017 (0.555%)¹	2,050			650
1.104% notes due 2017	2,000			2,000
1.718% notes due 2018	2,000			2,000
2.355% notes due 2022	2,000			2,000
1.365% notes due 2018	1,750			—
1.961% notes due 2020	1,750			—
4.95% notes due 2019	1,500			1,500
1.790% notes due 2018	1,250			—
2.419% notes due 2020	1,250			—
1.345% notes due 2017	1,100			1,100
1.344% notes due 2017	1,000			—
2.427% notes due 2020	1,000			1,000
Floating rate notes due 2018 (0.676%)¹	800			—
0.889% notes due 2016	750			750
2.193% notes due 2019	750			750
3.326% notes due 2025	750			—
2.411% notes due 2022	700			—
Floating rate notes due 2016 (0.444%)²	700			700
Floating rate notes due 2019 (0.772%)²	400			400
Floating rate notes due 2021 (0.892%)²	400			400
Floating rate notes due 2022 (0.952%)²	350			—
8.625% debentures due 2032	147			147
Amortizing Bank Loan due 2018 (1.172%)²	110			—
8.625% debentures due 2031	108			107
8.0% debentures due 2032	74			74
9.75% debentures due 2020	54			54
8.875% debentures due 2021	40			40
Medium-term notes, maturing from 2021 to 2038 (5.975%)¹	38			38
Total including debt due within one year	27,071			15,960
Debt due within one year	(1,487		)	—
Reclassified from short-term debt	8,000			8,000
Total long-term debt	$	33,584		$	23,960


¹	Weighted-average interest rate at December 31, 2015.


²	Interest rate at December 31, 2015.

Chevron has an automatic shelf registration statement that expires in August 2018. This registration statement is for an unspecified amount of nonconvertible debt securities issued or guaranteed by the company.

Long-term debt of $27,071 matures as follows: 2016 – $1,487; 2017 – $6,187; 2018 – $5,836; 2019 – $2,650; 2020 – $4,054; and after 2020 – $6,857.

The company completed bond issuances of $6,000 and $5,000 in March and November 2015, respectively.

See Note 9, beginning on page FS-34, for information concerning the fair value of the company’s long-term debt.

Note 21

Accounting for Suspended Exploratory Wells

The company continues to capitalize exploratory well costs after the completion of drilling when (a) the well has found a sufficient quantity of reserves to justify completion as a producing well, and (b) the business unit is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met or if the company obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well would be assumed to be impaired, and its costs, net of any salvage value, would be charged to expense.

FS--49

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

The following table indicates the changes to the company’s suspended exploratory well costs for the three years ended December 31, 2015:



	2015			2014			2013
Beginning balance at January 1	$	4,195		$	3,245		$	2,681
Additions to capitalized exploratory well costs pending the determination of proved reserves	869			1,591			885
Reclassifications to wells, facilities and equipment based on the determination of proved reserves	(164		)	(298		)	(290		)
Capitalized exploratory well costs charged to expense	(1,397		)	(312		)	(31		)
Other reductions^*	(191		)	(31		)	—
Ending balance at December 31	$	3,312		$	4,195		$	3,245

^*Represents property sales.

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



	At December 31
	2015		2014		2013
Exploratory well costs capitalized for a period of one year or less	$	489	$	1,522	$	641
Exploratory well costs capitalized for a period greater than one year	2,823		2,673		2,604
Balance at December 31	$	3,312	$	4,195	$	3,245
Number of projects with exploratory well costs that have been capitalized for a period greater than one year^*	39		51		51

^*Certain projects have multiple wells or fields or both.

Of the $2,823 of exploratory well costs capitalized for more than one year at December 31, 2015, $1,662 (20 projects) is related to projects that had drilling activities under way or firmly planned for the near future. The $1,161 balance is related to 19 projects in areas requiring a major capital expenditure before production could begin and for which additional drilling efforts were not under way or firmly planned for the near future. Additional drilling was not deemed necessary because the presence of hydrocarbons had already been established, and other activities were in process to enable a future decision on project development.

The projects for the $1,161 referenced above had the following activities associated with assessing the reserves and the projects’ economic viability: (a) $190 (two projects) – undergoing front-end engineering and design with final investment decision expected within four years; (b) $99 (one project) – development concept under review by government; (c) $814 (seven projects) – development alternatives under review; (d) $58 (nine projects) – miscellaneous activities for projects with smaller amounts suspended. While progress was being made on all 39 projects, the decision on the recognition of proved reserves under SEC rules in some cases may not occur for several years because of the complexity, scale and negotiations associated with the projects. Approximately half of these decisions are expected to occur in the next five years.

The $2,823 of suspended well costs capitalized for a period greater than one year as of December 31, 2015, represents 165 exploratory wells in 39 projects. The tables below contain the aging of these costs on a well and project basis:



Aging based on drilling completion date of individual wells:	Amount		Number of wells
1998-2004	$	285	26
2005-2009	395		33
2010-2014	2,143		106
Total	$	2,823	165

Aging based on drilling completion date of last suspended well in project:	Amount		Number of projects
2003-2007	$	200	4
2008-2011	393		6
2012-2015	2,230		29
Total	$	2,823	39

Note 22

Stock Options and Other Share-Based Compensation

Compensation expense for stock options for 2015, 2014 and 2013 was $312 ($203 after tax), $287 ($186 after tax) and $292 ($190 after tax), respectively. In addition, compensation expense for stock appreciation rights, restricted stock, performance units and restricted stock units was $32 ($21 after tax), $71 ($46 after tax) and $223 ($145 after tax) for 2015, 2014 and 2013, respectively. No significant stock-based compensation cost was capitalized at December 31, 2015, or December 31, 2014.

FS--50

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Cash received in payment for option exercises under all share-based payment arrangements for 2015, 2014 and 2013 was $195, $527 and $553, respectively. Actual tax benefits realized for the tax deductions from option exercises were $17, $54 and $73 for 2015, 2014 and 2013, respectively.

Cash paid to settle performance units and stock appreciation rights was $104, $204 and $186 for 2015, 2014 and 2013, respectively.

Awards under the Chevron Long-Term Incentive Plan (LTIP) may take the form of, but are not limited to, stock options, restricted stock, restricted stock units, stock appreciation rights, performance units and nonstock grants. From April 2004 through May 2023, no more than 260 million shares may be issued under the LTIP. For awards issued on or after May 29, 2013, no more than 50 million of those shares may be in a form other than a stock option, stock appreciation right or award requiring full payment for shares by the award recipient. For the major types of awards outstanding as of December 31, 2015, the contractual terms vary between three years for the performance units and restricted stock units, and 10 years for the stock options and stock appreciation rights.

Remaining awards under the Unocal Share-Based Plans expired in early 2015.

The fair market values of stock options and stock appreciation rights granted in 2015, 2014 and 2013 were measured on the date of grant using the Black-Scholes option-pricing model, with the following weighted-average assumptions:



	Year ended December 31
	2015			2014			2013
Expected term in years¹	6.1			6.0			6.0
Volatility²	21.9		%	30.3		%	31.3		%
Risk-free interest rate based on zero coupon U.S. treasury note	1.4		%	1.9		%	1.2		%
Dividend yield	3.6		%	3.3		%	3.3		%
Weighted-average fair value per option granted	$	13.89		$	25.86		$	24.48

¹Expected term is based on historical exercise and postvesting cancellation data.

²Volatility rate is based on historical stock prices over an appropriate period, generally equal to the expected term.

A summary of option activity during 2015 is presented below:



	Shares (Thousands)		Weighted-Average Exercise Price			Averaged Remaining Contractual Term (Years)	Aggregate Intrinsic Value
Outstanding at January 1, 2015	78,341			$	93.59
Granted	22,126			$	103.71
Exercised	(3,104	)		$	62.06
Forfeited	(3,071	)		$	103.70
Outstanding at December 31, 2015	94,292			$	96.67	5.83		$	467
Exercisable at December 31, 2015	65,657			$	91.85	4.61		$	467

The total intrinsic value (i.e., the difference between the exercise price and the market price) of options exercised during 2015, 2014 and 2013 was $120, $398 and $445, respectively. During this period, the company continued its practice of issuing treasury shares upon exercise of these awards.

As of December 31, 2015, there was $190 of total unrecognized before-tax compensation cost related to nonvested share-based compensation arrangements granted under the plans. That cost is expected to be recognized over a weighted-average period of 1.7 years.

At January 1, 2015, the number of LTIP performance units outstanding was equivalent to 2,265,952 shares. During 2015, 890,000 units were granted, 828,868 units vested with cash proceeds distributed to recipients and 134,147 units were forfeited. At December 31, 2015, units outstanding were 2,192,937. The fair value of the liability recorded for these instruments was $166, and was measured using the Monte Carlo simulation method. In addition, outstanding stock appreciation rights and other awards that were granted under various LTIP programs totaled approximately 4.5 million equivalent shares as of December 31, 2015. A liability of $51 was recorded for these awards.

Note 23

Employee Benefit Plans

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

FS--51

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

because contributions to these pension plans may be less economic and investment returns may be less attractive than the company’s other investment alternatives.

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

The company recognizes the overfunded or underfunded status of each of its defined benefit pension and OPEB plans as an asset or liability on the Consolidated Balance Sheet.

