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, ~~2012~~2013

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. o

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



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 — $~~207,005,770,000~~228,635,687,380 (As of June ~~29, 2012~~28, 2013)

Number of Shares of Common Stock outstanding as of February ~~11, 2013~~10, 2014 — ~~1,942,697,787~~1,909,130,328

DOCUMENTS INCORPORATED BY REFERENCE

(To The Extent Indicated Herein)

Notice of the ~~2013~~2014 Annual Meeting and ~~2013~~2014 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, in connection with the company’s ~~2013~~2014 Annual Meeting of Stockholders (in Part III)

TABLE OF CONTENTS


ITEM			PAGE NO.			PAGE NO.
PART I	PART I			PART I
1.		Business	3		Business	3
		General Development of Business	3		General Development of Business	3
		Description of Business and Properties	4		Description of Business and Properties	4
		Capital and Exploratory Expenditures	4		Capital and Exploratory Expenditures	4
		Upstream	4		Upstream	4
		Downstream	24		Downstream	24
		Other Businesses	26		Other Businesses	26
		Web Site Access to SEC Reports	28		Website Access to SEC Reports	27
1A.		Risk Factors	28		Risk Factors	27
1B.		Unresolved Staff Comments	30		Unresolved Staff Comments	29
2.		Properties	30		Properties	29
3.		Legal Proceedings	30		Legal Proceedings	29
4.		Mine Safety Disclosures	30		Mine Safety Disclosures	31
PART II	PART II			PART II
5.		Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	31		Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	31
6.		Selected Financial Data	31		Selected Financial Data	31
7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations	31		Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
7A.		Quantitative and Qualitative Disclosures About Market Risk	31		Quantitative and Qualitative Disclosures About Market Risk	31
8.		Financial Statements and Supplementary Data	31		Financial Statements and Supplementary Data	32
9.		Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	32		Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	32
9A.		Controls and Procedures	32		Controls and Procedures	32
9B.		Other Information	32		Other Information	32
PART III	PART III			PART III
10.		Directors, Executive Officers and Corporate Governance	33		Directors, Executive Officers and Corporate Governance	33
11.		Executive Compensation	34		Executive Compensation	34
12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	34		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	34
13.		Certain Relationships and Related Transactions, and Director Independence	34		Certain Relationships and Related Transactions, and Director Independence	34
14.		Principal Accounting Fees and Services	34		Principal Accounting Fees and Services	34
PART IV	PART IV			PART IV
15.		Exhibits, Financial Statement Schedules	35		Exhibits, Financial Statement Schedules	35
		Schedule II — Valuation and Qualifying Accounts	36		Schedule II — Valuation and Qualifying Accounts	36
		Signatures	37		Signatures	37



~~EX-10.9~~EX-10.8	~~EX-24.9~~EX-24.10
~~EX-10.13~~EX-10.9	EX-31.1
~~EX-10.16~~EX-12.1	EX-31.2
~~EX-12.1~~EX-21.1	EX-32.1
~~EX-21.1~~EX-23.1	EX-32.2
~~EX-23.1~~EX-24.1	EX-95
~~EX-24.1~~EX-24.2	EX-99.1
~~EX-24.2~~EX-24.3	EX-101 INSTANCE DOCUMENT
~~EX-24.3~~EX-24.4	EX-101 SCHEMA DOCUMENT
~~EX-24.4~~EX-24.5	EX-101 CALCULATION LINKBASE DOCUMENT
~~EX-24.5~~EX-24.6	EX-101 LABELS LINKBASE DOCUMENT
~~EX-24.6~~EX-24.7	EX-101 PRESENTATION LINKBASE DOCUMENT
~~EX-24.7~~EX-24.8	EX-101 DEFINITION LINKBASE DOCUMENT
~~EX-24.8~~EX-24.9

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

This Annual Report on Form 10-K of Chevron Corporation contains forward-looking statements relating to Chevron’s operations that are based on management’s current expectations, estimates and projections about the petroleum, chemicals and other energy-related industries. Words such as “anticipates,” “expects,” “intends,” “plans,” “targets,” “forecasts,” “projects,” “believes,” “seeks,” “schedules,” “estimates,” “budgets,” “outlook” 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; actions of competitors or regulators; timing of exploration expenses; timing of crude oil liftings; the competitiveness of alternate-energy sources or product substitutes; technological developments; the results of operations and financial condition of equity affiliates; the inability or failure of the company’s joint-venture partners to fund their share of operations and development activities; the potential failure to achieve expected net production from existing and future crude oil and natural gas development projects; potential delays in the development, construction or start-up of planned projects; the potential disruption or interruption of the company’s production or manufacturing facilities or delivery/transportation networks due to war, accidents, political events, civil unrest, severe weather or crude oil production quotas that might be imposed by the Organization of Petroleum Exporting Countries; the potential liability for remedial actions or assessments under existing or future environmental regulations and litigation; significant investment or product changes required by existing or future environmental statutes, regulations and litigation; the potential liability resulting from other pending or future litigation; the company’s future acquisition or disposition of assets and gains and losses from asset dispositions or impairments; government-mandated sales, divestitures, recapitalizations, industry-specific taxes, changes in fiscal terms or restrictions on scope of company operations; foreign currency movements compared with the U.S. dollar; the effects of changed accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; and the factors set forth under the heading “Risk Factors” on pages 2827 through 3029 in this report. In addition, such results could be affected by general domestic and international economic and political conditions. Other unpredictable or unknown factors not discussed in this report could also have material adverse effects on forward-looking statements.

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 fully integrated petroleum operations, chemicals operations, mining ~~activities,~~operations, and power ~~generation~~ and energy services. Upstream operations consist primarily of exploring for, developing and producing crude oil and natural gas; processing, liquefaction, transportation and regasification associated with liquefied natural gas; transporting crude oil by major international oil export pipelines; transporting, storage and marketing of natural gas; and a gas-to-liquids project. Downstream operations consist primarily of refining crude oil into petroleum products; marketing of crude oil and refined products; transporting crude oil and refined products by pipeline, marine vessel, motor equipment and rail car; and manufacturing and marketing of commodity petrochemicals, plastics for industrial uses and fuel and lubricant additives.

A list of the company’s major subsidiaries is presented on ~~pages E-4 and E-5.~~page E-4. As of December 31, ~~2012~~2013, Chevron had approximately ~~62,000~~64,600 employees (including about ~~3,700~~3,200 service station employees). Approximately ~~31,000~~32,000 employees (including about ~~3,400~~3,000 service station employees), or 50 percent, were employed in U.S. operations.

Overview of Petroleum Industry

Petroleum industry operations and profitability are influenced by many factors. Prices for crude oil, natural gas, petroleum products and petrochemicals are generally determined by supply and demand. The members of the Organization of Petroleum Exporting Countries (OPEC) are typically the world’s swing producers of crude oil and their production levels are a major factor in determining worldwide supply. Demand for crude oil and its products and for natural gas is largely driven by the conditions of local, national and global economies, although weather patterns and taxation relative to

other energy sources also play a significant part. Laws and governmental policies, particularly in the areas of taxation, energy and the environment affect where and how companies conduct their operations and formulate their products and, in some cases, limit their profits directly.

Strong competition exists in all sectors of the petroleum and petrochemical industries in supplying the energy, fuel and chemical needs of industry and individual consumers. Chevron competes with fully integrated, major global petroleum companies, as well as independent and national petroleum companies, for the acquisition of crude oil and natural gas leases and other properties and for the equipment and labor required to develop and operate those properties. In its downstream business, Chevron 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 and commercialize the company’s equity natural gas resource base while growing a high-impact global natural gas business.~~positions. In the downstream, the strategies are to ~~improve~~deliver competitive returns and grow earnings across the value chain. The company also continues to apply commercial excellence to enable the success of the upstream and downstream strategies, to utilize technology across all its businesses to differentiate performance, and to invest in profitable renewable energy and energy efficiency solutions.

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, ~~2012~~2013, and assets as of the end of ~~2012~~2013 and ~~2011~~2012 — for the United States and the company’s international geographic areas — are in Note 1011 to the Consolidated Financial Statements beginning on page ~~FS-36.~~FS-35. Similar comparative data for the company’s investments in and income from equity affiliates and property, plant and equipment are in Notes 1112 and 1213 on pages ~~FS-38~~FS-37 through ~~FS-40.~~FS-39.

Capital and Exploratory Expenditures

Total expenditures for ~~2012~~2013 were $~~34.2~~41.9 billion, including $~~2.1~~2.7 billion for the company’s share of equity-affiliate expenditures. In ~~2011~~2012 and ~~2010~~2011, expenditures were $~~29.1~~34.2 billion and $~~21.8~~29.1 billion, respectively, including the company’s share of affiliates’ expenditures of $2.1 billion in 2012 and $1.7 billion in 2011 ~~and~~ ~~$1.4 billion~~ in ~~2010~~.

Of the $~~34.2~~41.9 billion in expenditures for ~~2012~~2013, 8990 percent, or $~~30.4~~37.9 billion, was related to upstream activities. Approximately 89 ~~and~~ 87 percent was expended for upstream operations in both ~~2011~~2012 and ~~2010~~2011~~, respectively.~~. International upstream accounted for about 7278 percent of the worldwide upstream investment in 2013, about 72 percent in 2012, and about 68 percent in 2011 ~~and about~~ ~~82 percent~~ in ~~2010~~. These amounts exclude the acquisition of Atlas Energy, Inc., in 2011.

In ~~2013~~2014, the company estimates capital and exploratory expenditures will be ~~$36.7~~$39.8 billion, including ~~$3.3~~$4.8 billion of spending by affiliates. Approximately 90 percent of the total, or ~~$33~~$35.8 billion, is budgeted for exploration and production activities, with ~~$25.5~~$27.9 billion, or about 7078 percent, of this amount for projects outside the United States.

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

Upstream

The table on the following page summarizes the net production of liquids and natural gas for ~~2012~~2013 and ~~2011~~2012 by the company and its affiliates. Worldwide oil-equivalent production ~~was~~of ~~2.610~~2.597 million barrels per day ~~down about~~ ~~2 percent~~in 2013 was essentially unchanged from ~~2011~~2012. The ~~decrease was mainly associated with normal field declines, the shut-in~~benefits of ~~the Frade Field in Brazil,~~lower maintenance-related downtime and ~~a major planned turnaround~~higher reliability at the Tengizchevroil facilities in ~~Kazakhstan. The start-up~~Kazakhstan, and ~~ramp-up of several major capital projects — the Platong II natural gas project in Thailand,~~ramp-ups at the Usan ~~and Agbami 2 projects~~Project in Nigeria, ~~and the Perdido, Tahiti 2 and Caesar/Tonga projects~~ in the ~~U.S. Gulf of~~Marcellus Shale in western Pennsylvania and in the Delaware Basin in New Mexico ~~— partially~~were offset ~~the decrease in net production from 2011.~~by normal field declines. Refer to the “Results of Operations” section beginning on page FS-6 for a detailed discussion of the factors explaining the ~~2010~~2011 through ~~2012~~2013 changes in production for crude oil and natural gas liquids, and natural gas.

The company estimates its average worldwide oil-equivalent production in ~~2013~~2014 will be approximately ~~2.650~~2.610 million barrels per day based on an average Brent price of $~~112~~109 per barrel in ~~2012~~2013. This estimate is subject to many factors and uncertainties, including quotas that may be imposed by OPEC, price effects on entitlement volumes, changes in fiscal terms or restrictions on the scope of company operations, delays in project start-ups and ramp-ups, fluctuations in demand for natural gas in various markets, weather conditions that may shut in production, civil unrest, changing geopolitics, delays in completion of maintenance turnarounds, greater-than-expected declines in production from mature fields, or other disruptions to operations. The longer-term outlook for production levels is also affected by the size and number of economic investment opportunities and, for new, large-scale projects, the time lag between initial exploration and the beginning of production. Refer to the “Review of Ongoing Exploration and Production Activities in Key Areas,” beginning on page 9, for a discussion of the company’s major crude oil and natural gas development projects.

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 Crude Oil and Natural Gas Liquids and Natural Gas ¹



				Components of Oil-Equivalent							Components of Oil-Equivalent
				Crude Oil & Natural Gas							Crude Oil & Natural Gas
		Oil-Equivalent (Thousands		Liquids (Thousands of		Natural Gas (Millions			Oil-Equivalent (Thousands		Liquids (Thousands of		Natural Gas (Millions
		of Barrels per Day)		Barrels per Day)		of Cubic Feet per Day)			of Barrels per Day)		Barrels per Day)		of Cubic Feet per Day)
		2012	2011	2012	2011	2012	2011		2013	2012	2013	2012	2013	2012
United States		655	678	455	465	1,203	1,279		657	655	449	455	1,246	1,203
Other Americas
Argentina		22	27	21	26	4	4		19	22	18	21	6	4
Brazil		6	35	6	33	2	13		6	6	5	6	2	2
Canada		69	70	68	69	4	4		71	69	70	68	9	4
Colombia		36	39	—	—	216	234		36	36	—	—	216	216
Trinidad and Tobago		29	31	—	—	173	183		29	29	—	—	173	173
Total Other Americas		162	202	95	128	399	438		161	162	93	95	406	399
Africa
Angola		137	147	128	139	53	50		127	137	118	128	52	53
Chad		23	26	22	25	6	6		19	23	18	22	4	6
Democratic Republic of the Congo		3	3	2	3	1	1		3	3	2	2	1	1
Nigeria		269	260	242	236	165	142		268	269	238	242	182	165
Republic of the Congo		19	23	17	21	13	10		14	19	13	17	10	13
Total Africa		451	459	411	424	238	209		431	451	389	411	249	238
Asia
Azerbaijan		28	28	26	26	10	10		28	28	26	26	10	10
Bangladesh		94	74	2	2	550	434		113	94	2	2	663	550
China		21	22	20	20	9	10		20	21	19	20	6	9
Indonesia		198	208	158	166	236	253		193	198	156	158	225	236
Kazakhstan		61	62	37	38	139	144		57	61	34	37	135	139
Myanmar		16	14	—	—	94	86		16	16	—	—	96	94
Partitioned Zone²		90	91	86	88	21	20		87	90	84	86	19	21
Philippines		24	25	4	4	120	126		23	24	3	4	119	120
Thailand		243	209	67	65	1,060	867		229	243	62	67	1,003	1,060
Total Asia		775	733	400	409	2,239	1,950		766	775	386	400	2,276	2,239
Australia		99	101	28	26	428	448		96	99	26	28	421	428
Europe
Denmark		36	44	24	29	74	91		28	36	19	24	55	74
Netherlands		9	7	2	2	42	31		9	9	2	2	41	42
Norway		3	3	3	3	1	1		2	3	2	3	1	1
United Kingdom		66	85	46	59	122	155		55	66	40	46	94	122
Total Europe		114	139	75	93	239	278		94	114	63	75	191	239
Total Consolidated Companies		2,256	2,312	1,464	1,545	4,746	4,602		2,205	2,256	1,406	1,464	4,789	4,746
Equity Affiliates³		354	361	300	304	328	339
Affiliates3									392	354	325	300	403	328
Total Including Affiliates⁴		2,610	2,673	1,764	1,849	5,074	4,941		2,597	2,610	1,731	1,764	5,192	5,074


¹ Includes synthetic oil: Canada, net		43	40	43	40	—	—		43	43	43	43	—	—
Venezuelan affiliate, net	Venezuelan affiliate, net	17	32	17	32	—	—	Venezuelan affiliate, net	25	17	25	17	—	—
² Located between Saudi Arabia and Kuwait.
³ Volumes represent Chevron’s share of production by affiliates, including Tengizchevroil in Kazakhstan and Petroboscan, Petroindependiente and Petropiar in Venezuela.
⁴Volumes include natural gas consumed in operations of 586 million and 582 million cubic feet per day in 2012 and 2011, respectively. Total “as sold” natural gas volumes were 4,488 million and 4,359 million cubic feet per day for 2012 and 2011, respectively.
3 Volumes represent Chevron’s share of production by affiliates, including Tengizchevroil in Kazakhstan; Petroboscan, Petroindependiente and Petropiar in Venezuela; and Angola LNG in Angola.								3 Volumes represent Chevron’s share of production by affiliates, including Tengizchevroil in Kazakhstan; Petroboscan, Petroindependiente and Petropiar in Venezuela; and Angola LNG in Angola.
⁴Volumes include natural gas consumed in operations of 524 million and 522 million cubic feet per day in 2013 and 2012, respectively. Total “as sold” natural gas volumes were 4,668 million and 4,552 million cubic feet per day for 2013 and 2012, respectively.								⁴Volumes include natural gas consumed in operations of 524 million and 522 million cubic feet per day in 2013 and 2012, respectively. Total “as sold” natural gas volumes were 4,668 million and 4,552 million cubic feet per day for 2013 and 2012, respectively.

Average Sales Prices and Production Costs per Unit of Production

Refer to Table IV on page ~~FS-67~~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 ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011.

Gross and Net Productive Wells

The following table summarizes gross and net productive wells at year-end ~~2012~~2013 for the company and its affiliates:

Productive Oil and Gas Wells at December 31, ~~2012~~2013

Productive Productive

Oil Wells

Gas Wells

Gross

Net

Gross

Net

United States 50,180
32,758
14,248
7,737

Other Americas 736
548
48
28

Africa 2,579
861
17
7

Asia 13,127
11,335
3,148
1,924

Australia 815
458
65
11

Europe 330
97
227
48

Total Consolidated Companies 67,767
46,057
17,753
9,755

Equity Affiliates 1,300
456
7
2

Total Including Affiliates 69,067
46,513
17,760
9,757

Multiple completion wells included above 876
602
407
369




	Productive		Productive
	Oil Wells		Gas Wells
	Gross	Net	Gross	Net

United States	50,533	33,068	14,217	7,740
Other Americas	1,042	690	60	37
Africa	2,608	870	17	7
Asia	13,530	11,693	3,318	1,953
Australia	808	428	69	12
Europe	373	95	173	42
Total Consolidated Companies	68,894	46,844	17,854	9,791
Affiliates	1,364	476	7	2
Total Including Affiliates	70,258	47,320	17,861	9,793

Multiple completion wells included above	952	677	413	372

Reserves

Refer to Table V beginning on page ~~FS-67~~FS-64 for a tabulation of the company’s proved net crude oil and natural gas reserves by geographic area, at the beginning of ~~2010~~2011 and each year-end from ~~2010~~2011 through ~~2012~~2013. 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, ~~2012~~2013, are summarized in the discussion for Table V. Discussion is also provided regarding the nature of, status of and planned future activities associated with the development of proved undeveloped reserves. The company recognizes reserves for projects with various development periods, sometimes exceeding five years. The external factors that impact the duration of a project include scope and complexity, remoteness or adverse operating conditions, infrastructure constraints, and contractual limitations.

The net proved reserve balances at the end of each of the three years ~~2010~~2011 through ~~2012~~2013 are shown in the following table.

Net Proved Reserves at December 31


	2012	2011	2010	2013	2012	2011
Liquids — Millions of barrels	Liquids — Millions of barrels			Liquids — Millions of barrels
Consolidated Companies	4,353	4,295	4,270	4,303	4,353	4,295
Affiliated Companies	2,128	2,160	2,233	2,042	2,128	2,160
Total Liquids	6,481	6,455	6,503	6,345	6,481	6,455
Natural Gas — Billions of cubic feet	Natural Gas — Billions of cubic feet			Natural Gas — Billions of cubic feet
Consolidated Companies	25,654	25,229	20,755	25,670	25,654	25,229
Affiliated Companies	3,541	3,454	3,496	3,476	3,541	3,454
Total Natural Gas	29,195	28,683	24,251	29,146	29,195	28,683
Oil-Equivalent — Millions of barrels	Oil-Equivalent — Millions of barrels			Oil-Equivalent — Millions of barrels
Consolidated Companies	8,629	8,500	7,729	8,582	8,629	8,500
Affiliated Companies	2,718	2,736	2,816	2,621	2,718	2,736
Total Oil-Equivalent	11,347	11,236	10,545	11,203	11,347	11,236

Acreage

At December 31, ~~2012~~2013, the company owned or had under lease or similar agreements undeveloped and developed crude oil and natural gas properties throughout the world. The geographical distribution of the company’s acreage is shown in the following table.

Acreage at December 31, ~~2012~~2013
(Thousands of Acres)

Developed and

Undeveloped*

Developed

Undeveloped

Gross

Net

Gross

Net

Gross

Net

United States 6,399
5,161
7,788
5,008
14,187
10,169

Other Americas 26,913
15,898
1,348
365
28,261
16,263

Africa 8,848
3,840
3,328
1,373
12,176
5,213

Asia 30,795
14,189
1,487
857
32,282
15,046

Australia 11,427
5,728
918
239
12,345
5,967

Europe 5,481
4,153
648
126
6,129
4,279

Total Consolidated Companies 89,863
48,969
15,517
7,968
105,380
56,937

Equity Affiliates 938
430
259
102
1,197
532

Total Including Affiliates 90,801
49,399
15,776
8,070
106,577
57,469




					Developed and
	Undeveloped*		Developed		Undeveloped
	Gross	Net	Gross	Net	Gross	Net

United States	6,237	5,125	7,381	4,714	13,618	9,839
Other Americas	26,898	15,397	1,389	384	28,287	15,781
Africa	15,490	8,995	3,286	1,362	18,776	10,357
Asia	31,897	15,485	1,498	871	33,395	16,356
Australia	19,418	13,655	912	236	20,330	13,891
Europe	5,205	4,045	489	73	5,694	4,118
Total Consolidated Companies	105,145	62,702	14,955	7,640	120,100	70,342
Affiliates	935	429	262	103	1,197	532
Total Including Affiliates	106,080	63,131	15,217	7,743	121,297	70,874


*	The gross undeveloped acres that will expire in ~~2013~~2014, ~~2014~~2015 and ~~2015~~2016 if production is not established by certain required dates are ~~1,254, 3,629~~2,627, 2,430 and ~~3,141,~~701, 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 to third parties ~~192~~285 billion cubic feet of natural gas through ~~2015~~2016. 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 include a variety of pricing terms, including both indexed and fixed-price contracts.

Outside the United States, the company is contractually committed to deliver a total of ~~791~~871 billion cubic feet of natural gas to third parties from ~~2013~~2014 through ~~2015~~2016 ~~for~~from operations in Australia, Colombia, Denmark, the Netherlands 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-62~~FS-59 for details associated with the company’s development expenditures and costs of proved property acquisitions for ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011.

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, ~~2012~~2013. A “development well” is a well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Development Well Activity

Wells Drilling
Net Wells Completed

at 12/31/12 2012 2011 2010

Gross

Net

Prod.

Dry

Prod.

Dry

Prod.