The funded status of the company’s pension and OPEB plans for 2015 and 2014 follows:



	Pension Benefits
	2015						2014						Other Benefits
	U.S.			Int’l.			U.S.			Int’l.			2015			2014
Change in Benefit Obligation
Benefit obligation at January 1	$	14,250		$	5,767		$	12,080		$	6,095		$	3,660		$	3,138
Service cost	538			185			450			190			72			50
Interest cost	502			277			494			340			151			148
Plan participants' contributions	—			6			—			8			148			150
Plan amendments	—			(6		)	—			3			—			2
Actuarial (gain) loss	(345		)	(309		)	2,299			336			(326		)	544
Foreign currency exchange rate changes	—			(326		)	—			(348		)	(37		)	(22		)
Benefits paid	(1,382		)	(241		)	(1,073		)	(293		)	(344		)	(350		)
Divestitures	—			—			—			(564		)	—			—
Curtailment	—			(17		)	—			—			—			—
Benefit obligation at December 31	13,563			5,336			14,250			5,767			3,324			3,660
Change in Plan Assets
Fair value of plan assets at January 1	11,090			4,244			11,210			4,543			—			—
Actual return on plan assets	(75		)	112			854			571			—			—
Foreign currency exchange rate changes	—			(239		)	—			(279		)	—			—
Employer contributions	641			227			99			276			196			200
Plan participants' contributions	—			6			—			8			148			150
Benefits paid	(1,382		)	(241		)	(1,073		)	(293		)	(344		)	(350		)
Divestitures	—			—			—			(582		)	—			—
Fair value of plan assets at December 31	10,274			4,109			11,090			4,244			—			—
Funded Status at December 31	$	(3,289	)	$	(1,227	)	$	(3,160	)	$	(1,523	)	$	(3,324	)	$	(3,660	)

Amounts recognized on the Consolidated Balance Sheet for the company’s pension and OPEB plans at December 31, 2015 and 2014, include:



	Pension Benefits
	2015						2014						Other Benefits
	U.S.			Int’l.			U.S.			Int’l.			2015			2014
Deferred charges and other assets	$	13		$	333		$	13		$	244		$	—		$	—
Accrued liabilities	(153		)	(77		)	(123		)	(68		)	(191		)	(198		)
Noncurrent employee benefit plans	(3,149		)	(1,483		)	(3,050		)	(1,699		)	(3,133		)	(3,462		)
Net amount recognized at December 31	$	(3,289	)	$	(1,227	)	$	(3,160	)	$	(1,523	)	$	(3,324	)	$	(3,660	)

Amounts recognized on a before-tax basis in “Accumulated other comprehensive loss” for the company’s pension and OPEB plans were $6,478 and $7,417 at the end of 2015 and 2014, respectively. These amounts consisted of:



	Pension Benefits
	2015					2014					Other Benefits
	U.S.			Int’l.		U.S.			Int’l.		2015		2014
Net actuarial loss	$	4,809		$	1,143	$	4,972		$	1,487	$	367	$	763
Prior service (credit) costs	(5		)	120		(13		)	150		44		58
Total recognized at December 31	$	4,804		$	1,263	$	4,959		$	1,637	$	411	$	821

FS--52

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

The accumulated benefit obligations for all U.S. and international pension plans were $12,032 and $4,684, respectively, at December 31, 2015, and $12,833 and $4,995, respectively, at December 31, 2014.

Information for U.S. and international pension plans with an accumulated benefit obligation in excess of plan assets at December 31, 2015 and 2014, was:



	Pension Benefits
	2015				2014
	U.S.		Int’l.		U.S.		Int’l.
Projected benefit obligations	$	13,500	$	1,623	$	14,182	$	1,938
Accumulated benefit obligations	11,969		1,357		12,765		1,525
Fair value of plan assets	10,198		207		11,009		262

The components of net periodic benefit cost and amounts recognized in the Consolidated Statement of Comprehensive Income for 2015, 2014 and 2013 are shown in the table below:



	Pension Benefits
	2015						2014						2013						Other Benefits
	U.S.			Int’l.			U.S.			Int’l.			U.S.			Int’l.			2015			2014			2013
Net Periodic Benefit Cost
Service cost	$	538		$	185		$	450		$	190		$	495		$	197		$	72		$	50		$	66
Interest cost	502			277			494			340			471			314			151			148			149
Expected return on plan assets	(783		)	(262		)	(788		)	(298		)	(701		)	(274		)	—			—			—
Amortization of prior service costs (credits)	(8		)	22			(9		)	21			2			21			14			14			(50		)
Recognized actuarial losses	356			78			209			96			485			143			34			7			53
Settlement losses	320			6			237			208			173			12			—			—			—
Curtailment losses (gains)	—			(14		)	—			—			—			—			—			—			—
Total net periodic benefit cost	925			292			593			557			925			413			271			219			218
Changes Recognized in Comprehensive Income
Net actuarial (gain) loss during period	513			(260		)	2,233			(17		)	(2,244		)	(476		)	(362		)	514			(659		)
Amortization of actuarial loss	(676		)	(84		)	(446		)	(304		)	(658		)	(155		)	(34		)	(7		)	(53		)
Prior service (credits) costs during period	—			(6		)	—			4			(78		)	18			—			2			—
Amortization of prior service (costs) credits	8			(24		)	9			(21		)	(2		)	(21		)	(14		)	(14		)	50
Total changes recognized in other comprehensive income	(155		)	(374		)	1,796			(338		)	(2,982		)	(634		)	(410		)	495			(662		)
Recognized in Net Periodic Benefit Cost and Other Comprehensive Income	$	770		$	(82	)	$	2,389		$	219		$	(2,057	)	$	(221	)	$	(139	)	$	714		$	(444	)

Net actuarial losses recorded in “Accumulated other comprehensive loss” at December 31, 2015, for the company’s U.S. pension, international pension and OPEB plans are being amortized on a straight-line basis over approximately 10, 10 and 16 years, respectively. These amortization periods represent the estimated average remaining service of employees expected to receive benefits under the plans. These losses are amortized to the extent they exceed 10 percent of the higher of the projected benefit obligation or market-related value of plan assets. The amount subject to amortization is determined on a plan-by-plan basis. During 2016, the company estimates actuarial losses of $335, $56 and $19 will be amortized from “Accumulated other comprehensive loss” for U.S. pension, international pension and OPEB plans, respectively. In addition, the company estimates an additional $324 will be recognized from “Accumulated other comprehensive loss” during 2016 related to lump-sum settlement costs from the main U.S. pension plan.

The weighted average amortization period for recognizing prior service costs (credits) recorded in “Accumulated other comprehensive loss” at December 31, 2015, was approximately 4 and 11 years for U.S. and international pension plans, respectively, and 7 years for OPEB plans. During 2016, the company estimates prior service (credits) costs of $(9), $15 and $14 will be amortized from “Accumulated other comprehensive loss” for U.S. pension, international pension and OPEB plans, respectively.

FS--53

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

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



	Pension Benefits
	2015				2014				2013						Other Benefits
	U.S.		Int’l.		U.S.		Int’l.		U.S.		Int’l.		2015		2014		2013
Assumptions used to determine benefit obligations:
Discount rate	4.0	%	5.3	%	3.7	%	5.0	%	4.3	%	5.8	%	4.6	%	4.3	%	4.9	%
Rate of compensation increase	4.5	%	4.8	%	4.5	%	5.1	%	4.5	%	5.5	%	N/A		N/A		N/A
Assumptions used to determine net periodic benefit cost:
Discount rate	3.7	%	5.0	%	4.3	%	5.8	%	3.6	%	5.2	%	4.3	%	4.9	%	4.1	%
Expected return on plan assets	7.5	%	6.3	%	7.5	%	6.6	%	7.5	%	6.8	%	N/A		N/A		N/A
Rate of compensation increase	4.5	%	5.1	%	4.5	%	5.5	%	4.5	%	5.5	%	N/A		N/A		N/A

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

For 2015, the company used an expected long-term rate of return of 7.5 percent for U.S. pension plan assets, which account for 71 percent of the company’s pension plan assets. In both 2014 and 2013, the company used a long-term rate of return of 7.5 percent for this plan.

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

Discount Rate The discount rate assumptions used to determine the U.S. and international pension and OPEB plan obligations and expense reflect the rate at which benefits could be effectively settled, and are equal to the equivalent single rate resulting from yield curve analysis. This analysis considered the projected benefit payments specific to the company's plans and the yields on high-quality bonds. At December 31, 2015, the projected cash flows were discounted to the valuation date using the yield curve for the main U.S. pension and OPEB plans. The effective discount rates derived from this analysis were 4.0 percent for the main U.S. pension plan and 4.5 percent for the main U.S. OPEB plan. The discount rates for these plans at the end of 2014 were 3.7 and 4.1 percent, respectively, while in 2013 they were 4.3 and 4.7 percent for these plans, respectively.

The company changed the method used to estimate the service and interest costs associated with the company’s main U.S. pension and OPEB plans. In prior years, the service and interest costs were estimated utilizing a single weighted-average discount rate derived from the yield curve used to measure the defined benefit obligations at the beginning of the year. Under the new method, these costs are estimated by applying spot rates along the yield curve to the relevant projected cash flows. The change was made to provide a more precise measurement of the service and interest costs by improving the correlation between projected benefit cash flows and the corresponding spot yield curve rates. This change in accounting estimate is accounted for prospectively beginning with the year ending December 31, 2016. The company does not expect the change to have a material effect on its consolidated financial position or liquidity.

Other Benefit Assumptions For the measurement of accumulated postretirement benefit obligation at December 31, 2015, for the main U.S. OPEB plan, the assumed health care cost-trend rates start with 7.1 percent in 2016 and gradually decline to 4.5 percent for 2025 and beyond. For this measurement at December 31, 2014, the assumed health care cost-trend rates started with 7 percent in 2015 and gradually declined to 4.5 percent for 2025 and beyond. In both measurements, the annual increase to company contributions was capped at 4 percent.

Assumed health care cost-trend rates can have a significant effect on the amounts reported for retiree health care costs. The impact is mitigated by the 4 percent cap on the company’s medical contributions for the main U.S. plan. A 1-percentage-point change in the assumed health care cost-trend rates would have the following effects on worldwide plans:



	1 Percent Increase		1 Percent Decrease
Effect on total service and interest cost components	$	20	$	(17	)
Effect on postretirement benefit obligation	$	192	$	(164	)

FS--54

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Plan Assets and Investment Strategy

The fair value measurements of the company’s pension plans for 2015 and 2014 are below:



	U.S.									Int’l.
	Total Fair Value		Level 1			Level 2		Level 3		Total Fair Value		Level 1			Level 2		Level 3
At December 31, 2014
Equities
U.S.¹	$	2,087	$	2,087		$	—	$	—	$	241	$	241		$	—	$	—
International	1,297		1,297			—		—		313		313			—		—
Collective Trusts/Mutual Funds²	3,240		22			3,218		—		979		173			806		—
Fixed Income
Government	84		47			37		—		1,066		53			1,013		—
Corporate	1,502		—			1,502		—		585		26			537		22
Mortgage-Backed Securities	1		—			1		—		1		—			1		—
Other Asset Backed	—		—			—		—		—		—			—		—
Collective Trusts/Mutual Funds²	1,174		—			1,174		—		394		16			378		—
Mixed Funds³	—		—			—		—		122		3			119		—
Real Estate⁴	1,364		—			—		1,364		329		—			—		329
Cash and Cash Equivalents	270		270			—		—		190		189			1		—
Other⁵	71		(3		)	20		54		24		—			21		3
Total at December 31, 2014	$	11,090	$	3,720		$	5,952	$	1,418	$	4,244	$	1,014		$	2,876	$	354
At December 31, 2015
Equities
U.S.¹	$	1,699	$	1,699		$	—	$	—	$	392	$	382		$	10	$	—
International	1,302		1,296			6		—		457		435			22		—
Collective Trusts/Mutual Funds²	2,460		18			2,442		—		572		7			565		—
Fixed Income
Government	257		46			211		—		1,089		93			996		—
Corporate	1,654		—			1,654		—		615		33			557		25
Bank Loans	148		—			148		—		—		—			—		—
Mortgage-Backed Securities	1		—			1		—		1		—			1		—
Other Asset Backed	1		—			1		—		—		—			—		—
Collective Trusts/Mutual Funds²	933		—			933		—		269		12			257		—
Mixed Funds³	—		—			—		—		85		4			81		—
Real Estate⁴	1,494		—			—		1,494		378		—			—		378
Cash and Cash Equivalents	253		253			—		—		232		232			—		—
Other⁵	72		(6		)	26		52		19		(2		)	19		2
Total at December 31, 2015	$	10,274	$	3,306		$	5,422	$	1,546	$	4,109	$	1,196		$	2,508	$	405


¹	U.S. equities include investments in the company’s common stock in the amount of $9 at December 31, 2015, and $24 at December 31, 2014.