Dry

United States 78
45
941
6
909
9
634
7

Other Americas 13
6
50
—
37
—
32
—

Africa 10
4
23
—
29
—
33
—

Asia 75
35
566
15
549
15
445
15

Australia 8
4
—
—
—
—
—
—

Europe 5
—
9
—
6
—
4
—

Total Consolidated Companies 189
94
1,589
21
1,530
24
1,148
22

Equity Affiliates 6
3
26
—
25
—
8
—

Total Including Affiliates 195
97
1,615
21
1,555
24
1,156
22




	Wells Drilling		Net Wells Completed
	at 12/31/13		2013		2012		2011
	Gross	Net	Prod.	Dry	Prod.	Dry	Prod.	Dry
United States	134	75	1,101	4	941	6	909	9
Other Americas	60	39	127	—	50	—	37	—
Africa	9	3	20	1	23	—	29	—
Asia	77	42	535	5	566	6	549	6
Australia	4	2	—	—	—	—	—	—
Europe	3	—	3	—	9	—	6	—
Total Consolidated Companies	287	161	1,786	10	1,589	12	1,530	15
Affiliates	30	13	25	—	26	—	25	—
Total Including Affiliates	317	174	1,811	10	1,615	12	1,555	15

Exploration Activities

Refer to Table I on page ~~FS-62~~FS-59 for detail on the company’s exploration expenditures and costs of unproved property acquisitions for ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011.

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, ~~2012~~2013. “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.

Exploratory Well Activity

Wells Drilling
Net Wells Completed

at 12/31/12 2012 2011 2010

Gross

Net

Prod.

Dry

Prod.

Dry

Prod.

Dry

United States 11

8

4

—

5

1

1

1

Other Americas 2

1

8

—

1

—

—

1

Africa 1

—

1

2

1

—

1

—

Asia 1

1

12

3

10

1

5

5

Australia 1

1

3

—

4

1

5

2

Europe 1

1

1

2

—

1

—

—

Total Consolidated Companies 17

12

29

7

21

4

12

9

Equity Affiliates —

—

—

—

1

—

—

—

Total Including Affiliates 17

12

29

7

22

4

12

9




	Wells Drilling		Net Wells Completed
	at 12/31/13		2013		2012		2011
	Gross	Net	Prod.	Dry	Prod.	Dry	Prod.	Dry

United States	10	7	17	2	4	—	5	1
Other Americas	3	1	12	2	8	—	1	—
Africa	2	1	—	—	1	2	1	—
Asia	4	3	13	4	12	3	10	1
Australia	2	1	3	—	3	—	4	1
Europe	2	—	2	2	1	2	—	1
Total Consolidated Companies	23	13	47	10	29	7	21	4
Affiliates	—	—	—	—	—	—	1	—
Total Including Affiliates	23	13	47	10	29	7	22	4

Review of Ongoing Exploration and Production Activities in Key Areas

Chevron’s ~~2012~~2013 key upstream activities, some of which are also discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations, beginning on page ~~FS-2,~~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-11.~~E-10.

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

Chevron has exploration and production activities in most of the world’s major hydrocarbon basins. The company’s upstream strategy is to grow profitably in core areas, build new legacy positions and commercialize the company’s equity natural gas resource base while growing a high-impact global natural gas business. The map above indicates Chevron’s primary areas for exploration and production.

United States

Upstream activities in the United States are concentrated in California, the Gulf of Mexico, Colorado, Louisiana, Michigan, New Mexico, Ohio, Oklahoma, Pennsylvania, Texas, West Virginia and Wyoming. Average net oil-equivalent production in the United States during ~~2012~~2013 was ~~655,000~~657,000 barrels per day.

In California, the company has significant production in the San Joaquin Valley. In ~~2012,~~2013, net daily production averaged ~~163,000~~162,000 barrels of crude oil, 7069 million cubic feet of natural gas and 4,000 barrels of natural gas liquids (NGLs). Approximately

86 percent of the crude oil production is considered heavy oil (typically with API gravity lower than 22 degrees).

During ~~2012,~~2013, net daily production for the company’s combined interests in the Gulf of Mexico ~~shelf and deepwater areas, and the onshore fields in the region, was 153,000~~averaged 143,000 barrels of crude oil, ~~395~~347 million cubic feet of natural gas and ~~16,000~~15,000 barrels of NGLs.

Chevron was engaged in various exploration and development activities in the deepwater Gulf of Mexico during ~~2012.~~2013. The Jack and St. Malo fields are ~~located within 25 miles of each other and are~~ being jointly ~~developed.~~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 and a 50.7 percent~~Field. Both fields are company-operated. Chevron's interest in the production host ~~facility. Both fields are company operated. Drilling operations progressed during 2012, with five~~facility was reduced to 40.6 percent in 2013, after the owners of ~~10 planned wells drilled. At~~a third-party oil field acquired an interest in the ~~end of 2012, project activities were more than 57 percent complete, with subsea and floating production unit installation activities expected in second-half 2013.~~host. The facility ~~is planned to have~~has a design capacity of ~~177,000~~170,000 barrels of ~~oil-equivalent~~crude oil and 42 million cubic feet of natural gas per day to accommodate production from the Jack/St. Malo development ~~which~~and third-party tiebacks. Development drilling activities continued during the year, and the FPU was moored at the offshore location in fourth quarter 2013. At the end of 2013, project activities were 74 percent complete and first oil is ~~estimated to have maximum total daily production of 94,000 barrels of oil equivalent, plus production from a nearby third-party field.~~expected in late 2014. Total project costs for the initial phase of development are estimated at $7.5 ~~billion and start-up is expected in 2014. The fields have an estimated production life of 30 years.~~billion. Proved reserves have been recognized for this project.

In ~~2012, an~~2013, work continued on the evaluation of additional development opportunities ~~was initiated~~ for the Jack and St. Malo fields. Stage 2, the first phase of future development work, is expected to include four additional development wells, two each at the Jack and the St. Malo fields. Front-end engineering and design (FEED) activities ~~are planned to begin~~began in ~~mid-2013.~~mid-2013, and a final investment decision is expected in 2015. At the end of ~~2012,~~2013, proved reserves had not been recognized for the Jack/St. Malo Stage 2 ~~project.~~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 production life of 30 years.

Fabrication ~~and development drilling~~ continued in ~~2012~~2013 for the 60 percent-owned and operated Big Foot ~~project.~~Project. The development plan includes a 15-slot drilling and production platform with water injection facilities and a design capacity of ~~79,000~~75,000 barrels of crude oil ~~equivalent~~and 25 million cubic feet of natural gas per day. At the end of ~~2012,~~2013, project activities were 6884 percent complete, and ~~topside module installation~~the platform is ~~planned for mid-2013. First~~expected to be towed to the location in third quarter 2014. Total project costs are estimated at $5.1 billion, and first production is anticipated in ~~2014.~~2015. The field has an estimated production life of 20 years. Proved reserves have been recognized for this project.

Tahiti 2 is the second development phase for the 58 percent-owned and operated Tahiti Field, and is designed to increase recovery ~~and return production to more than 100,000 barrels of crude oil per day. The project includes~~ from the main producing interval by adding

two ~~additional~~ production wells, three water injection wells and water injection facilities. ~~Drilling commenced on the first production well in early 2012, and water injection began in first quarter 2012.~~ Start-up of the first production well ~~is expected by third~~occurred in fourth quarter 2013. ~~Proved~~Additional infill drilling is scheduled for the Tahiti Field from 2014 through 2016. The next development phase, the Tahiti Vertical Expansion Project, is being planned, with FEED expected in 2015. At the end of 2013, proved reserves ~~have~~had not been recognized for the infill drilling or the Tahiti ~~2 project, and the field~~Vertical Expansion Project. The Tahiti Field has an estimated production life of 30 years.

The company has a 42.9 percent nonoperated working interest in the Tubular Bells Field. Development drilling ~~began in second quarter 2012,~~continued during 2013, and plans include three producing and two injection wells, with a subsea tieback to a third-party production facility. First oil is ~~anticipated in~~planned for third quarter 2014, ~~and maximum~~with total ~~daily~~ production is expected to reach ~~40,000 to 45,000~~44,000 barrels of ~~oil-equivalent.~~oil-equivalent per day. The field has an estimated production life of 25 years. ~~The initial recognition of proved~~Proved reserves have been recognized for ~~the project occurred in 2012.~~this project.

Chevron has a 20.3 percent nonoperated working interest in the Caesar and Tonga area. First production occurred in first quarter 2012, and maximum total daily production reached about 62,000 barrels of oil-equivalent by year-end 2012. Drilling operations on the fourth development well concluded in early 2013, and the well is expected to commence production in second quarter 2013.

The company has a 15.6 percent nonoperated working interest in the Mad Dog Field. The next development phase, the Mad Dog II ~~Project. FEED commenced in second quarter 2012 and a final investment decision~~Project, is ~~expected in 2014.~~planned to develop the southern portion of the Mad Dog Field. The project ~~includes the construction and installation of a new production and drilling spar facility~~was recycled in 2013 and is expected to ~~add incremental maximum total daily production of 120,000 to 140,000 barrels of oil equivalent.~~reenter FEED in late 2014. At the end of ~~2012,~~2013, proved reserves had not been recognized for this project.

~~In 2012,~~ Chevron ~~signed commercial agreements for~~holds a 20 percent nonoperated working interest in the Stampede ~~project allowing for~~Project, which includes the joint development of the Knotty Head and Pony fields. ~~Chevron holds~~The development plans include a ~~20 percent nonoperated working interest in this joint development.~~tension leg platform with a planned design capacity of 80,000 barrels of crude oil and 40 million cubic feet of natural gas per day. The project entered FEED in second quarter 2013, and a final investment decision is expected ~~to enter FEED by mid-2013.~~in fourth quarter 2014. At the end of ~~2012,~~2013, proved reserves had not been recognized for this project.

Pre-FEED activities continue at the 55 percent-owned and operated Buckskin Project. The project is expected to enter FEED in 2015. The Moccasin discovery, located 12 miles from Buckskin, is a potential tieback opportunity into Buckskin.

Deepwater exploration activities in ~~2012~~2013 included participation in ~~three~~six exploratory wells — ~~one~~three appraisal and ~~two wildcats.~~three wildcat. Drilling ~~began on an~~of the first appraisal well at the

43.8 percent-owned and operated Moccasin discovery was

completed in ~~fourth~~third quarter ~~2012.~~2013. Drilling ~~activities were placed on hold in early 2013 for equipment repair and are~~of an appraisal well at the Buckskin discovery is expected to ~~resume later this year. Moccasin and~~be completed in second quarter 2014. Drilling at the 5540 percent-owned and operated ~~Buckskin~~Coronado prospect resulted in a crude oil discovery ~~located 12 miles apart, could be jointly developed upon~~in the ~~successful completion of additional~~Lower Tertiary Wilcox formation in first quarter 2013. Drilling commenced on the first Coronado appraisal well in December 2013. The company also completed drilling ~~planned for 2013. A second Coronado~~a wildcat well ~~began drilling~~at the 30 percent-owned and operated Rio Grande prospect in ~~second quarter 2012, targeting the lower Tertiary Wilcox formation. Drilling was completed in February~~December 2013 and at the ~~results are under evaluation. Chevron also had a 20 percent nonoperated working interest~~67.5 percent-owned and operated Oceanographer prospect in ~~the Hummer Shallow wildcat well.~~January 2014.

Chevron added 15eight leases to ~~the~~its deepwater portfolio as a result of awards from the central Gulf of Mexico lease sale held in ~~mid-2012.~~first quarter 2013. In addition, Chevron ~~submitted the highest bids on 28 additional~~acquired three deepwater leases atfrom the western Gulf of Mexico lease sale held in ~~late 2012.~~

Besides the activities connected with development and exploration projects in the Gulf of Mexico, the company also has contracted liquefied natural gas (LNG) offloading, storage and regasification capacity at the Sabine Pass LNG facility and natural gas transportation capacity in a third-party pipeline system connecting the terminal to the U.S. natural gas pipeline grid.third quarter 2013.

Company activities in the ~~mid-continental~~midcontinental United States include operated and nonoperated interests in properties primarily in Colorado, New Mexico, Oklahoma, Texas and Wyoming. During ~~2012,~~2013, the company’s net daily production in these areas averaged ~~90,000~~96,000 barrels of crude oil, ~~600~~610 million cubic feet of natural gas and ~~29,000~~28,000 barrels of ~~NGL's.~~NGLs.

In West Texas, the company continues to pursue development of ~~tight oil~~shale and ~~liquids-rich shale~~tight resources in the Midland Basin’s Wolfcamp play and several plays in the Delaware Basin through use of advanced drilling and completion technologies. Additional production growth is expected from interests in these formations in future years. In ~~October 2012, an acquisition of more than 350,000 gross~~June 2013, the company reached a joint development agreement covering 104,000 total acres ~~in New Mexico augmented the company's leasehold position~~ in the Delaware ~~Basin~~Basin. In East Texas, the company continued development, at a managed pace, of multiple stacked reservoirs, including the Travis Peak, Cotton Valley, Bossier and ~~surrounding areas.~~Haynesville zones, during 2013.

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 ~~2012,~~2013, the company's net daily production in these areas averaged ~~approximately 138~~220 million cubic feet of natural gas. In ~~2012,~~2013, development of the Marcellus Shale ~~proceeded~~continued at a measured pace, focused on improving execution capability and reservoir understanding. Activities in the Utica Shale during ~~2012~~2013 included ~~acquisition of regional seismic data in eastern Ohio to identify core areas. The company commenced~~ drilling ~~on four~~seven exploratory ~~wells during the year.~~wells. This initial activity was focused on acquiring data necessary for potential future development. ~~The company also holds a 49 percent interest in Laurel Mountain Midstream, LLC, an affiliate that owns more than 1,200 miles of natural gas gathering lines servicing the Marcellus.~~

Other Americas

“Other Americas” is composed of Argentina, Brazil, Canada, Colombia, Greenland, Suriname, Trinidad and Tobago, and Venezuela. Net oil-equivalent production from these countries averaged ~~230,000~~226,000 barrels per day during ~~2012, including the company’s share of synthetic oil production.~~

2013.

Canada: Chevron has interests in oil sands projects and shale acreage in ~~Alberta,~~Alberta; shale acreage and ~~an LNG~~a liquefied natural gas (LNG) project in British ~~Columbia,~~Columbia; exploration, development and production projects offshore in the Atlantic ~~region,~~region; and exploration and discovered resource interests in the Beaufort Sea region of the Northwest Territories. Average net oil-equivalent production during ~~2012~~2013 was ~~69,000~~71,000 barrels per day, composed of ~~25,000~~27,000 barrels of crude oil, 49 million cubic feet of natural gas and 43,000 barrels of synthetic oil from oil sands.

The company holds a 20 percent nonoperated working interest in the Athabasca Oil Sands Project (AOSP). 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. During 2012, ramp-up from the AOSP Expansion 1 Project continued to boost production toward the total daily design capacity of approximately 255,000 barrels. Additionally, a final investment decision was reached in mid-2012Construction work progressed during 2013 on the Quest Project, a carbon capture and sequestration project that is designed to capture and store more than one million tons ~~annually~~ of carbon dioxide produced annually by bitumen processing at the AOSP by 2015.

In February 2013, Chevron acquired a 50 percent-owned and operated interest in the Kitimat LNG ~~project~~ and ~~proposed~~ Pacific Trail Pipeline projects, and a 50 percent nonoperated working interest in 644,000 total acres in the Horn River and Liard shale gas basins in British Colombia. The Kitimat ~~project~~LNG Project is planned to include a two-train, 10.0 million-metric-ton-per-year LNG ~~facility,~~facility. The total production capacity for the project is expected to be 1.6 billion cubic feet of natural gas per day. Activities during 2013 included FEED, early site preparation and ~~at the time of acquisition, FEED activities were in progress.~~LNG marketing activities.

Chevron holds a 26.9 percent nonoperated working interest in the Hibernia Field and a 23.6 nonoperated working interest in the unitized Hibernia Southern Extension (HSE) areas offshore Atlantic Canada. The HSE development is expected to increase the economic life of the Hibernia Field. ~~Fabrication~~During 2013, two subsea water injection wells began drilling, and installation of ~~topside and~~ subsea equipment ~~progressed in 2012.~~was initiated. Full production start-up is expected in ~~2014.~~2015. Proved reserves have been recognized for ~~the initial wells drilled.~~this project.

The company holds a 26.6 percent nonoperated working interest in the ~~heavy-oil~~heavy oil Hebron Field, also offshore Atlantic Canada. The development plan includes a concrete, gravity-based platform with a design capacity of 150,000 barrels of crude oil per day. ~~The maximum total daily crude oil production is expected to be 134,000 barrels. FEED~~Procurement and construction activities ~~were completed~~progressed in ~~2012, and a final investment decision was made in December 2012.~~2013. Project costs are estimated at $14 billion. The project has an expected economic life of 30 years, and first oil is expected in 2017.~~The initial recognition of proved~~ Proved reserves have been recognized for ~~the project occurred in 2012.~~this project.

~~During 2012, drilling continued on a multiwell program on~~ In 2013, the ~~100 percent-owned and operated leases~~company acquired 86,000 total additional acres in the Duvernay shale formation in Alberta.Drilling for these tight resources continued in 2013, with completion of a

multiwell program. Nine wells were completed and tied into production facilities by early 2014.

The company also holds a 40 percent nonoperated working interest in exploration ~~licenses and leases~~rights for two blocks in the Flemish Pass Basin offshore Newfoundland. During 2013, the company relinquished its license in the Orphan Basin located offshore Newfoundland and ~~Orphan basins~~Exploration License 1109 located offshore ~~Atlantic Canada and~~Labrador. The company also holds two exploration licenses in the Beaufort Sea region of the Northwest Territories ~~including~~and a ~~35.4~~40 percent nonoperated working interest in the ~~offshore~~ Amauligak discovery.

In addition, Chevron holds interests in the Aitken Creek and Alberta Hub natural gas storage facilities, which have aggregate total capacity of approximately 100 billion cubic feet. These facilities are located in western Canada near the Duvernay, Horn River, Liard and Montney shale gas plays.

Greenland: In December ~~2012,~~2013, Chevron ~~relinquished its~~acquired a 29.2 percent ~~nonoperated working~~ interest in ~~Exploration License 2007/26, which includes Block 4~~and operatorship of two blocks located in the Kanumas Area, offshore ~~West~~the northeast cost of Greenland. Blocks 9 and 14 cover 1.2 million acres. The acquisition of seismic data is planned for 2014.

Argentina: Chevron holds operated interests in four concessions in the Neuquen ~~Basin. Working~~Basin, with working interests ~~range~~ranging from 18.8 percent to 100 ~~percent.~~percent, and a 50 percent nonoperated working interest in one concession. Net oil-equivalent production in ~~2012~~2013 averaged ~~22,000~~19,000 barrels per day, composed of ~~21,000~~18,000 barrels of crude oil and 46 million cubic feet of natural gas. During ~~2012, two~~2013, the company completed four exploratory wells in El Trapial concession, targeting ~~shale~~oil and gas ~~and tight oil resources were drilled~~ in the Vaca Muerta ~~formation in the El Trapial concession. In early 2013, a third exploratory well commenced drilling and the results of the previous wells were under evaluation.~~Shale. Chevron plans to ~~drill three additional appraisal~~continue production testing the wells ~~in 2013. The~~during 2014. El Trapial concession expires in 2032.

In addition, Chevron signed agreements during 2013 to advance the Loma Campana Project to develop the Vaca Muerta Shale. In 2013, 109 wells were drilled, and the drilling plan includes more than 140 wells in 2014.

Brazil: Chevron holds working interests in three deepwater fields in the Campos Basin: Frade (51.7 percent-owned and operated), Papa-Terra and Maromba (37.5 percent and 30 percent nonoperated working interests, respectively). Net oil-equivalent production in ~~2012~~2013 averaged 6,000 barrels per day, composed of ~~6,000~~5,000 barrels of crude oil and 2 million cubic feet of natural gas.

In ~~March 2012,~~second quarter 2013, the company received regulatory approval to partially resume production ~~was suspended as a precautionary measure~~ at the Frade ~~Field while studies were conducted~~Field. A plan to ~~better understand the geology in the area. Production is expected to partially~~ resume ~~in 2013 subject to necessary~~production from additional existing wells has been submitted for regulatory ~~approvals.~~approval. The concession that includes the Frade Field expires in 2025.

~~During 2012, construction activities and development drilling continued~~First production from the initial well occurred in fourth quarter 2013 for the Papa-Terra ~~project.~~Project. The project includes a floating production, storage and offloading vessel (FPSO) and a tension leg wellhead platform, with a design capacity of 140,000 barrels of crude oil and 35 million cubic feet of natural gas per day. ~~First production~~The concession that contains the Papa-Terra Field expires in 2032. Additional development drilling is ~~expected in second-half 2013. Proved reserves have been recognized~~planned for ~~this project.~~ 2014.

Evaluation of the field development concept for Maromba ~~continued in 2012 with submission of an initial Plan of Development to the authorities in September.~~ continues. At the end of ~~2012,~~2013, proved reserves had not been recognized for this project. ~~These concessions expire~~The concession containing the Maromba Field expires in 2032.

In May 2013, Chevron was awarded a 50 percent interest in and operatorship of Block CE-M715. The deepwater block covers 81,000 total acres and is located in the Ceará Basin offshore equatorial Brazil. Acquisition of seismic data is planned for 2014.

Colombia: The company operates the offshore Chuchupa and the onshore Ballena and Riohacha natural gas fields ~~as part of the Guajira Association contract. In exchange, Chevron~~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. Daily net production averaged 216 million cubic feet of natural gas in ~~2012.~~2013.

Suriname: ~~In November 2012,~~ Chevron ~~acquired~~holds a 50 percent nonoperated working interest in Blocks 42 and 45 offshore Suriname. ~~Under the agreements, the company would assume the role of operator in the event of commercial discoveries.~~ In 2013, ~~planned exploration activities include~~ seismic data ~~acquisition and processing.~~was acquired for Block 45. The data is being processed in 2014 to plan for the drilling of an exploration well in 2015.

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 and Dolphin Deep producing natural gas fields and the Starfish development. Net production in ~~2012~~2013 averaged 173 million cubic feet of natural gas per day. Development of the Starfish Field ~~commenced in third quarter 2012,~~continued during 2013, and first gas is expected in ~~2014.~~2015. Natural gas from the project ~~will~~is planned to supply existing contractual commitments. Proved reserves have been recognized for this project. Chevron also holds a 50 percent-owned and operated interest in the Manatee Area of Block 6(d), where the Manatee discovery comprises a single cross-border field with Venezuela's Loran Field in Block 2. In ~~2012,~~2013, cross-border agreements were signed between the governments of Trinidad and Tobago and Venezuela, and work continued on maturing commercial development concepts.

Venezuela: ~~Chevron holds interests in~~Chevron's production activities are performed by two ~~producing~~ affiliates ~~located~~ in western Venezuela and one ~~producing~~ affiliate in the Orinoco Belt. Chevron has a 30 percent interest in the Petropiar affiliate that operates the Hamaca ~~heavy-oil~~heavy oil production and upgrading project located in Venezuela’s Orinoco Belt, a 39.2 percent interest in the Petroboscan affiliate that operates the Boscan Field in ~~the~~ western ~~part of the country,~~Venezuela, and a 25.2 percent interest in the Petroindependiente affiliate that operates the LL-652 Field in Lake Maracaibo. The company’s share of net oil-equivalent production during ~~2012~~2013 from these operations averaged ~~68,000~~65,000 barrels per day, composed of ~~64,000~~61,000 barrels of liquids and 2726 million cubic feet of natural gas.