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


³	Mixed funds are composed of funds that invest in both equity and fixed-income instruments in order to diversify and lower risk.


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


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

FS--55

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

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



	Fixed Income
	Corporate			Mortgage-Backed Securities			Real Estate			Other			Total
Total at December 31, 2013	$	23		$	2		$	1,559		$	57		$	1,641
Actual Return on Plan Assets:
Assets held at the reporting date	—			—			115			—			115
Assets sold during the period	—			—			20			—			20
Purchases, Sales and Settlements	(1		)	(2		)	(1		)	—			(4		)
Transfers in and/or out of Level 3	—			—			—			—			—
Total at December 31, 2014	$	22		$	—		$	1,693		$	57		$	1,772
Actual Return on Plan Assets:
Assets held at the reporting date	(3		)	—			149			(1		)	145
Assets sold during the period	—			—			23			—			23
Purchases, Sales and Settlements	6			—			7			(2		)	11
Transfers in and/or out of Level 3	—			—			—			—			—
Total at December 31, 2015	$	25		$	—		$	1,872		$	54		$	1,951

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

The company’s U.S. and U.K. pension plans comprise 91 percent of the total pension assets. Both the U.S. and U.K. plans have an Investment Committee that regularly meets during the year to review the asset holdings and their returns. To assess the plans’ investment performance, long-term asset allocation policy benchmarks have been established.

For the primary U.S. pension plan, the company's Benefit Plan Investment Committee has established the following approved asset allocation ranges: Equities 40–70 percent, Fixed Income and Cash 20–60 percent, Real Estate 0–15 percent, and Other 0–5 percent. For the U.K. pension plan, the U.K. Board of Trustees has established the following asset allocation guidelines: Equities 30–50 percent, Fixed Income and Cash 35–65 percent, and Real Estate 5–15 percent. The other significant international pension plans also have established maximum and minimum asset allocation ranges that vary by plan. Actual asset allocation within approved ranges is based on a variety of current economic and market conditions and consideration of specific asset class risk. To mitigate concentration and other risks, assets are invested across multiple asset classes with active investment managers and passive index funds.

The company does not prefund its OPEB obligations.

Cash Contributions and Benefit Payments In 2015, the company contributed $641 and $227 to its U.S. and international pension plans, respectively. In 2016, the company expects contributions to be approximately $650 to its U.S. plans and $250 to its international pension plans. Actual contribution amounts are dependent upon investment returns, changes in pension obligations, regulatory environments and other economic factors. Additional funding may ultimately be required if investment returns are insufficient to offset increases in plan obligations.

The company anticipates paying OPEB benefits of approximately $191 in 2016; $196 was paid in 2015.

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



	Pension Benefits				Other
	U.S.		Int’l.		Benefits
2016	$	1,462	$	284	$	191
2017	$	1,384	$	297	$	195
2018	$	1,360	$	467	$	199
2019	$	1,329	$	339	$	203
2020	$	1,287	$	346	$	207
2021-2025	$	5,804	$	1,822	$	1,053

FS--56

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Employee Savings Investment Plan Eligible employees of Chevron and certain of its subsidiaries participate in the Chevron Employee Savings Investment Plan (ESIP). Compensation expense for the ESIP totaled $316, $316 and $163 in 2015, 2014 and 2013, respectively. The amount for ESIP expense in 2013 is net of $140, which reflects the value of common stock released from the former leveraged employee stock ownership plan (LESOP). LESOP debt was retired in 2013, and all remaining shares were released.

Benefit Plan Trusts Prior to its acquisition by Chevron, Texaco established a benefit plan trust for funding obligations under some of its benefit plans. At year-end 2015, the trust contained 14.2 million shares of Chevron treasury stock. The trust will sell the shares or use the dividends from the shares to pay benefits only to the extent that the company does not pay such benefits. The company intends to continue to pay its obligations under the benefit plans. The trustee will vote the shares held in the trust as instructed by the trust’s beneficiaries. The shares held in the trust are not considered outstanding for earnings-per-share purposes until distributed or sold by the trust in payment of benefit obligations.

Prior to its acquisition by Chevron, Unocal established various grantor trusts to fund obligations under some of its benefit plans, including the deferred compensation and supplemental retirement plans. At December 31, 2015 and 2014, trust assets of $36 and $38, respectively, were invested primarily in interest-earning accounts.

Employee Incentive Plans The Chevron Incentive Plan is an annual cash bonus plan for eligible employees that links awards to corporate, business unit and individual performance in the prior year. Charges to expense for cash bonuses were $690, $965 and $871 in 2015, 2014 and 2013, respectively. Chevron also has the LTIP for officers and other regular salaried employees of the company and its subsidiaries who hold positions of significant responsibility. Awards under the LTIP consist of stock options and other share-based compensation that are described in Note 22, beginning on page FS-50.

Note 24

Other Contingencies and Commitments

Income Taxes The company calculates its income tax expense and liabilities quarterly. These liabilities generally are subject to audit and are not finalized with the individual taxing authorities until several years after the end of the annual period for which income taxes have been calculated. Refer to Note 18, beginning on page FS-45, for a discussion of the periods for which tax returns have been audited for the company’s major tax jurisdictions and a discussion for all tax jurisdictions of the differences between the amount of tax benefits recognized in the financial statements and the amount taken or expected to be taken in a tax return.

Settlement of open tax years, as well as other tax issues in countries where the company conducts its businesses, are not expected to have a material effect on the consolidated financial position or liquidity of the company and, in the opinion of management, adequate provision has been made for income and franchise taxes for all years under examination or subject to future examination.

Guarantees The company’s guarantee of $447 is associated with certain payments under a terminal use agreement entered into by an equity affiliate. Over the approximate 12-year remaining term of the guarantee, the maximum guarantee amount will be reduced as certain fees are paid by the affiliate. There are numerous cross-indemnity agreements with the affiliate and the other partners to permit recovery of amounts paid under the guarantee. Chevron has recorded no liability for its obligation under this guarantee.

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

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

FS--57

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

products, to be used or sold in the ordinary course of the company’s business. The aggregate approximate amounts of required payments under these various commitments are: 2016 – $2,100; 2017 – $1,900; 2018 – $1,700; 2019 – $1,500; 2020 – $1,100; 2020 and after – $3,100. A portion of these commitments may ultimately be shared with project partners. Total payments under the agreements were approximately $1,900 in 2015, $3,700 in 2014 and $3,600 in 2013.

Environmental The company is subject to loss contingencies pursuant to laws, regulations, private claims and legal proceedings related to environmental matters that are subject to legal settlements or that in the future may require the company to take action to correct or ameliorate the effects on the environment of prior release of chemicals or petroleum substances, including MTBE, by the company or other parties. Such contingencies may exist for various operating, closed and divested sites, including, but not limited to, federal Superfund sites and analogous sites under state laws, refineries, chemical plants, marketing facilities, crude oil fields, and mining sites.

Although the company has provided for known environmental obligations that are probable and reasonably estimable, it is likely that the company will continue to incur additional liabilities. The amount of additional future costs are not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties. These future costs may be material to results of operations in the period in which they are recognized, but the company does not expect these costs will have a material effect on its consolidated financial position or liquidity.

Chevron’s environmental reserve as of December 31, 2015, was $1,578. Included in this balance were $348 related to remediation activities at approximately 163 sites for which the company had been identified as a potentially responsible party under the provisions of the federal Superfund law or analogous state laws which provide for joint and several liability for all responsible parties. Any future actions by regulatory agencies to require Chevron to assume other potentially responsible parties’ costs at designated hazardous waste sites are not expected to have a material effect on the company’s results of operations, consolidated financial position or liquidity.

Of the remaining year-end 2015 environmental reserves balance of $1,230, $845 is related to the company’s U.S. downstream operations, $58 to its international downstream operations, $323 to upstream operations and $4 to other businesses. Liabilities at all sites were primarily associated with the company’s plans and activities to remediate soil or groundwater contamination or both.

The company manages environmental liabilities under specific sets of regulatory requirements, which in the United States include the Resource Conservation and Recovery Act and various state and local regulations. No single remediation site at year-end 2015 had a recorded liability that was material to the company’s results of operations, consolidated financial position or liquidity.

Refer to Note 25 on page FS-59 for a discussion of the company’s asset retirement obligations.

Other Contingencies On November 7, 2011, while drilling a development well in the deepwater Frade Field about 75 miles offshore Brazil, an unanticipated pressure spike caused oil to migrate from the well bore through a series of fissures to the sea floor, emitting approximately 2,400 barrels of oil. The source of the seep was substantially contained within four days and the well was plugged and abandoned. On March 14, 2012, the company identified a small, second seep in a different part of the field. No evidence of any coastal or wildlife impacts related to either of these seeps emerged. As reported in the company’s previously filed periodic reports, it has resolved civil claims relating to these incidents brought by a Brazilian federal district prosecutor. As also reported previously, the federal district prosecutor also filed criminal charges against Chevron and11 Chevron employees. These charges were dismissed by the trial court on February 19, 2013, reinstated by an appellate court on October 9, 2013, and then, upon Chevron’s motion for reconsideration, dismissed by the appellate court on August 27, 2015. The federal district prosecutor has appealed the appellate court’s decision.

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

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

FS--58

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Note 25

Asset Retirement Obligations

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

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

The following table indicates the changes to the company’s before-tax asset retirement obligations in 2015, 2014 and 2013:



	2015			2014			2013
Balance at January 1	$	15,053		$	14,298		$	13,271
Liabilities incurred	51			133			59
Liabilities settled	(981		)	(1,291		)	(907		)
Accretion expense	715			882			627
Revisions in estimated cash flows	804			1,031			1,248
Balance at December 31	$	15,642		$	15,053		$	14,298

In the table above, the amounts associated with "Revisions in estimated cash flows" generally reflect increased cost estimates to abandon wells, equipment and facilities and accelerated timing of abandonment. The long-term portion of the $15,642 balance at the end of 2015 was $14,892.