~~gas.~~

Chevron holds a 34 percent interest in the Petroindependencia affiliate that is working toward commercialization of Carabobo 3, a ~~heavy-oil~~heavy oil project located within the Carabobo Area of the Orinoco Belt. ~~During 2012, work continued~~Project activities in 2013 focused on ~~conceptual engineering for the potential~~assessing development ~~project.~~alternatives.

The company operates and ~~has~~holds a ~~working~~60 percent interest ~~of 60percent~~ in Block 2 and a 100 percent interest in Block 3 in the Plataforma Deltana area offshore eastern Venezuela. The Loran Field in Block 2 and the Manatee Field in Trinidad and Tobago form a single, cross-border field that lies along the maritime border of Venezuela ~~which includes~~and Trinidad and Tobago. During 2013, cross-border agreements were signed between the ~~Loran Field. During 2012,~~governments of Venezuela and Trinidad and Tobago, and work continued on maturing commercial development concepts.

Africa

In Africa, the company is engaged in upstream activities in Angola, Chad, Democratic Republic of the Congo, Liberia, Morocco, Nigeria, the Republic of the Congo, Sierra Leone and South Africa. Net oil-equivalent production in Africa averaged ~~451~~437,000 barrels per day during ~~2012.~~2013.

Angola: Chevron holds company-operated working interests in offshore Blocks 0 and 14 and nonoperated working interests in offshore Block 2 and the onshore Fina Sonangol Texaco (FST) concession area. In addition, Chevron has a 36.4 percent interest in Angola LNG Limited. Net production from these operations in ~~2012~~2013 averaged ~~137,000~~133,000 barrels of oil-equivalent per day.

~~The company operates the 39.2 percent-owned Block 0, which averaged 98,000 barrels per day of net liquids production in 2012. The Block 0 concession extends through 2030.~~

~~Work~~The company operates the 39.2 percent-owned Block 0, which averaged 90,000 barrels per day of net liquids production in 2013. The Block 0 concession extends through 2030.

Construction activities on Mafumeira Sul, the second development stage offor the Mafumeira Field in Block 0, ~~continued~~progressed in ~~2012. Mafumeira Sul, a project to develop the southern portion of the field, reached a final investment decision in 2012.~~2013. Development plans include a central processing facility, two wellhead platforms, subsea pipelines, and 34 producing and 16 water injection wells. The facility has a design capacity of 150,000 barrels of liquids and 350 million cubic feet of natural gas per day. First production is planned for 2015, ~~with maximum total~~and ramp-up to full production is expected to ~~reach 110,000 barrels of crude oil and 10,000 barrels of liquefied petroleum gas (LPG) per day.~~continue until 2017. The project is estimated to cost $5.6 billion. ~~The initial recognition of proved~~Proved reserves have been recognized for this ~~project occurred in 2012.~~project.

A project to develop the Greater ~~Vanza/~~Longui Area of Block 0 is ~~scheduled~~expected to enter FEED in ~~second-half 2013.~~first-half 2014. FEED activities ~~continued~~progressed during ~~2012~~2013 on the south extension of the N’Dola Field development ~~with~~and work continues toward a final investment ~~decision expected in 2014.~~decision. The facility is planned to have a design capacity of 28,000 barrels of crude oil and 50 million cubic feet of natural gas per day. At the end of ~~2012,~~2013, proved reserves had not been recognized for these projects.

Work continued in ~~2012~~2013 on ~~the final stage of~~ the Nemba Enhanced Secondary Recovery Stage 1 ~~and~~& 2 Project in Block 0. Installation ~~activities are scheduled to begin~~of the platform was completed in ~~2013,~~early 2014, and project start-up is expected in ~~early~~ 2015. ~~Maximum total~~Total daily production is expected to ~~reach 13,000~~be 12,000 barrels of ~~oil-equivalent per day.~~ crude oil. Proved reserves have been recognized for this project.

Also in Block 0, drilling ~~commenced on a post-salt/pre-salt dual objective~~of an exploration well in Area A ~~in late 2012 and~~ was completed in early ~~2013. The results~~2013 and resulted in a discovery in the post-salt Vermelha interval. Plans for future development are under evaluation. ~~An additional~~Drilling of an appraisal well in the Minzu Pinda reservoir commenced in late 2013 and is planned to be completed in second quarter 2014. A pre-salt exploration well in Area A is planned for ~~second-half 2013, along with one pre-salt and one post-salt appraisal well in Area B.~~first-half 2014.

~~In the~~The company operates and holds a 31 ~~percent-owned~~percent interest in a production-sharing contract (PSC) for deepwater Block ~~14, net~~14. Net production in ~~2012~~2013 averaged ~~28,000~~27,000 barrels of liquids per day. Development and production rights for the various producing fields in Block 14 expire between 2023 and 2028.

~~In June 2012,~~Planning continues on the ~~project to develop the~~multireservoir, deepwater Lucapa Field in Block 14, ~~entered FEED. Development plans include an FPSO and 17 subsea wells.~~located on the north rim of the Congo River Canyon. The ~~facility is planned~~project was recycled in 2013 to ~~have~~conduct additional subsurface studies over a ~~design capacity of 80,000 barrels of crude oil per day. A final investment decision is expected in 2014.~~12-month period. During the year, development alternatives were evaluated for the Malange Field, and the project is expected to enter FEED in ~~mid-2013.~~early 2014. At the end of ~~2012,~~2013, proved reserves had not been recognized for these projects.

In addition to the exploration and production activities in Angola, Chevron has a 36.4 percent interest in Angola LNG Limited, which ~~will operate~~operates an onshore natural gas liquefaction plant in Soyo, Angola. The plant ~~is designed~~has a 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. ~~The~~ This is the world's first LNG

plant ~~reached mechanical completion,~~supplied with associated gas, where the natural gas is a by-product of crude oil production. Feedstock for the plant originates from multiple fields and ~~commissioning activities continued through 2012.~~operators. The first LNG shipment from the plant ~~is expected to occur~~occurred in second quarter 2013. ~~The project~~Commissioning and testing of the plant continued through the end of 2013. Due to the variability in the associated gas that supplies Angola LNG, the plant is

~~estimated~~ expected to ~~cost $10 billion.~~operate at approximately 50 percent of capacity until permanent plant modifications are completed in 2015, allowing Angola LNG to consistently produce at full capacity. Total daily production in 2013 averaged 83 million cubic feet of natural gas (30 million net) and 2,000 barrels of NGLs (1,000 net). The anticipated economic life of the project is in excess of 20 years. ~~Proved reserves have been recognized for the producing operations associated with this project.~~

The company also holds a 38.1 percent interest in ~~a pipeline~~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 project continued in ~~2012, and the~~2013, with project ~~is expected to be completed in 2014.~~completion targeted for 2015.

Angola-Republic of the Congo Joint Development Area: Chevron operates and holds a 31.3 percent interest in the Lianzi ~~development zone,~~Unitization Zone, located in an area shared equally by Angola and the Republic of the Congo. ~~A final investment decision for the Lianzi development project was reached in July 2012.~~ The project scope includes four producing wells and three water injection wells with a subsea tieback to an existing platform in Block 14. ~~First production is anticipated in 2015, and maximum total daily production is expected to be~~The project has a design capacity of 46,000 barrels of crude ~~oil. The initial recognition of proved~~oil per day. First production is planned for 2015. Proved reserves have been recognized for ~~the project occurred in 2012.~~this project.

Democratic Republic of the Congo: Chevron has a 17.7 percent nonoperated working interest in an offshore concession. Daily net production in ~~2012~~2013 averaged ~~3,000~~2,000 barrels of ~~oil-equivalent.~~crude oil.

Republic of the Congo: Chevron has a 31.5 percent nonoperated working interest in the offshore Haute Mer permit areas (Nkossa, Nsoko and Moho-Bilondo) ~~and a 29.3 percent nonoperated working interest in the Kitina permit area, all of which are offshore.~~. The licenses for ~~Kitina,~~ Nsoko, Nkossa and Moho-Bilondo expire in ~~2014,~~ 2018, 2027 and 2030, respectively. In September 2013, the company sold its nonoperated interest in the Kitina permit area. Net production averaged ~~19,000~~13,000 barrels of ~~oil-equivalent~~liquids per day in ~~2012.~~2013.

~~FEED activities~~A final investment decision was reached in first quarter 2013 for the Moho Nord ~~project,~~Project, located in the Moho-Bilondo development ~~area, continued in 2012.~~area. The $10 billion project includes a new facilities hub and a subsea tieback to the existing Moho-Bilondo ~~floating~~FPU. First production ~~unit. Maximum~~is expected in 2015, and total daily production ~~is expected to be 127,000~~of 140,000 barrels of crude oil ~~per day. A final investment decision~~ is expected in ~~first quarter 2013 and start-up is planned for 2015. At the end~~2017. The initial recognition of ~~2012,~~ proved reserves ~~had not been recognized for this project.~~occurred in 2013.

Chad/Cameroon: Chevron has a 25 percent nonoperated working interest in crude oil producing operations in southern Chad and an approximate 21 percent interest in two affiliates that own an export pipeline that transports crude oil to the coast of Cameroon. Average daily net crude oil production from the Chad fields in ~~2012~~2013 was ~~23,000 barrels of oil-equivalent.~~18,000 barrels. The Chad producing operations are conducted under a concession that expires in 2030.

Nigeria: Chevron holds a 40 percent interest in 13 operated concessions, predominantly in the onshore and near-offshore regions of the Niger Delta. The company ~~operates under a joint-venture arrangement in this region with the Nigerian National Petroleum Corporation, which owns a 60 percent interest. The company~~ also owns varying interests in ~~four~~three operated and six nonoperated deepwater blocks. In ~~2012,~~2013, the company’s net oil-equivalent production in Nigeria averaged ~~269,000~~268,000 barrels per day, composed of ~~238,000~~233,000 barrels of crude oil, ~~165~~182 million cubic feet of natural gas and ~~4,000~~5,000 barrels of ~~LPG.~~liquefied petroleum gas (LPG).

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 ~~2012,~~2013, drilling continued on a 10-well, Phase 2 development program, Agbami 2, that is expected to offset field decline and maintain plateau production. Drilling is expected to continue through 2015. The ~~first well~~third development phase, Agbami 3, is a five-well drilling program expected to offset field decline. The project entered FEED in ~~this program commenced production~~early 2014, and a final investment decision is expected in ~~second quarter 2012.~~second-half 2014. Drilling is scheduled to continue through 2017. The leases that contain the Agbami Field expire in 2023 and 2024.

~~The company~~Chevron holds a 30 percent nonoperated ~~working~~ interest in the deepwater Usan ~~project~~Field in OML 138. ~~Production commenced in first quarter 2012,~~Ramp-up continued during 2013, and total daily production at year-end 2012 was 81,000 barrels of crude oil and 3 million cubic feet of natural gas. The facilities have a maximum total production capacity of 180,000 barrels of crude oil per day. The production-sharing contract (PSC) expires in 2023.additional development drilling is planned for 2014 through 2017.

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. The proposed development plan involves subsea wells tied back to an FPSO with a planned design

capacity of 225,000 barrels of crude oil per day. The project achieved FEED in second quarter 2013, and a final investment decision is expected ~~to enter FEED~~ in ~~2013.~~late 2014. At the end of ~~2012,~~2013, no proved reserves were recognized for this project.