Note 26

Restructuring and Reorganization Costs

In 2015, the company recorded accruals and adjustments for employee reduction programs related to the restructuring and reorganization of its corporate staffs and certain upstream operations. The employee reductions are expected to be substantially completed by the end of 2016.

A before-tax charge of $353 ($223 after-tax) was recorded in 2015, with $219 reported as “Operating Expenses” and $134 reported as "Selling, general and administrative expense" on the Consolidated Statement of Income. The accrued liability, covering severance benefits, is classified as current on the Consolidated Balance Sheet. Approximately $134 ($87 after-tax) is associated with employee reductions in All Other, $113 ($73 after-tax) in U.S. Upstream and $106 ($63 after-tax) in International Upstream.

During 2015, the company made payments of $60 million associated with these liabilities. The following table summarizes the accrued severance liability, which is classified as current on the Consolidated Balance Sheet:



	Amounts Before Tax
Balance at January 1, 2015	$	—
Accruals/Adjustments	353
Payments	(60		)
Balance at December 31, 2015	$	293

Note 27

Other Financial Information

Earnings in 2015 included after-tax gains of approximately $2,300 relating to the sale of nonstrategic properties. Of this amount, approximately $1,800 and $500 related to downstream and upstream, respectively. Earnings in 2014 included after-tax gains of approximately $3,000 relating to the sale of nonstrategic properties, of which approximately $1,800 and $1,000 related to upstream and downstream assets, respectively. Earnings in 2015 included after-tax charges of approximately $3,000 for impairments and other asset write-offs related to upstream. Earnings in 2014 included after-tax charges of approximately $1,000 for impairments and other asset write-offs, of which $800 was related to upstream and $200 to a mining asset.

FS--59

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Other financial information is as follows:



	Year ended December 31
	2015			2014		2013
Total financing interest and debt costs	$	495		$	358	$	284
Less: Capitalized interest	495			358		284
Interest and debt expense	$	—		$	—	$	—
Research and development expenses	$	601		$	707	$	750
Excess of replacement cost over the carrying value of inventories (LIFO method)	3,745			8,135		9,150
LIFO (losses) / profits on inventory drawdowns included in earnings	(65		)	13		14
Foreign currency effects*	$	769		$	487	$	474

^*Includes $344, $118 and $244 in 2015, 2014 and 2013, respectively, for the company’s share of equity affiliates’ foreign currency effects.

The company has $4,588 in goodwill on the Consolidated Balance Sheet related to the 2005 acquisition of Unocal and to the 2011 acquisition of Atlas Energy, Inc. The company tested this goodwill for impairment during 2015 and concluded no impairment was necessary.

Five-Year Financial Summary

Unaudited




Millions of dollars, except per-share amounts	2015		2014		2013		2012		2011
Statement of Income Data
Revenues and Other Income
Total sales and other operating revenues^*	$	129,925	$	200,494	$	220,156	$	230,590	$	244,371
Income from equity affiliates and other income	8,552		11,476		8,692		11,319		9,335
Total Revenues and Other Income	138,477		211,970		228,848		241,909		253,706
Total Costs and Other Deductions	133,635		180,768		192,943		195,577		206,072
Income Before Income Tax Expense	4,842		31,202		35,905		46,332		47,634
Income Tax Expense	132		11,892		14,308		19,996		20,626
Net Income	4,710		19,310		21,597		26,336		27,008
Less: Net income attributable to noncontrolling interests	123		69		174		157		113
Net Income Attributable to Chevron Corporation	$	4,587	$	19,241	$	21,423	$	26,179	$	26,895
Per Share of Common Stock
Net Income Attributable to Chevron
– Basic	$	2.46	$	10.21	$	11.18	$	13.42	$	13.54
– Diluted	$	2.45	$	10.14	$	11.09	$	13.32	$	13.44
Cash Dividends Per Share	$	4.28	$	4.21	$	3.90	$	3.51	$	3.09
Balance Sheet Data (at December 31)
Current assets	$	35,347	$	42,232	$	50,250	$	55,720	$	53,234
Noncurrent assets	230,756		223,794		203,503		177,262		156,240
Total Assets	266,103		266,026		253,753		232,982		209,474
Short-term debt	4,928		3,790		374		127		340
Other current liabilities	21,536		28,136		32,644		34,085		33,260
Long-term debt and capital lease obligations	33,664		24,028		20,057		12,065		9,812
Other noncurrent liabilities	52,089		53,881		50,251		48,873		43,881
Total Liabilities	112,217		109,835		103,326		95,150		87,293
Total Chevron Corporation Stockholders' Equity	$	152,716	$	155,028	$	149,113	$	136,524	$	121,382
Noncontrolling interests	1,170		1,163		1,314		1,308		799
Total Equity	$	153,886	$	156,191	$	150,427	$	137,832	$	122,181

^* Includes excise, value-added and similar taxes:	$	7,359	$	8,186	$	8,492	$	8,010	$	8,085

FS--60

Supplemental Information on Oil and Gas Producing Activities - Unaudited

In accordance with FASB and SEC disclosure requirements for oil and gas producing activities, this section provides supplemental information on oil and gas exploration and producing activities of the company in seven separate tables. Tables I through IV provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables V through VII present information on the company’s estimated net proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved

Table I - Costs Incurred in Exploration, Property Acquisitions and Development¹



	Consolidated Companies														Affiliated Companies
			Other						Australia/
Millions of dollars	U.S.		Americas		Africa		Asia		Oceania		Europe		Total		TCO		Other
Year Ended December 31, 2015
Exploration
Wells	$	857	$	66	$	172	$	218	$	81	$	14	$	1,408	$	—	$	—
Geological and geophysical	69		6		77		86		107		26		371		—		—
Rentals and other	218		56		121		109		71		68		643		—		—
Total exploration	1,144		128		370		413		259		108		2,422		—		—
Property acquisitions²
Proved	23		21		—		54		—		—		98		—		—
Unproved	554		3		30		—		—		—		587		—		—
Total property acquisitions	577		24		30		54		—		—		685		—		—
Development³	6,275		2,048		3,701		3,924		6,715		995		23,658		1,641		225
Total Costs Incurred⁴	$	7,996	$	2,200	$	4,101	$	4,391	$	6,974	$	1,103	$	26,765	$	1,641	$	225
Year Ended December 31, 2014
Exploration
Wells	$	965	$	87	$	436	$	381	$	207	$	101	$	2,177	$	—	$	—
Geological and geophysical	107		72		32		64		88		41		404		—		—
Rentals and other	150		37		198		98		101		103		687		—		—
Total exploration	1,222		196		666		543		396		245		3,268		—		—
Property acquisitions²
Proved	33		1		521		60		—		—		615		—		—
Unproved	196		2		39		—		—		—		237		—		—
Total property acquisitions	229		3		560		60		—		—		852		—		—
Development³	8,207		3,226		3,771		4,363		7,182		887		27,636		1,598		393
Total Costs Incurred⁴	$	9,658	$	3,425	$	4,997	$	4,966	$	7,578	$	1,132	$	31,756	$	1,598	$	393
Year Ended December 31, 2013
Exploration
Wells	$	594	$	495	$	88	$	405	$	262	$	123	$	1,967	$	—	$	—
Geological and geophysical	134		70		105		116		29		55		509		—		—
Rentals and other	166		62		147		80		124		131		710		—		—
Total exploration	894		627		340		601		415		309		3,186		—		—
Property acquisitions²
Proved	71		—		26		64		—		1		162		—		—
Unproved	331		2,068		—		203		105		3		2,710		—		—
Total property acquisitions	402		2,068		26		267		105		4		2,872		—		—
Development³	7,457		2,306		3,549		4,907		6,611		1,046		25,876		1,027		544
Total Costs Incurred⁴	$	8,753	$	5,001	$	3,915	$	5,775	$	7,131	$	1,359	$	31,934	$	1,027	$	544



¹	Includes costs incurred whether capitalized or expensed. Excludes general support equipment expenditures. Includes capitalized amounts related to asset retirement obligations. See Note 25, “Asset Retirement Obligations,” on page FS-59.
²	Does not include properties acquired in nonmonetary transactions.
³	Includes $325, $349 and $661 costs incurred prior to assignment of proved reserves for consolidated companies in 2015, 2014, and 2013, respectively.
⁴	Reconciliation of consolidated and affiliated companies total cost incurred to Upstream capital and exploratory (C&E) expenditures - $ billions:
		2015			2014			2013
	Total cost incurred	$	28.6		$	33.7		$	33.5
	Non-oil and gas activities	3.5			4.6			5.8			(Primarily includes LNG, gas-to-liquids and transportation activities)
	ARO	(1.0		)	(1.2		)	(1.4		)
	Upstream C&E	$	31.1		$	37.1		$	37.9		Reference page FS-13 Upstream total

FS--61

Supplemental Information on Oil and Gas Producing Activities - Unaudited

reserves and changes in estimated discounted future net cash flows. The amounts for consolidated companies are organized by geographic areas including the United States, Other Americas, Africa, Asia, Australia/Oceania and Europe. Amounts for affiliated companies include Chevron’s equity interests in Tengizchevroil (TCO) in the Republic of Kazakhstan and in other affiliates, principally in Venezuela and Angola. Refer to Note 15, beginning on page FS-40, for a discussion of the company’s major equity affiliates.