In the Niger Delta region, the company reached a final investment decision in ~~early~~ 2013 on the Dibi Long-Term Project that is designed to rebuild the Dibi facilities and replace the Early Production System facility. The facilities ~~are planned to~~ have a ~~maximum production~~design capacity of 70,000 barrels of crude oil per day, and start-up is expected in 2016.

Also in the Niger Delta region, ramp-up activity continued at the Escravos Gas Plant (EGP). During ~~2012,~~2013, construction continued on Phase 3B of the EGP project, which is designed to gather 120 million cubic feet of natural gas per day from eight ~~offshore~~near-shore fields and to compress and transport the natural gas to onshore facilities. The Phase 3B project is expected to be completed in 2016. Proved reserves associated with this project have been recognized.

~~The~~Construction activities progressed during 2013 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 2016. Proved reserves have been recognized for the project.

Chevron is the operator of and has a 75 ~~percent-owned and operated~~percent interest in athis 33,000-barrel-per-day gas-to-liquids facility at ~~Escravos that is being developed with the Nigerian National Petroleum Corporation.~~Escravos. The ~~33,000-barrel-per-day~~ facility is designed to process 325 million cubic feet per day of natural ~~gas supplied from~~gas. Production is scheduled to commence in first-half 2014, and the ~~Phase 3A expansion of EGP. As of early 2013, overall work on the project was more than 89 percent complete and start-up~~first product shipment is ~~planned for late 2013.~~ expected to occur in second-half 2014.The estimated cost of the ~~plant~~project is ~~$9.5~~$10 billion.

The company has a 40 percent-owned and operated interest in the Onshore Asset Gas Management project that is designed to restore approximately 125 million cubic feet per day of natural gas production from certain onshore fields that have been shut in since 2003 due to civil unrest. Construction was completed in third quarter 2012, and start-up commenced in late 2012.

In deepwater exploration, ~~the company has~~Chevron operates and holds a 27100 percent ~~nonoperated working~~ interest in ~~Oil Prospecting License (OPL) 223~~OML 132, where an exploration well ~~was drilled in third quarter 2012.~~at Aparo North is planned for 2014. In addition, Chevron operates and holds a 95 percent interest in the deepwater Nsiko discovery in OML ~~140. Additional~~140, where additional exploration activities are planned for ~~2013 and~~ 2014.

Shallow-water exploration activities ~~in 2012 included reprocessing~~to identify and evaluate potential deep hydrocarbon targets are ongoing. Reprocessing of 3-D seismic data ~~from~~over OML 49 and regional mapping activities over OML 86 and OML 88 ~~and regional mapping activities.~~continued in 2013.

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.

Liberia: Chevron holds a 45 percent interest in and operates three deepwater blocks off the coast of Liberia. In ~~July 2012, the company farmed down its interest from 70 percent to 45 percent in these blocks. Exploration wells were drilled in blocks LB-11 and LB-12 during 2012. In 2013,~~2014, the company plans ~~to mature~~additional drilling ~~prospects~~ based on the evaluation of 3-D seismic data and 2012 drilling ~~results and 3-D seismic data.~~results.

Morocco: In early 2013, the company ~~entered into agreements to acquire~~acquired a 75 ~~percent~~percent-owned and operated interest in three deepwater areas offshore Morocco. The areas, Cap Rhir Deep, Cap Cantin Deep and Cap Walidia Deep, encompass approximately 7.2 million acres. ~~Once the award is finalized,~~The acquisition of seismic data is ~~planned.~~planned for 2014.

Sierra Leone: ~~In September 2012, the~~The company ~~announced that it had been awarded operatorship and~~holds a 55 percent interest in and operates a concession off the coast of Sierra Leone. The concession contains two deepwater blocks, with a combined area of approximately 1.4 million acres. ~~Acquisition~~Interpretation of 2-D seismic data is planned for ~~2013.~~2014.

South Africa: In ~~December 2012,~~2013, the company ~~entered into an agreement to seek~~continued seeking shale gas exploration opportunities in the Karoo Basin in South ~~Africa. This~~Africa under an agreement that allows Chevron and its partner to work together ~~over a five-year period~~ to obtain exploration permits in the 151 million-acre basin.

Asia

In Asia, the company is engaged in upstream activities in Azerbaijan, Bangladesh, Cambodia, China, Indonesia, Kazakhstan, the Kurdistan Region of Iraq, Myanmar, the Partitioned Zone located between Saudi Arabia and Kuwait, the Philippines, Russia, Thailand, and Vietnam. During ~~2012,~~2013, net oil-equivalent production averaged ~~1,061,000~~1,087,000 barrels per day.

Azerbaijan: Chevron holds an 11.3 percent nonoperated working interest in the Azerbaijan International Operating Company (AIOC), which produces crude oil from the ~~Azeri-Chirag-Gunashli~~Azeri-

Chirag-Gunashli (ACG) ~~project.~~fields. The company’s daily net

production ~~from AIOC~~ averaged 28,000 barrels of oil-equivalent in ~~2012.~~2013. AIOC operations are conducted under a PSC that expires in 2024.

~~During 2012, construction progressed~~In January 2014, production commenced on the next development phase of the ACG project, which ~~will~~ further ~~develop~~develops the ~~deepwater~~Chirag and Deepwater Gunashli ~~Field.~~fields. The ~~total estimated cost of the~~ project ~~is $6 billion, with~~has an incremental ~~targeted maximum total daily production~~design capacity of ~~103,000~~183,000 barrels of ~~oil-equivalent. Production is expected to begin in late 2013. Proved reserves have been recognized for this project.~~crude oil and 285 million cubic feet of natural gas per day.

Chevron also has an 8.9 percent interest in the Baku-Tbilisi-Ceyhan (BTC) affiliate, which owns and operates a crude oil export pipeline from Baku, Azerbaijan, through Georgia to Mediterranean deepwater port facilities at Ceyhan, Turkey. The BTC ~~Pipeline~~pipeline has a capacity of ~~1.2~~1 million barrels per day and transports the majority of ACG production. Another production export route for crude oil is the Western Route Export Pipeline, ~~wholly owned and~~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 participates in two major upstream developments in western Kazakhstan. The company holds a 50 percent interest in the Tengizchevroil (TCO) affiliate, which is operating and developing the Tengiz and Korolev crude oil fields under a concession that expires in 2033. Chevron’s net oil-equivalent production in ~~2012~~2013 from these fields averaged ~~286,000~~321,000 barrels per day, composed of ~~218,000~~243,000 barrels of crude oil, ~~301~~347 million cubic feet of natural gas and ~~18,000~~20,000 barrels of NGLs. During ~~2012,~~2013, 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 ~~via~~by rail to Black Sea ~~ports.~~ports and via the BTC pipeline to the Mediterranean.

In ~~2012,~~2013, FEED ~~activities were initiated~~continued for three projects. The Wellhead Pressure Management Project (WPMP) is designed to maintain production capacity and extend the production plateau from existing assets. The Capacity and Reliability (CAR) Project is designed to reduce facility bottlenecks and increase plant efficiency and reliability. The Future Growth Project (FGP) is designed to increase total daily ~~crude oil~~ production by 250,000 to 300,000 barrels of oil-equivalent and to increase ~~the~~ ultimate recovery offrom the reservoir. The project ~~will~~plans to expand the utilization of sour gas injection technology proven in existing operations. During 2013, the company and the government of Kazakhstan signed a memorandum of understanding that establishes the framework and mutual commitments to progress the FGP and the WPMP. The final investment decision on the CAR Project was made in February 2014.The final investment decisions on ~~these projects~~the WPMP and the FGP are planned for ~~late 2013.~~second-half 2014. At the end of ~~2012,~~2013, proved reserves have ~~only~~ been recognized for the ~~Wellhead Pressure Management Project.~~

~~Also at TCO, start-up commenced on~~WPMP and the ~~Sulfur Expansion~~CAR Project ~~in December 2012. This project is designed to eliminate routine additions to sulfur inventory.~~

~~In June 2012, the company's~~The company holds an 18 percent nonoperated working interest in the Karachaganak Field ~~was reduced from 20 percent to 18 percent as a result of a 2011 agreement with the Republic of Kazakhstan government. Operations and development of the field are conducted~~ under a PSC that expires in 2038. During ~~2012,~~2013, Karachaganak net oil-equivalent production averaged ~~61,000~~57,000 barrels per day, composed of ~~37,000~~34,000 barrels of liquids and ~~139~~135 million cubic feet of natural gas. Access to the CPC and Atyrau-Samara (Russia) pipelines enabled ~~approximately 35,000~~32,000 net barrels per day of Karachaganak liquids to be exported and sold at world-market prices during ~~2012.~~2013. The remaining liquids were sold into local and Russian markets. ~~During 2012,~~In 2013, work continued on identifying the optimal scope for ~~the~~ future expansion of the field. At the end of ~~2012,~~2013, proved reserves had not been recognized for ~~any further~~a future expansion.

Kazakhstan/Russia: Chevron has a 15 percent interest in the CPC affiliate. During ~~2012,~~2013, CPC transported an average of ~~approximately 657,000~~706,000 barrels of crude oil per day, including ~~590,000~~635,000 barrels per day from Kazakhstan and ~~67,000~~71,000 barrels per day from Russia. ~~During 2012,~~In 2013, work continued on the 670,000-barrel-per-day expansion of the pipeline capacity with ~~the mechanical~~ completion of the offshore loading system. The ~~$5.4 billion~~ project is ~~expected to be~~being implemented in ~~three~~ phases, with capacity increasing progressively until reaching maximum capacity of 1.4 million barrels per day in 2016. The ~~first increase in~~incremental capacity ofis expected to reach 400,000 barrels per day by year-end 2014, with the first increase expected to be realized by March 2014. The expansion is expected to provide additional transportation capacity that accommodates a portion of the future growth in ~~2014.~~

~~Turkey:~~ ~~In December 2012, Chevron relinquished its 50 percent interest in License 3921 in the Black Sea.~~TCO production.

Bangladesh: Chevron holds a 9899 percent interest in two operated PSCs covering Block 12 ~~(Bibiyana)~~(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 from these operations in ~~2012~~2013 averaged ~~94,000~~113,000 barrels per day, composed of ~~550~~663 million cubic feet of natural gas and 2,000 barrels of ~~liquids.~~condensate.

In April 2012, start-up of the Muchai compression project was achieved. This project supports additional natural gas production capacity of 80 million cubic feet per day from the Bibiyana, Jalalabad and Moulavi Bazar fields. The Bibiyana Expansion ~~project achieved a final investment decision in July 2012. The project scope~~Project includes ainstallation of two gas ~~plant expansion,~~processing trains, additional development ~~drilling~~wells and an enhanced liquids recovery ~~unit,~~facility, and ~~is expected to increase total maximum daily production by more than~~has an incremental design capacity of 300 million cubic feet of natural gas and 4,000 barrels of ~~condensate.~~condensate per day. First production is expected in late 2014. ~~The initial recognition of proved~~Proved reserves have been recognized for this ~~expansion project occurred in 2012.~~project.

Cambodia: Chevron owns a 30 percent interest in and operates the 1.2 million-acre Block A, located in the Gulf of Thailand. In ~~2012,~~2013, the company ~~progressed~~continued discussions on the production permit and commercial terms for development of Block A. The planned development consists of a wellhead platform and a floating storage and offloading vessel (FSO). A final investment decision is pending resolution of commercial terms. At the end of ~~2012,~~2013, proved reserves had not been recognized for the project.

Myanmar: Chevron has a 28.3 percent nonoperated working interest in a PSC for the production of natural gas from the Yadana and Sein fields, 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. The company’s average net natural gas production in ~~2012~~2013 was 9496 million cubic feet per day.

Thailand: Chevron has operated and nonoperated working interests in multiple offshore blocks in the Gulf of Thailand. The company’s net oil-equivalent production in ~~2012~~2013 averaged ~~243,000~~229,000 barrels per day, composed of ~~67,000~~62,000 barrels of crude oil and condensate and ~~1.1~~1 billion cubic feet of natural gas. The company’s natural gas production is sold to the domestic market under long-term sales ~~contracts.~~agreements.

The company holds operated interests in the Pattani Basin with ownership interests ranging from 35 percent to 80 percent. Concessions for producing areas within this basin expire between 2020 and 2035. Chevron 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.

In the Pattani Basin, the Ubon Project entered FEED in second quarter 2013, and a final investment decision is expected in 2015. The facilities have a planned design capacity of 35,000 barrels of liquids and 115 million cubic feet of natural gas per day. At the end of 2013, proved reserves had not been recognized for this project.

During ~~2012,~~2013, the company drilled ~~six~~five exploration wells in the Pattani Basin, and ~~four~~three were ~~successful~~successful..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: Chevron is the operator of two PSCs in the Malay Basin off the southwest coast of Vietnam. The company has a 42.4 percent interest in a PSC that includes Blocks B and 48/95, and a 43.4 percent interest in a PSC for Block 52/97.

The Block B Gas Development Project ~~is designed to produce natural gas from the Malay Basin for delivery to state-owned Petrovietnam. The project~~ includes installation of wellhead and hub platforms, an FSO, a central processing platform and a pipeline to shore. ~~FEED continued during 2012. Maximum total daily production is expected to be 490~~The facilities have a design capacity of 640 million cubic feet of natural gas and ~~4,000~~21,000 barrels of ~~condensate.~~liquids per day. A final investment decision for the development is pending resolution of commercial terms. Concurrent with the commercial negotiations, the company is also evaluating these assets for possible divestment. At the end of ~~2012,~~2013, proved reserves had not been recognized for the development project.

~~During 2012, the company drilled two exploratory wells in Block 52/97, and both were successful.~~

China: Chevron has operated and nonoperated working interests in several areas in China. The company’s net oil-equivalent production in ~~2012~~2013 averaged ~~21,000~~20,000 barrels per day, composed of ~~20,000~~19,000 barrels of crude oil and condensate and 96 million cubic feet of natural gas.

The company operates and holds a 49 percent interest in the

Chuandongbei PSC, located onshore in the ~~onshore~~ Sichuan Basin. The full development includes two ~~new sour-gas~~sour gas processing plants ~~with an aggregate inlet design capacity of 740 million cubic feet per day,~~ connected by a natural gas gathering system to five fields.

During ~~2012,~~2013, the company continued construction ~~of the first~~on both natural gas processing ~~plant, and site preparation commenced for the second natural gas processing plant.~~plants. The first plant's initial ~~plant, with an expected maximum total production~~three trains have a design outlet capacity of 258 million cubic feet per day, iswith the first train targeted for mechanical completion atin 2014. Start-up is scheduled for 2015. The total design outlet capacity for the ~~end of 2013. Planned maximum total natural gas production~~project is 558 million cubic feet per ~~day, and the~~day. The total project cost is estimated to be $6.4 billion. Proved reserves have been recognized for this project. The PSC for Chuandongbei expires in ~~2037.~~2038.

The company holds a 59.2 percent-owned and operated interest in deepwater Block 42/05 in the South China ~~Sea, which covers~~Sea. In late 2013 and early 2014, an exploratory ~~acreage of approximately 1.3 million acres. During 2012, the company~~well was drilled ~~two exploration wells~~ in ~~South China Sea deepwater Blocks 53/30 and 64/18, and both were unsuccessful. In November 2012, the company relinquished its interest in deepwater Blocks 53/30 and 64/18.~~

~~Additional 3-D seismic data was acquired over~~ Block 42/05 and ~~further exploration drilling is under evaluation. In 2012,~~was unsuccessful. Chevron ~~entered into an agreement to acquire~~also has a 100 percent-owned and operated interest in shallow-water Blocks 15/10 and 15/~~28, which cover approximately 1.4 million exploratory acres. Government approval is expected in first-half~~28. In 2013, ~~and a~~the company acquired two 3-D seismic ~~survey~~surveys in these blocks. Processing of this seismic data is ~~expected to commence in mid-2013.~~ongoing.

During ~~2012,~~2013, the company drilled ~~an initial~~two exploratory ~~well~~wells for shale gas in the Qiannan ~~Basin. Evaluation of the well continues in early 2013. Additional drilling is planned for 2013.~~Basin and both were unsuccessful.

The company also has ~~nonoperated working interests of 32.7 percent in Blocks 16/08 and 16/19 in the Pearl River Mouth Basin and~~ nonoperated working interests of 24.5 percent in the QHD 32-6 Field and 16.2 percent in Block 11/19 in the Bohai ~~Bay.~~Bay and 32.7 percent in Block16/19 in the Pearl River Mouth Basin.

Philippines: The company holds a 45 percent nonoperated working interest in the Malampaya natural gas ~~field located 50 miles offshore Palawan Island.~~field. Net oil-equivalent production in ~~2012~~2013 averaged ~~24,000~~23,000 barrels per day, composed of ~~120~~119 million cubic feet of natural gas and ~~4,000~~3,000 barrels of condensate. ~~During 2012, plans progressed on~~The Malampaya Phase 2 Project is designed to ~~drill~~maintain capacity. During 2013, work progressed with two ~~additional~~ infill wells ~~and~~being completed. First production is expected to ~~add depletion~~commence in first quarter 2014 with compression ~~facilities. Start-up is planned for 2014.~~facilities to follow in 2015. Proved reserves have been recognized for this project.

Chevron ~~also~~holds a 40 percent interest in an affiliate that develops and produces geothermal resources in southern Luzon, which ~~supply~~supplies steam to third-party ~~637-megawatt~~ power generation ~~facilities.~~facilities with a combined operating capacity of 692 megawatts. During ~~fourth quarter 2012, Chevron sold 60 percent of its interest in these geothermal operations in order to secure~~2013, the affiliate secured a ~~25-year geothermal operating~~renewable energy service contract ~~with the Philippine government~~ for ~~the continued development and operation of the steam fields.~~an additional 25 years. Chevron also has a 90 percent-owned and operated interest in the Kalinga geothermal prospect area in northern ~~Luzon~~Luzon. In 2013, Chevron held negotiations to sell down equity to comply with local law and ~~is in~~to secure a 25-year term for a renewable energy service contract. Negotiations are planned to continue into 2014. The company continues to assess the ~~early phase of geological and geophysical assessments.~~prospect area.

Indonesia: Chevron holds operated and nonoperated working interests in Indonesia. ~~The~~In Sumatra, the company ~~has~~holds a 100 percent-owned and operated ~~interests~~interest in the Rokan ~~and~~PSC. The Siak ~~PSCs onshore Sumatra. Chevron~~PSC expired in November 2013. Chevron also operates four PSCs in the Kutei Basin, located offshore ~~East~~eastern Kalimantan. These interests range from 62 percent to 92.5 percent. Chevron also has ~~51 percent operated working interests in two exploration blocks in western Papua, West Papua I and West Papua III, and~~ a 25 percent nonoperated working interest in a joint venture in Block B in the South Natuna ~~Sea.~~Sea and a 51 percent operated working interest in two exploration blocks in western Papua, West Papua I and West Papua III.

The company’s net oil-equivalent production in ~~2012~~2013 from its interests in Indonesia averaged ~~198,000~~193,000 barrels per day, composed of ~~158,000~~156,000 barrels of liquids and ~~236~~225 million cubic feet of natural gas. The largest producing field is Duri, located in the Rokan PSC. Duri has been under steamflood since 1985 and is one of the world’s largest steamflood developments. The ~~North Duri Development is divided into multiple expansion areas. Construction began~~company continues to implement projects designed to sustain production from existing reservoirs. The company progressed construction on the Duri Area 13 expansion project ~~in fourth quarter 2012.~~during 2013. First production ~~is scheduled for late~~occurred in second-half 2013, and ~~maximum total daily~~ramp-up of production ~~of 17,000 barrels of crude oil~~ is expected ~~to be reached in~~through 2016. The Rokan PSC expires in 2021.

During ~~2012,~~2013, two deepwater natural gas development projects in the Kutei Basin progressed under a single plan of development. InCollectively, these projects are referred to as the ~~first~~Indonesia Deepwater Development. One of these projects, ~~Chevron completed FEED for the~~ Gendalo-Gehem, ~~deepwater natural gas project, and a final investment decision is expected during 2014. The project~~ includes two separate hub developments, each with its own FPU, subsea drill centers, natural gas and condensate pipelines, and an onshore receiving facility. ~~Maximum total daily production from the~~ The

project ~~is expected to be about~~has a planned design capacity of 1.1 billion cubic feet of natural gas and ~~31,000~~47,000 barrels of ~~condensate. Gas from~~condensate per day. During 2013, the ~~project~~company received bids for all major contracts. A final investment decision is ~~expected~~planned for 2014, but is subject to ~~be used~~

~~domestically and for LNG export.~~the timing of government approvals. The company’s working interest is approximately 63 percent. At the end of ~~2012,~~2013, proved reserves had not been recognized for this project.

~~In the second of these projects, the company requested bids for all major contracts for the~~The other project, Bangka, ~~deepwater natural gas project. A final investment decision is expected in 2013. The project scope~~ includes a subsea tieback to the West Seno FPU, with a ~~floating production unit, and maximum total daily production is expected to be about 114~~planned design capacity of 115 million cubic feet of natural gas and 4,000 barrels of ~~condensate.~~condensate per day. The company’s working interest is 62 percent. Bids were received on all major contracts during 2013. A final investment decision is planned for 2014, but is subject to the timing of government approvals. At year-end ~~2012,~~2013, proved reserves had not been recognized for this project.

In Sumatra, ~~four~~three exploration wells were ~~drilled. Two wells were successful~~drilled with one discovery. Further exploration and ~~the results for two wells are under evaluation in early 2013. Appraisal and exploration~~appraisal drilling is planned for ~~2013.~~2014. In the West Papua exploration blocks, which are in close proximity to a third-party LNG facility, 2-D seismic data acquisition and processing was completed ~~for West Papua I in 2012 and is planned for completion~~ for West Papua III in 2013.

In West Java, the company operates and holds a 95 percent interest in the Darajat geothermal field, which supplies steam to a power plant with a total operating capacity of ~~259~~270 megawatts. Chevron also operates and holds a 100 percent interest in the Salak geothermal field in West Java, which supplies steam to a power plant with a total operating capacity of 377 megawatts. In Sumatra, Chevron operates and holds a 95 percent interest in the North Duri Cogeneration Plant, supplying up to 300 megawatts of power to the company's Sumatra operations and steam in support of the Duri steamflood project. In the Suoh-Sekincau prospect area of South Sumatra, the company holds a 95 percent-owned and operated interest in a license to explore and develop a geothermal prospect.

Kurdistan Region of Iraq: ~~In July 2012, the~~The company ~~announced the acquisition of~~operates and holds an 80 ~~percent-owned and operated~~percent interest in two PSCs covering the Rovi and Sarta ~~blocks~~blocks.In June 2013, the company acquired the operatorship and an 80 percent interest in the ~~Kurdistan Region of Iraq.~~Qara Dagh Block. The blocks cover a combined area of ~~approximately 232,000~~444,000 acres. In second-half 2013, Chevron commenced exploration drilling in the Rovi and Sarta blocks, and drilling on two wells is expected to be completed in first quarter 2014.Acquisition of seismic data and further exploration drilling is planned during 2014.