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



	Consolidated Companies														Affiliated Companies
			Other						Australia/
Millions of dollars	U.S.		Americas		Africa		Asia		Oceania		Europe		Total		TCO		Other
At December 31, 2015
Unproved properties	$	9,880	$	3,216	$	271	$	1,487	$	1,990	$	23	$	16,867	$	108	$	—
Proved properties and related producing assets	79,891		16,810		36,563		51,509		3,012		9,664		197,449		7,803		3,857
Support equipment	1,970		363		1,229		1,967		1,195		176		6,900		1,452		—
Deferred exploratory wells	438		237		443		612		1,321		261		3,312		—		—
Other uncompleted projects	7,700		5,566		6,517		5,070		29,843		2,332		57,028		3,732		425
Gross Capitalized Costs	99,879		26,192		45,023		60,645		37,361		12,456		281,556		13,095		4,282
Unproved properties valuation	1,667		873		209		438		107		23		3,317		51		—
Proved producing properties – Depreciation and depletion	53,718		8,950		21,904		35,004		1,950		8,074		129,600		3,714		984
Support equipment depreciation	800		208		740		1,420		480		161		3,809		661		—
Accumulated provisions	56,185		10,031		22,853		36,862		2,537		8,258		136,726		4,426		984
Net Capitalized Costs	$	43,694	$	16,161	$	22,170	$	23,783	$	34,824	$	4,198	$	144,830	$	8,669	$	3,298
At December 31, 2014
Unproved properties	$	10,095	$	3,207	$	286	$	1,933	$	1,990	$	33	$	17,544	$	108	$	—
Proved properties and related producing assets	75,511		14,697		33,117		47,007		3,303		9,172		182,807		7,370		3,713
Support equipment	1,670		361		1,193		1,791		796		186		5,997		1,331		—
Deferred exploratory wells	1,012		220		647		734		1,330		252		4,195		—		—
Other uncompleted projects	7,714		5,566		6,691		5,997		23,487		1,841		51,296		2,679		458
Gross Capitalized Costs	96,002		24,051		41,934		57,462		30,906		11,484		261,839		11,488		4,171
Unproved properties valuation	1,332		796		213		634		46		33		3,054		48		—
Proved producing properties – Depreciation and depletion	48,315		6,516		19,729		31,207		2,259		7,540		115,566		3,295		845
Support equipment depreciation	711		203		694		1,276		202		159		3,245		611		—
Accumulated provisions	50,358		7,515		20,636		33,117		2,507		7,732		121,865		3,954		845
Net Capitalized Costs	$	45,644	$	16,536	$	21,298	$	24,345	$	28,399	$	3,752	$	139,974	$	7,534	$	3,326
At December 31, 2013
Unproved properties	$	10,228	$	3,697	$	267	$	2,064	$	1,990	$	36	$	18,282	$	109	$	29
Proved properties and related producing assets	67,837		12,868		32,936		42,780		3,274		9,592		169,287		6,977		3,408
Support equipment	1,314		344		1,180		1,678		1,608		177		6,301		1,166		—
Deferred exploratory wells	670		297		536		335		1,134		273		3,245		—		—
Other uncompleted projects	9,149		4,175		4,424		5,998		16,000		1,390		41,136		1,638		404
Gross Capitalized Costs	89,198		21,381		39,343		52,855		24,006		11,468		238,251		9,890		3,841
Unproved properties valuation	1,243		707		203		389		6		31		2,579		45		10
Proved producing properties – Depreciation and depletion	45,756		5,695		18,051		27,356		2,083		7,825		106,766		2,672		696
Support equipment depreciation	656		189		647		1,177		384		149		3,202		538		—
Accumulated provisions	47,655		6,591		18,901		28,922		2,473		8,005		112,547		3,255		706
Net Capitalized Costs	$	41,543	$	14,790	$	20,442	$	23,933	$	21,533	$	3,463	$	125,704	$	6,635	$	3,135

FS--62

Supplemental Information on Oil and Gas Producing Activities - Unaudited

Table III - Results of Operations for Oil and Gas Producing Activities¹

The company’s results of operations from oil and gas producing activities for the years 2015, 2014 and 2013 are shown in the following table. Net income from exploration and production activities as reported on page FS-38 reflects income taxes computed on an effective rate basis.

Income taxes in Table III are based on statutory tax rates, reflecting allowable deductions and tax credits. Interest income and expense are excluded from the results reported in Table III and from the net income amounts on page FS-38.



	Consolidated Companies																					Affiliated Companies
				Other									Australia/
Millions of dollars	U.S.			Americas			Africa			Asia			Oceania			Europe			Total			TCO			Other
Year Ended December 31, 2015
Revenues from net production
Sales	$	1,475		$	1,155		$	279		$	6,254		$	889		$	403		$	10,455		$	4,097		$	729
Transfers	7,195			1,089			6,182			3,779			408			829			19,482			—			—
Total	8,670			2,244			6,461			10,033			1,297			1,232			29,937			4,097			729
Production expenses excluding taxes	(4,293		)	(1,162		)	(1,758		)	(3,601		)	(162		)	(505		)	(11,481		)	(510		)	(365		)
Taxes other than on income	(430		)	(123		)	(124		)	(15		)	(172		)	(2		)	(866		)	(279		)	(31		)
Proved producing properties:
Depreciation and depletion	(7,640		)	(2,519		)	(2,506		)	(3,887		)	(217		)	(556		)	(17,325		)	(501		)	(169		)
Accretion expense²	(265		)	(23		)	(127		)	(158		)	(37		)	(69		)	(679		)	(3		)	(14		)
Exploration expenses	(1,614		)	(137		)	(667		)	(492		)	(289		)	(106		)	(3,305		)	—			(1		)
Unproved properties valuation	(583		)	(55		)	(24		)	(79		)	(61		)	—			(802		)	—			—
Other income (expense)³	220			(291		)	638			21			73			237			898			(25		)	373
Results before income taxes	(5,935		)	(2,066		)	1,893			1,822			432			231			(3,623		)	2,779			522
Income tax expense	2,133			550			(986		)	(679		)	(178		)	(62		)	778			(835		)	(291		)
Results of Producing Operations	$	(3,802	)	$	(1,516	)	$	907		$	1,143		$	254		$	169		$	(2,845	)	$	1,944		$	231
Year Ended December 31, 2014
Revenues from net production
Sales	$	2,660		$	1,338		$	707		$	8,290		$	1,466		$	1,037		$	15,498		$	7,717		$	1,733
Transfers	13,023			2,285			12,546			8,153			888			1,277			38,172			—			—
Total	15,683			3,623			13,253			16,443			2,354			2,314			53,670			7,717			1,733
Production expenses excluding taxes	(4,786		)	(1,328		)	(2,084		)	(4,527		)	(191		)	(773		)	(13,689		)	(493		)	(670		)
Taxes other than on income	(654		)	(122		)	(140		)	(82		)	(329		)	(4		)	(1,331		)	(344		)	(418		)
Proved producing properties:
Depreciation and depletion	(4,605		)	(793		)	(3,092		)	(3,977		)	(208		)	(351		)	(13,026		)	(567		)	(175		)
Accretion expense²	(334		)	(22		)	(130		)	(142		)	(32		)	(84		)	(744		)	(9		)	(4		)
Exploration expenses	(581		)	(119		)	(383		)	(309		)	(269		)	(281		)	(1,942		)	—			(5		)
Unproved properties valuation	(140		)	(219		)	(12		)	(289		)	(40		)	(3		)	(703		)	—			(38		)
Other income (expense)³	654			674			221			115			102			358			2,124			(28		)	(85		)
Results before income taxes	5,237			1,694			7,633			7,232			1,387			1,176			24,359			6,276			338
Income tax expense	(1,955		)	(471		)	(4,924		)	(3,604		)	(392		)	(579		)	(11,925		)	(1,883		)	(284		)
Results of Producing Operations	$	3,282		$	1,223		$	2,709		$	3,628		$	995		$	597		$	12,434		$	4,393		$	54


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


²	Represents accretion of ARO liability. Refer to Note 25, “Asset Retirement Obligations,” on page FS-59.


³	Includes foreign currency gains and losses, gains and losses on property dispositions and other miscellaneous income and expenses.

FS--63

Supplemental Information on Oil and Gas Producing Activities - Unaudited

Table III - Results of Operations for Oil and Gas Producing Activities¹, continued



	Consolidated Companies																					Affiliated Companies
				Other									Australia/
Millions of dollars	U.S.			Americas			Africa			Asia			Oceania			Europe			Total			TCO			Other
Year Ended December 31, 2013
Revenues from net production
Sales	$	2,303		$	1,351		$	702		$	9,220		$	1,431		$	1,345		$	16,352		$	8,522		$	2,100
Transfers	14,471			1,973			14,804			9,521			984			1,701			43,454			—			—
Total	16,774			3,324			15,506			18,741			2,415			3,046			59,806			8,522			2,100
Production expenses excluding taxes	(4,606		)	(1,218		)	(2,099		)	(4,429		)	(193		)	(759		)	(13,304		)	(401		)	(444		)
Taxes other than on income	(648		)	(90		)	(149		)	(140		)	(378		)	(3		)	(1,408		)	(439		)	(704		)
Proved producing properties:
Depreciation and depletion	(4,039		)	(440		)	(2,747		)	(3,602		)	(342		)	(416		)	(11,586		)	(518		)	(179		)
Accretion expense²	(223		)	(22		)	(125		)	(114		)	(28		)	(79		)	(591		)	(9		)	(14		)
Exploration expenses	(555		)	(372		)	(203		)	(272		)	(161		)	(258		)	(1,821		)	—			—
Unproved properties valuation	(129		)	(84		)	(13		)	(141		)	(4		)	(5		)	(376		)	—			(10		)
Other income (expense)³	242			(5		)	145			(275		)	89			13			209			(81		)	462
Results before income taxes	6,816			1,093			10,315			9,768			1,398			1,539			30,929			7,074			1,211
Income tax expense	(2,471		)	(289		)	(6,545		)	(4,824		)	(411		)	(1,058		)	(15,598		)	(2,122		)	(624		)
Results of Producing Operations	$	4,345		$	804		$	3,770		$	4,944		$	987		$	481		$	15,331		$	4,952		$	587


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


²	Represents accretion of ARO liability. Refer to Note 25, “Asset Retirement Obligations,” on page FS-59.


³	Includes foreign currency gains and losses, gains and losses on property dispositions, and other miscellaneous income and expenses.

Table IV - Results of Operations for Oil and Gas Producing Activities - Unit Prices and Costs¹



	Consolidated Companies														Affiliated Companies
			Other						Australia/
	U.S.		Americas³		Africa		Asia		Oceania		Europe		Total		TCO		Other
Year Ended December 31, 2015
Average sales prices
Liquids, per barrel	$	42.70	$	49.66	$	49.88	$	46.19	$	49.96	$	48.53	$	46.26	$	38.71	$	34.92
Natural gas, per thousand cubic feet	1.89		3.24		1.84		4.94		6.17		5.28		3.96		1.57		2.51
Average production costs, per barrel²	16.60		20.45		12.23		13.55		5.03		17.14		14.60		4.32		17.44
Year Ended December 31, 2014
Average sales prices
Liquids, per barrel	$	84.13	$	86.23	$	96.43	$	89.44	$	95.17	$	95.05	$	89.44	$	81.07	$	76.07
Natural gas, per thousand cubic feet	3.90		3.25		1.53		5.86		10.42		9.29		5.44		1.53		6.38
Average production costs, per barrel²	20.09		22.77		13.77		17.21		5.53		27.14		17.69		4.47		29.30
Year Ended December 31, 2013
Average sales prices
Liquids, per barrel	$	93.46	$	91.44	$	107.22	$	98.37	$	103.28	$	105.78	$	99.05	$	88.06	$	78.87
Natural gas, per thousand cubic feet	3.38		3.03		1.76		6.02		10.61		11.04		5.45		1.50		4.00
Average production costs, per barrel²	19.57		21.29		13.93		16.49		5.90		22.87		17.10		4.37		22.69


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


²	Natural gas converted to oil-equivalent gas (OEG) barrels at a rate of 6 MCF = 1 OEG barrel.


³	2013 and 2014 conformed to 2015 presentation.

FS--64

Supplemental Information on Oil and Gas Producing Activities - Unaudited

Table V Reserve Quantity Information

Summary of Net Oil and Gas Reserves



	2015			2014			2013
Liquids in Millions of Barrels	Crude Oil			Crude Oil			Crude Oil
Liquids in Millions of Barrels	Condensate	Synthetic	Natural	Condensate	Synthetic	Natural	Condensate	Synthetic	Natural
Natural Gas in Billions of Cubic Feet	NGLs	Oil	Gas	NGLs	Oil	Gas	NGLs	Oil	Gas
Proved Developed
Consolidated Companies
U.S.	933	—	2,683	955	—	2,743	976	—	2,632
Other Americas	109	594	597	103	531	739	109	403	943
Africa	702	—	1,100	701	—	1,112	763	—	1,161
Asia	660	—	4,933	584	—	4,607	601	—	4,620
Australia/Oceania	60	—	4,330	38	—	1,117	44	—	1,251
Europe	76	—	166	87	—	167	94	—	200
Total Consolidated	2,540	594	13,809	2,468	531	10,485	2,587	403	10,807
Affiliated Companies
TCO	1,020	—	1,504	961	—	1,431	884	—	1,188
Other	91	58	288	100	51	317	105	44	330
Total Consolidated and Affiliated Companies	3,651	652	15,601	3,529	582	12,233	3,576	447	12,325
Proved Undeveloped
Consolidated Companies
U.S.	453	—	1,559	477	—	1,431	354	—	1,358
Other Americas	127	3	117	135	3	384	134	134	357
Africa	255	—	1,837	320	—	1,856	341	—	1,884
Asia	130	—	1,023	168	—	1,659	191	—	2,125
Australia/Oceania	93	—	7,543	104	—	9,824	87	—	9,076
Europe	67	—	58	79	—	68	72	—	63
Total Consolidated	1,125	3	12,137	1,283	3	15,222	1,179	134	14,863
Affiliated Companies
TCO	656	—	764	654	—	746	784	—	1,102
Other	40	135	935	45	153	915	49	176	856
Total Consolidated and Affiliated Companies	1,821	138	13,836	1,982	156	16,883	2,012	310	16,821
Total Proved Reserves	5,472	790	29,437	5,511	738	29,116	5,588	757	29,146

Reserves Governance The company has adopted a comprehensive reserves and resource classification system modeled after a system developed and approved by the Society of Petroleum Engineers, the World Petroleum Congress and the American Association of Petroleum Geologists. The system classifies recoverable hydrocarbons into six categories based on their status at the time of reporting – three deemed commercial and three potentially recoverable. Within the commercial classification are proved reserves and two categories of unproved: probable and possible. The potentially recoverable categories are also referred to as contingent resources. For reserves estimates to be classified as proved, they must meet all SEC and company standards.

Proved oil and gas reserves are the estimated quantities that geoscience and engineering data demonstrate with reasonable certainty to be economically producible in the future from known reservoirs under existing economic conditions, operating methods and government regulations. Net proved reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at the time of the estimate.

Proved reserves are classified as either developed or undeveloped. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods.

Due to the inherent uncertainties and the limited nature of reservoir data, estimates of reserves are subject to change as additional information becomes available.

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Supplemental Information on Oil and Gas Producing Activities - Unaudited

Proved reserves are estimated by company asset teams composed of earth scientists and engineers. As part of the internal control process related to reserves estimation, the company maintains a Reserves Advisory Committee (RAC) that is chaired by the Manager of Corporate Reserves, a corporate department that is separate from the Upstream operating organization. The Manager of Corporate Reserves has more than 30 years’ experience working in the oil and gas industry and a Master of Science in Petroleum Engineering degree from Stanford University. His experience includes more than 15 years of managing oil and gas reserves processes. He was chairman of the Society of Petroleum Engineers Oil and Gas Reserves Committee, served on the United Nations Expert Group on Resources Classification, and is a past member of the Joint Committee on Reserves Evaluator Training and the California Conservation Committee. He is an active member of the Society of Petroleum Evaluation Engineers and serves on the Society of Petroleum Engineers Oil and Gas Reserves Committee.

All RAC members are degreed professionals, each with more than 10 years of experience in various aspects of reserves estimation relating to reservoir engineering, petroleum engineering, earth science or finance. The members are knowledgeable in SEC guidelines for proved reserves classification and receive annual training on the preparation of reserves estimates.

The RAC has the following primary responsibilities: establish the policies and processes used within the operating units to estimate reserves; provide independent reviews and oversight of the business units’ recommended reserves estimates and changes; confirm that proved reserves are recognized in accordance with SEC guidelines; determine that reserve volumes are calculated using consistent and appropriate standards, procedures and technology; and maintain the Corporate Reserves Manual, which provides standardized procedures used corporatewide for classifying and reporting hydrocarbon reserves.

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

RAC subteams also conduct in-depth reviews during the year of many of the fields that have large proved reserves quantities. These reviews include an examination of the proved-reserve records and documentation of their compliance with the Corporate Reserves Manual.

Technologies Used in Establishing Proved Reserves Additions In 2015, additions to Chevron’s proved reserves were based on a wide range of geologic and engineering technologies. Information generated from wells, such as well logs, wire line sampling, production and pressure testing, fluid analysis, and core analysis, was integrated with seismic data, regional geologic studies, and information from analogous reservoirs to provide “reasonably certain” proved reserves estimates. Both proprietary and commercially available analytic tools, including reservoir simulation, geologic modeling and seismic processing, have been used in the interpretation of the subsurface data. These technologies have been utilized extensively by the company in the past, and the company believes that they provide a high degree of confidence in establishing reliable and consistent reserves estimates.

Proved Undeveloped Reserves At the end of 2015, proved undeveloped reserves totaled 4.3 billion barrels of oil-equivalent (BOE), a decrease of 687 million BOE from year-end 2014. The decrease was due to the transfer of 1,027 million BOE to proved developed and 2 million BOE in sales, partially offset by increases of 273 million BOE in extensions and discoveries, 65 million BOE in revisions, and 4 million BOE in improved recovery.

During 2015, investments totaling approximately $14.3 billion in oil and gas producing activities and about $2.3 billion in non-oil and gas producing activities were expended to advance the development of proved undeveloped reserves. Australia accounted for about $6.4 billion of the total, mainly for development and construction activities at the Gorgon and Wheatstone LNG projects. Expenditures of about $2.7 billion in the United States related primarily to various development activities in the Gulf of Mexico and the midcontinent region. In Asia, expenditures during the year totaled approximately $3.2 billion, primarily related to development projects of the TCO affiliate in Kazakhstan, and in Thailand. In Africa, about $2.8 billion was expended on various offshore development and natural gas projects in Nigeria, Angola and Republic of the Congo. Development activities in Canada were primarily responsible for about $1.5 billion of expenditures in Other Americas.

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

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Supplemental Information on Oil and Gas Producing Activities - Unaudited

At year-end 2015, the company held approximately 2.2 billion BOE of proved undeveloped reserves that have remained undeveloped for five years or more. The majority of these reserves are in three locations where the company has a proven track record of developing major projects. In Australia, approximately 500 million BOE have remained undeveloped for five years or more related to the Gorgon Project. The company is currently constructing liquefaction and other facilities in Australia to develop this natural gas. In Africa, approximately 400 million BOE have remained undeveloped for five years or more, primarily due to facility constraints at various fields and infrastructure associated with the Escravos gas projects in Nigeria. Affiliates account for about 1.1 billion BOE of proved undeveloped reserves that have remained undeveloped for five years or more, with the majority related to the TCO affiliate in Kazakhstan. At TCO, further field development to convert the remaining proved undeveloped reserves is scheduled to occur in line with reservoir depletion.

Annually, the company assesses whether any changes have occurred in facts or circumstances, such as changes to development plans, regulations or government policies, that would warrant a revision to reserve estimates. In 2015, significant reductions in commodity prices negatively impacted the economic limits of oil and gas properties, resulting in proved reserve decreases, and positively impacted proved reserves due to entitlement effects. The year-end reserves volumes have been updated for these circumstances and significant changes have been discussed in the appropriate reserves sections. For 2015, this assessment did not result in any material changes in reserves classified as proved undeveloped. Over the past three years, the ratio of proved undeveloped reserves to total proved reserves has ranged between 38 percent and 46 percent. The consistent completion of major capital projects has kept the ratio in a narrow range over this time period.

Proved Reserve Quantities For the three years ending December 31, 2015, the pattern of net reserve changes shown in the following tables are not necessarily indicative of future trends. Apart from acquisitions, the company’s ability to add proved reserves can be affected by events and circumstances that are outside the company’s control, such as delays in government permitting, partner approvals of development plans, changes in oil and gas prices, OPEC constraints, geopolitical uncertainties, and civil unrest.

At December 31, 2015, proved reserves for the company were 11.2 billion BOE. The company’s estimated net proved reserves of liquids including crude oil, condensate, natural gas liquids and synthetic oil for the years 2013, 2014 and 2015 are shown in the table on page FS-68. The company’s estimated net proved reserves of natural gas are shown on page FS-69.

Noteworthy changes in liquids proved reserves for 2013 through 2015 are discussed below and shown in the table on the following page:

Revisions In 2013, improved field performance from various Nigeria and Angola producing assets was primarily responsible for the 94 million barrel increase in Africa. In Asia, drilling performance across numerous assets resulted in an 84 million barrel increase. Improved field performance and drilling associated with Gulf of Mexico projects and drilling in the Midland and Delaware basins accounted for the majority of the 55 million barrel increase in the United States. Synthetic oil reserves in Canada increased by 40 million barrels, primarily due to improved field performance.

In 2014, drilling in the Midland and Delaware basins and improved field performance and drilling in California accounted for the majority of the 90 million barrel increase in the United States. Improved field performance at various Nigeria fields was primarily responsible for the 74 million barrel increase in Africa. In Asia, drilling performance across numerous assets, primarily in Indonesia, resulted in the 80 million barrel increase.

In 2015, entitlement effects and improved performance were responsible for the163 million barrel increase in the TCO affiliate in Kazakhstan. In Asia, entitlement effects and drilling performance across numerous assets resulted in the 164 million barrel increase. Improved field performance at various Nigerian fields, including Agbami, was primarily responsible for the 60 million barrel increase in Africa. Synthetic oil reserves in Canada increased by 80 million barrels, primarily due to entitlement effects.

Improved Recovery In 2013, improved recovery increased reserves by 57 million barrels due to numerous small projects, including expansions of existing projects in the United States, Europe, Asia, and Africa.

In 2014, improved recovery increased reserves by 34 million barrels, primarily due to secondary recovery projects in the United States, mostly related to steamflood expansions in California.

Extensions and Discoveries In 2013, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 55 million barrel increase in the United States.

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Supplemental Information on Oil and Gas Producing Activities - Unaudited

In 2014, extensions and discoveries in the Midland and Delaware basins and the Gulf of Mexico were primarily responsible for the 164 million barrel increase in the United States.

In 2015, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 137 million barrel increase in the United States.

Purchases In 2014, the purchase of additional reserves in Canada was responsible for the 26 million barrel increase in synthetic oil.

Sales In 2014, the sale of the company’s interests in Chad was responsible for the 20 million barrel decrease in Africa.

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



	Consolidated Companies																Affiliated Companies						Total Consolidated
			Other						Australia/				Synthetic						Synthetic				and Affiliated
Millions of barrels	U.S.		Americas¹		Africa		Asia		Oceania		Europe		Oil²		Total		TCO		Oil		Other³		Companies
Reserves at January 1, 2013	1,359		223		1,130		837		134		157		513		4,353		1,732		232		164		6,481
Changes attributable to:
Revisions	55		25		94		84		7		17		40		322		32		(3	)	3		354
Improved recovery	26		—		10		10		—		11		—		57		—		—		—		57
Extensions and discoveries	55		4		13		2		—		4		—		78		—		—		—		78
Purchases	2		9		—		—		—		—		—		11		—		—		—		11
Sales	(3	)	—		(1	)	—		—		—		—		(4	)	—		—		—		(4	)
Production	(164	)	(18	)	(142	)	(141	)	(10	)	(23	)	(16	)	(514	)	(96	)	(9	)	(13	)	(632	)
Reserves at December 31, 2013⁴	1,330		243		1,104		792		131		166		537		4,303		1,668		220		154		6,345
Changes attributable to:
Revisions	90		—		74		80		19		9		(32	)	240		41		(4	)	—		277
Improved recovery	19		1		1		8		—		5		—		34		—		—		—		34
Extensions and discoveries	164		18		2		7		—		8		19		218		—		—		1		219
Purchases	1		—		—		—		—		—		26		27		—		—		—		27
Sales	(6	)	—		(20	)	—		—		(3	)	—		(29	)	—		—		—		(29	)
Production	(166	)	(24	)	(140	)	(135	)	(8	)	(19	)	(16	)	(508	)	(94	)	(12	)	(10	)	(624	)
Reserves at December 31, 2014⁴	1,432		238		1,021		752		142		166		534		4,285		1,615		204		145		6,249
Changes attributable to:
Revisions	(1	)	(9	)	60		164		14		(3	)	80		305		163		—		(4	)	464
Improved recovery	7		—		11		2		—		—		—		20		—		—		—		20
Extensions and discoveries	137		28		4		5		5		—		—		179		—		—		—		179
Purchases	—		—		—		—		—		—		—		—		—		—		—		—
Sales	(6	)	—		(7	)	—		—		—		—		(13	)	—		—				(13	)
Production	(183	)	(21	)	(132	)	(133	)	(8	)	(20	)	(17	)	(514	)	(102	)	(11	)	(10	)	(637	)
Reserves at December 31, 2015⁴	1,386		236		957		790		153		143		597		4,262		1,676		193		131		6,262


¹	Ending reserve balances in North America were 155, 142 and 141 and in South America were 81, 96 and 102 in 2015, 2014 and 2013, respectively.


²	Reserves associated with Canada.


³	Ending reserve balances in Africa were 34, 37 and 37 and in South America were 97, 108 and 117 in 2015, 2014 and 2013, respectively.


⁴	Included are year-end reserve quantities related to production-sharing contracts (PSC) (refer to page E-10 for the definition of a PSC). PSC-related reserve quantities are 20 percent, 19 percent and 20 percent for consolidated companies for 2015, 2014 and 2013, respectively.

FS--68

Supplemental Information on Oil and Gas Producing Activities - Unaudited

Net Proved Reserves of Natural Gas



	Consolidated Companies														Affiliated Companies				Total Consolidated
			Other						Australia/										and Affiliated
Billions of cubic feet (BCF)	U.S.		Americas¹		Africa		Asia		Oceania		Europe		Total		TCO		Other²		Companies
Reserves at January 1, 2013	3,722		1,475		3,081		6,867		10,252		257		25,654		2,299		1,242		29,195
Changes attributable to:
Revisions	(234	)	(59	)	27		627		229		46		636		117		(35	)	718
Improved recovery	3		—		2		6		—		4		15		—		—		15
Extensions and discoveries	951		—		27		16		—		27		1,021		—		—		1,021
Purchases	12		32		—		60		—		—		104		—		—		104
Sales	(10	)	—		(1	)	—		—		(1	)	(12	)	—		—		(12	)
Production³	(454	)	(148	)	(91	)	(831	)	(154	)	(70	)	(1,748	)	(126	)	(21	)	(1,895	)
Reserves at December 31, 2013	3,990		1,300		3,045		6,745		10,327		263		25,670		2,290		1,186		29,146
Changes attributable to:
Revisions	76		(110	)	35		252		775		36		1,064		9		34		1,107
Improved recovery	2		1		1		—		—		1		5		—		—		5
Extensions and discoveries	614		56		—		79		—		3		752		—		32		784
Purchases	1		—		—		21		—		—		22		—		—		22
Sales	(53	)	(1	)	(3	)	—		—		(5	)	(62	)	—		—		(62	)
Production³	(456	)	(123	)	(110	)	(831	)	(161	)	(63	)	(1,744	)	(122	)	(20	)	(1,886	)
Reserves at December 31, 2014	4,174		1,123		2,968		6,266		10,941		235		25,707		2,177		1,232		29,116
Changes attributable to:
Revisions	(66	)	(435	)	27		480		974		49		1,029		218		2		1,249
Improved recovery	1		—		—		—		—		—		1		—		—		1
Extensions and discoveries	659		147		61		61		118		—		1,046		—		—		1,046
Purchases	—		—		—		—		—		—		—		—		—		—
Sales	(48	)	—		(5	)	—		—		—		(53	)	—		—		(53	)
Production³	(478	)	(121	)	(114	)	(851	)	(160	)	(60	)	(1,784	)	(127	)	(11	)	(1,922	)
Reserves at December 31, 2015	4,242		714		2,937		5,956		11,873		224		25,946		2,268		1,223		29,437


¹	Ending reserve balances in North America and South America were 174, 59, 54 and 540, 1,064, 1,246 in 2015, 2014 and 2013, respectively.


²	Ending reserve balances in Africa and South America were 1,044, 1,043, 1,009 and 179, 189, 177 in 2015, 2014 and 2013, respectively.


³	Total “as sold” volumes are 1,742 BCF, 1,695 BCF and 1,702 BCF for 2015, 2014 and 2013, respectively; 2013 conformed to 2014 presentation.


⁴	Includes reserve quantities related to production-sharing contracts (PSC) (refer to page E-11 for the definition of a PSC). PSC-related reserve quantities are 16 percent, 19 percent and 20 percent for consolidated companies for 2015, 2014 and 2013, respectively.

Noteworthy changes in natural gas proved reserves for 2013 through 2015 are discussed below and shown in the table above:

Revisions In 2013, net revisions of 627 BCF in Asia were primarily due to development drilling and improved field performance in Bangladesh and Thailand. In Australia, drilling performance drove the 229 BCF increase. The majority of the net decrease of 234 BCF in the United States was due to a change in development plans in the Appalachian region.

In 2014, net revisions of 775 BCF in Australia were primarily due to development drilling at Gorgon.

In 2015, positive drilling performance at Wheatstone and Gorgon was responsible for the 974 BCF increase in Australia. Net revisions of 480 BCF in Asia were primarily due to improved field performance in Thailand and to entitlement effects and improved performance in Kazakhstan. The majority of the net decrease of 435 BCF in Other Americas was due to the deferral of the infill drilling and compression projects as well as drilling results in Trinidad and Tobago. The 218 BCF increase for the TCO affiliate was due to entitlement effects and improved performance.

Extensions and Discoveries In 2013, extensions and discoveries of 951 BCF in the United States were primarily in the Appalachian region.

In 2014, extensions and discoveries of 614 BCF in the United States were primarily in the Appalachian region and the Delaware Basin.

In 2015, extensions and discoveries of 659 BCF in the United States were primarily in the Appalachian region and the Midland and Delaware basins.

FS--69

Supplemental Information on Oil and Gas Producing Activities - Unaudited

Table VI - Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves

The standardized measure of discounted future net cash flows is calculated in accordance with SEC and FASB requirements. This includes using the average of first-day-of-the-month oil and gas prices for the 12-month period prior to the end of the reporting period, estimated future development and production costs assuming the continuation of existing economic conditions, estimated costs for asset retirement obligations (includes costs to retire existing wells and facilities in addition to those future wells and facilities necessary to produce proved undeveloped reserves), and estimated future income taxes based on appropriate statutory tax rates. Discounted future net cash flows are calculated using 10 percent mid-period discount factors. Estimates of proved-reserve quantities are imprecise and change over time as new information becomes available. Probable and possible reserves, which may become proved in the future, are excluded from the calculations. The valuation requires assumptions as to the timing and amount of future development and production costs. The calculations are made as of December 31 each year and do not represent management’s estimate of the company’s future cash flows or value of its oil and gas reserves. In the following table, the caption “Standardized Measure Net Cash Flows” refers to the standardized measure of discounted future net cash flows.



	Consolidated Companies																					Affiliated Companies						Total Consolidated
				Other									Australia/															and Affiliated
Millions of dollars	U.S.			Americas			Africa			Asia			Oceania			Europe			Total			TCO			Other			Companies
At December 31, 2015
Future cash inflows from production	$	67,536		$	39,363		$	52,128		$	58,645		$	93,550		$	8,561		$	319,783		$	75,378		$	17,519		$	412,680
Future production costs	(33,895		)	(26,477		)	(22,963		)	(27,499		)	(10,814		)	(6,994		)	(128,642		)	(17,959		)	(6,546		)	(153,147		)
Future development costs	(12,625		)	(5,485		)	(6,562		)	(8,924		)	(11,612		)	(1,751		)	(46,959		)	(17,232		)	(3,226		)	(67,417		)
Future income taxes	(4,161		)	(2,316		)	(14,681		)	(9,229		)	(21,337		)	70			(51,654		)	(12,056		)	(3,460		)	(67,170		)
Undiscounted future net cash flows	16,855			5,085			7,922			12,993			49,787			(114		)	92,528			28,131			4,287			124,946
10 percent midyear annual discount for timing of estimated cash flows	(5,871		)	(2,830		)	(2,230		)	(3,673		)	(26,179		)	292			(40,491		)	(15,249		)	(2,239		)	(57,979		)
Standardized Measure Net Cash Flows	$	10,984		$	2,255		$	5,692		$	9,320		$	23,608		$	178		$	52,037		$	12,882		$	2,048		$	66,967
At December 31, 2014
Future cash inflows from production	$	138,385		$	67,102		$	103,304		$	99,741		$	142,541		$	18,168		$	569,241		$	144,721		$	37,511		$	751,473
Future production costs	(42,817		)	(30,899		)	(26,992		)	(34,359		)	(12,744		)	(10,814		)	(158,625		)	(30,015		)	(17,061		)	(205,701		)
Future development costs	(13,616		)	(8,283		)	(9,486		)	(12,629		)	(15,681		)	(3,031		)	(62,726		)	(19,349		)	(4,454		)	(86,529		)
Future income taxes	(27,129		)	(8,445		)	(47,884		)	(24,225		)	(34,235		)	(2,692		)	(144,610		)	(28,607		)	(6,634		)	(179,851		)
Undiscounted future net cash flows	54,823			19,475			18,942			28,528			79,881			1,631			203,280			66,750			9,362			279,392
10 percent midyear annual discount for timing of estimated cash flows	(23,257		)	(12,082		)	(6,145		)	(8,570		)	(43,325		)	(380		)	(93,759		)	(34,987		)	(5,294		)	(134,040		)
Standardized Measure Net Cash Flows	$	31,566		$	7,393		$	12,797		$	19,958		$	36,556		$	1,251		$	109,521		$	31,763		$	4,068		$	145,352
At December 31, 2013¹
Future cash inflows from production	$	136,942		$	73,468		$	117,119		$	111,970		$	130,620		$	20,232		$	590,351		$	157,108		$	43,380		$	790,839
Future production costs	(39,009		)	(29,373		)	(27,800		)	(35,716		)	(12,593		)	(10,099		)	(154,590		)	(32,245		)	(18,027		)	(204,862		)
Future development costs	(12,058		)	(10,149		)	(10,983		)	(17,290		)	(18,220		)	(2,644		)	(71,344		)	(12,852		)	(3,879		)	(88,075		)
Future income taxes	(28,458		)	(9,454		)	(53,953		)	(26,162		)	(29,942		)	(4,727		)	(152,696		)	(33,603		)	(9,418		)	(195,717		)
Undiscounted future net cash flows	57,417			24,492			24,383			32,802			69,865			2,762			211,721			78,408			12,056			302,185
10 percent midyear annual discount for timing of estimated cash flows	(23,055		)	(15,217		)	(8,165		)	(10,901		)	(39,117		)	(888		)	(97,343		)	(41,444		)	(6,482		)	(145,269		)
Standardized Measure Net Cash Flows	$	34,362		$	9,275		$	16,218		$	21,901		$	30,748		$	1,874		$	114,378		$	36,964		$	5,574		$	156,916


¹	2013 conformed to 2014 and 2015 presentation.

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Supplemental Information on Oil and Gas Producing Activities - Unaudited

Table VII - Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves

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



									Total Consolidated and
Millions of dollars	Consolidated Companies¹				Affiliated Companies				Affiliated Companies
Present Value at January 1, 2013		$	110,626			$	45,214			$	155,840
Sales and transfers of oil and gas produced net of production costs		(43,760		)		(8,692		)		(52,452		)
Development costs incurred		22,907				1,411				24,318
Purchases of reserves		184				—				184
Sales of reserves		243				—				243
Extensions, discoveries and improved recovery less related costs		3,135				—				3,135
Revisions of previous quantity estimates		22,796				1,306				24,102
Net changes in prices, development and production costs		(22,591		)		(5,925		)		(28,516		)
Accretion of discount		18,510				6,406				24,916
Net change in income tax		2,328				2,818				5,146
Net change for 2013		3,752				(2,676		)		1,076
Present Value at December 31, 2013		$	114,378			$	42,538			$	156,916
Sales and transfers of oil and gas produced net of production costs		(38,935		)		(7,578		)		(46,513		)
Development costs incurred		25,687				1,963				27,650
Purchases of reserves		255				—				255
Sales of reserves		(1,178		)		—				(1,178		)
Extensions, discoveries and improved recovery less related costs		3,956				215				4,171
Revisions of previous quantity estimates		17,462				1,573				19,035
Net changes in prices, development and production costs		(34,953		)		(12,496		)		(47,449		)
Accretion of discount		18,884				5,926				24,810
Net change in income tax		3,965				3,690				7,655
Net change for 2014		(4,857		)		(6,707		)		(11,564		)
Present Value at December 31, 2014		$	109,521			$	35,831			$	145,352
Sales and transfers of oil and gas produced net of production costs		(17,145		)		(3,637		)		(20,782		)
Development costs incurred		21,703				1,863				23,566
Purchases of reserves		2				—				2
Sales of reserves		(109		)		—				(109		)
Extensions, discoveries and improved recovery less related costs		1,415				—				1,415
Revisions of previous quantity estimates		9,171				3,607				12,778
Net changes in prices, development and production costs		(143,055		)		(37,056		)		(180,111		)
Accretion of discount		18,179				4,965				23,144
Net change in income tax		52,355				9,357				61,712
Net change for 2015		(57,484		)		(20,901		)		(78,385		)
Present Value at December 31, 2015		$	52,037			$	14,930			$	66,967

¹2013 conformed to 2014 and 2015 presentation.

FS--71

EXHIBIT INDEX



Exhibit No.	Description
3.1	Restated Certificate of Incorporation of Chevron Corporation, dated May 30, 2008, filed as Exhibit 3.1 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2008, and incorporated herein by reference.
3.2	By-Laws of Chevron Corporation, as amended September 30, 2015 filed as Exhibit 3.2 to Chevron Corporation's Current Report on Form 8-K filed September 30, 2015, and incorporated herein by reference.
4.1	Pursuant to the Instructions to Exhibits, certain instruments defining the rights of holders of long-term debt securities of the company and its consolidated subsidiaries are not filed because the total amount of securities authorized under any such instrument does not exceed 10 percent of the total assets of the corporation and its subsidiaries on a consolidated basis. A copy of such instrument will be furnished to the Securities and Exchange Commission upon request.
4.2	Confidential Stockholder Voting Policy of Chevron Corporation, filed as Exhibit 4.2 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2008, and incorporated herein by reference.
10.1	Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan, filed as Exhibit 10.1 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2008, and incorporated herein by reference.
10.2	Form of Retainer Stock Option Agreement under the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan, filed as Exhibit 10.17 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2009, and incorporated herein by reference.
10.3	Form of Stock Units Agreement under the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan, filed as Exhibit 10.19 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2008, and incorporated herein by reference.
10.4	Chevron Incentive Plan, filed as Exhibit 10.2 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2008, and incorporated herein by reference.
10.5	Summary of Chevron Incentive Plan Award Criteria, filed as Exhibit 10.5 to Chevron Corporation's Annual Report on Form 10-K for the year ended December 31, 2014, and incorporated herein by reference.
10.6	Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit B to Chevron Corporation’s Notice of the 2013 Annual Meeting and 2013 Proxy Statement filed April 11, 2013, and incorporated herein by reference.
10.7	Form of Restricted Stock Units Grant Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.7 to Chevron Corporation's Annual Report on Form 10-K for the year ended December 31, 2014, and incorporated herein by reference.
10.8	Form of Non-Qualified Stock Options Grant Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.8 to Chevron Corporation's Annual Report on Form 10-K for the year ended December 31, 2014, and incorporated herein by reference.
10.9	Form of Performance Shares Grant Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.9 to Chevron Corporation's Annual Report on Form 10-K for the year ended December 31, 2014, and incorporated herein by reference.
10.10	Form of Stock Appreciation Rights Grant Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.10 to Chevron Corporation's Annual Report on Form 10-K for the year ended December 31, 2014, and incorporated herein by reference.
10.11	Chevron Corporation Deferred Compensation Plan for Management Employees, filed as Exhibit 10.5 to Chevron Corporation’s Current Report on Form 8-K filed December 13, 2005, and incorporated herein by reference.
10.12	Chevron Corporation Deferred Compensation Plan for Management Employees II, filed as Exhibit 10.5 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2008, and incorporated herein by reference.
10.13	Chevron Corporation Retirement Restoration Plan, filed as Exhibit 10.6 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2008, and incorporated herein by reference.
10.14	Chevron Corporation ESIP Restoration Plan, filed as Exhibit 10.7 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2008, and incorporated herein by reference.
10.15	Agreement between Chevron Corporation and R. Hewitt Pate, filed as Exhibit 10.16 to Chevron Corporation's Annual Report on Form 10-K for the year ended December 31, 2011, and incorporated herein by reference.
12.1*	Computation of Ratio of Earnings to Fixed Charges (page E-3).
21.1*	Subsidiaries of Chevron Corporation (page E-4).

E--1



Exhibit No.		Description

23.1*		Consent of PricewaterhouseCoopers LLP (page E-5).
24.1 to 24.11*		Powers of Attorney for certain directors of Chevron Corporation, authorizing the signing of the Annual Report on Form 10-K on their behalf.
31.1*		Rule 13a-14(a)/15d-14(a) Certification by the company’s Chief Executive Officer (page E-6).
31.2*		Rule 13a-14(a)/15d-14(a) Certification by the company’s Chief Financial Officer (page E-7).
32.1*		Rule 13a-14(b)/15d-14(b) Certification by the company’s Chief Executive Officer (page E-8).
32.2*		Rule 13a-14(b)/15d-14(b) Certification by the company’s Chief Financial Officer (page E-9).
95*		Mine Safety Disclosure.
99.1*		Definitions of Selected Energy and Financial Terms (pages E-10 through E-11).
101.INS*		XBRL Instance Document.
101.SCH*		XBRL Schema Document.
101.CAL*		XBRL Calculation Linkbase Document.
101.LAB*		XBRL Label Linkbase Document.
101.PRE*		XBRL Presentation Linkbase Document.
101.DEF*		XBRL Definition Linkbase Document.

Attached as Exhibit 101 to this report are documents formatted in XBRL (Extensible Business Reporting Language). The financial information contained in the XBRL-related documents is “unaudited” or “unreviewed.”

_______________________________


^*	Filed herewith.

Copies of the above exhibits not contained herein are available to any security holder upon written request to the Corporate Governance Department, Chevron Corporation, 6001 Bollinger Canyon Road, San Ramon, California 94583-2324.

E--2