Partitioned Zone (PZ): Chevron holds a concession to operate the Kingdom of Saudi Arabia's 50 percent interest in the ~~petroleum~~hydrocarbon resources in the onshore area of the PZ between Saudi Arabia and Kuwait. The concession expires in 2039.

During ~~2012,~~2013, the company's average net oil-equivalent production was ~~90,000~~87,000 barrels per day, composed of ~~86,000~~84,000 barrels of crude oil and 2119 million cubic feet of natural gas. During ~~2012,~~2013, the company continued a steam injection pilot project in the First Eocene carbonate reservoir ~~that was initiated in 2009.~~and achieved thermal maturity. A project to expand the steam injection pilot to the Second Eocene reservoir ~~is expected to enter~~entered FEED ~~by late~~in September 2013. Development planning also continued ~~during 2012~~ on a full-field steamflood application in the Wafra Field. The Wafra Steamflood Stage 1 Project has a planned design capacity of 80,000 barrels of crude oil per day and is expected to enter FEED in late 2014. At the end of ~~2012,~~2013, proved reserves had not been recognized for any of these steamflood developments.

Also in ~~2012,~~2013, FEED activities continued on the Central Gas Utilization Project. The project is intended to increase natural gas utilization and eliminate routine flaring. A final investment decision is expected in late 2014. At year-end ~~2012,~~2013, proved reserves had not been recognized for this project.

Australia

In Australia, the company’s upstream efforts are concentrated off the northwest coast. During ~~2012,~~2013, the average net oil-equivalent production from Australia was ~~99,000~~96,000 barrels per day.

Chevron holds a 47.3 percent ownership interest across most of the Greater Gorgon Area and is the operator of the Gorgon Project, which ~~combines~~includes the development of the Gorgon and nearby ~~Io/Jansz~~Jansz-Io natural gas fields. The development includes a three-train, 15.6 million-metric-ton-per-year LNG facility, a carbon ~~sequestration project~~dioxide injection facility and a domestic natural gas plant. ~~Maximum~~The total ~~daily~~ production ~~from~~capacity for the project is expected to ~~reach~~be approximately 2.6 billion cubic feet of natural gas and 20,000 barrels of ~~condensate. Start-up of the~~condensate per day. Gorgon plant start-up and first ~~train~~cargo is ~~expected in late 2014, leading to the first LNG cargo in first quarter 2015.~~planned for mid-2015. Total estimated project costs for the first phase of development are ~~$52~~$54 billion. Proved reserves have been recognized for this project. The project's estimated economic life exceeds 40 years from the time of start-up.

Work on the Gorgon project continued during 2013 with approximately 75 percent of the project activities complete at year-end. Through early 2014, 20 of 21 Train 1 LNG plant modules had been delivered and installed at Barrow Island, with the final module expected to arrive by mid-year. In addition, installation activities were completed for the domestic gas pipeline from Barrow Island to the mainland, enabling delivery of commissioning gas. Progress continued on the construction of the LNG tanks and jetty, with completion of LNG Tank 1 expected in second-half 2014. Start-up of the first gas turbine generator, allowing first natural gas into the LNG plant, is planned for late 2014.

~~Work on~~Construction of the upstream facilities also advanced with 14 of the 18 subsea wells drilled and completed. The offshore pipelines from both fields to Barrow Island were completed in 2013. Infield flow lines and subsea structures continue to be installed in 2014. Perforation of all eight development wells in the Gorgon ~~project continued during 2012. As of year-end 2012, more than 55 percent~~Field and completion of the ~~project activities had been completed. Key milestones achieved in 2012 were the arrival and installation of the first LNG plant modules, subsea wellhead trees and subsea pipelines. The development~~Jansz-Io drilling program ~~also progressed during 2012.~~are expected in late 2014.

Chevron has signed binding, long-term LNG Sales and Purchase Agreements with six Asian customers for delivery of about 4.8 million metric tons of LNG per year, which brings delivery commitments to ~~about~~ 65 percent of Chevron’s share of LNG from this project. Discussions continue with potential customers to increase long-term sales to 85around 80 percent of Chevron’s net LNG offtake. Chevron also has binding long-term agreements for delivery of about 65 million cubic feet per day of natural gas to Western Australian natural gas consumers starting in 2015, and the company continues to market additional natural gas quantities from the Gorgon Project.

AnThe evaluation of expansion ~~project~~options to ~~develop a fourth train at~~increase the production capacity of Gorgon ~~LNG facility~~ is ~~expected~~planned to ~~enter FEED~~continue in ~~late 2013. At the end of 2012, proved reserves had not been recognized for the fields associated with this project.~~2014.

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 located at Ashburton North, ~~along~~on the ~~northwest~~ coast of Western Australia. The company plans to supply natural gas to the facilities from three company-operated licenses containing the Wheatstone ~~Field~~and Iago fields. Chevron holds a 64.1 percent interest in the LNG facilities and an 80.2 percent interest in the offshore licenses. Total production capacity for the Wheatstone and Iago fields and nearby ~~Iago Field. Maximum total daily production from these and~~ third-party fields is expected to be ~~about~~approximately 1.6 billion cubic feet of natural gas and 30,000 barrels of ~~condensate.~~condensate per day. Start-up of the first train is expected in 2016. Total estimated ~~project~~ costs for the ~~first~~foundation phase ~~of development~~ are $29 billion. Proved reserves have been recognized for this project. The project's estimated economic life exceeds 30 years from the time of start-up.

In ~~2012,~~2013, construction and fabrication activities progressed, with a focus on delivering site infrastructure to enable efficient plant construction. Offshore dredging, pipeline installation and drilling of development wells commenced during the year. Fabrication also progressed on key upstream components, ofincluding the offshore platform and subsea equipment. ~~Chevron signed additional commercial agreements that decreased Chevron's interest~~Delivery of the first Train 1 LNG plant modules is expected in second-half 2014, along with the installation of the offshore ~~licenses to 80.2 percent~~platform steel gravity-based structure, completion of the natural gas export trunkline and incompletion of the LNG ~~facilities to 64.1 percent.~~Tank 1 foundation. The project was approximately 25 percent complete at year-end.

The company also executed ~~agreements~~binding long-term Sales and Purchase Agreements with two Asian customers for the delivery of additional ~~volumes of~~ LNG. As of year-end ~~2012, more than 80~~2013, 85 percent of Chevron’s equity LNG offtake ~~was covered~~is committed under long-term agreements with customers in Asia. In addition, the company ~~has begun marketing~~continues to market its equity share of natural gas ~~of approximately 120 million cubic feet per day~~ to Western Australia ~~natural gas~~ consumers.

During ~~2012 and early~~ 2013, the company announced ~~seven~~two natural gas discoveries in the Carnarvon Basin. These include natural gas discoveries at the 47.3 percent-owned and operated Pontus prospect in Block WA-37-L, the 50 percent-owned and operated Satyr prospect in Block WA-374-P, the 50 percent-owned and operated Pinhoe prospect in Block WA-383-P, the 50 percent-owned and operated Arnhem prospect in Block

~~WA-364-P, and the~~ 50 percent-owned and operated Kentish Knock South prospect in Block ~~WA-365-P.~~WA-365-P and the 50 percent-owned and operated Elfin prospect in Block WA-268-P. These discoveries are expected to contribute to potential expansion opportunities at company-operated LNG ~~facilities.~~projects.

Chevron has a 16.7 percent nonoperated working interest in the North West Shelf (NWS) Venture in Western Australia. Daily net production ~~from the project during 2012~~in 2013 averaged ~~20,000~~19,000 barrels of crude oil and condensate, ~~428~~419 million cubic feet of natural gas, and ~~4,000~~3,000 barrels of LPG. Approximately 70 percent of the natural gas was sold in the form of LNG to major utilities in Asia, primarily under long-term contracts. The remaining natural gas was sold to the Western Australia domestic market. The concession for the NWS Venture expires in 2034.

~~The~~Production commenced at the North Rankin 2 ~~project continued to advance during 2012, with start-up expected~~Project in ~~mid-2013.~~fourth quarter 2013. The project is designed to recover remaining low-pressure natural gas from the North Rankin and Perseus fields to meet gas supply needs and maintain NWS daily production ~~capacity~~ of about 2 billion cubic feet of natural gas and 39,000 barrels of condensate. ~~Total estimated projects costs are $5.4 billion. Proved reserves have been recognized for the project.~~ The project's estimated economic life exceeds 20 years from the time of start-up.

~~In October 2012, the~~ The company exchanged its 16.7 percent interest in the East Browse leases and its 20 percent interest in the West Browse leases for financial consideration and a 33.3 percent interest in the WA-205-P and WA-42-R blocks in the Carnarvon Basin and now holds ~~a 100 percent interest in these blocks, which contain the Clio and Acme fields. The company retains other~~ nonoperated working interests ranging from 24.8 percent to 50 percent in three ~~other~~ blocks in the Browse Basin.

In ~~Block WA-274-P, drilling~~2013, the company acquired nonoperated working interests in two onshore blocks covering 810,000 total acres in the ~~fourth quarter 2012 resulted~~Nappamerri Trough, located in the Cooper Basin region in central Australia. The acquisition includes a ~~natural gas discovery at the Crown prospect.~~30 percent interest in PEL 218 in South Australia and an 18 percent interest in ATP 855 in Queensland. Pending favorable results of an exploration drilling program, Chevron could earn nonoperated working interests of 60 percent in PEL 218 and 36 percent in ATP 855.

In October 2013, the company acquired exploration interests in offshore Blocks EPP44 and EPP45, which span more than 8 million acres in the Bight Basin off the South Australian coast. Chevron is the operator and holds a 100 percent interest.

Europe

In Europe, the company is engaged in upstream activities in Bulgaria, Denmark, Lithuania, the Netherlands, Norway, Poland, Romania, Ukraine and the United Kingdom. Net oil-equivalent production in Europe averaged ~~114,000~~94,000 barrels per day during ~~2012.~~2013.

Denmark: Chevron ~~has~~holds a 12 percent nonoperated working interest in the ~~partner-operated~~ Danish Underground Consortium (DUC), which produces crude oil and natural gas from 13 fields in the Danish North Sea. Net oil-equivalent production in ~~2012~~2013 from DUC averaged ~~36,000~~28,000 barrels per day, composed of ~~24,000~~19,000 barrels of crude oil and 7455 million cubic feet of natural gas. In July 2012, as part of a 30-year concession extension, the state-owned Danish North Sea Fund received a 20 percent ownership of the DUC in exchange for the previous 20 percent government profit-take arrangements and the company's interest was reduced from 15 percent to 12 percent. The concession expires in 2042.

Netherlands: Chevron operates and holds interests ranging from ~~34.1~~23.5 percent to 80 percent in 1011 blocks in the Dutch sector of the North Sea. In ~~2012,~~2013, the company’s net oil-equivalent production was 9,000 barrels per day, composed of 2,000 barrels of crude oil and 4241 million cubic feet of natural gas. The company is evaluating these assets for possible divestment.

Norway: The company holds a 7.6 percent nonoperated working interest in the Draugen Field. The company’s net production averaged ~~3,000~~2,000 barrels of oil-equivalent per day during ~~2012.~~2013. The company is evaluating this asset for possible divestment. Chevron is the operator and has a 40 percent working interest in exploration licenses PL 527 and PL 598. Both licenses are in the deepwater portion of the Norwegian Sea.

United Kingdom: The company’s average net oil-equivalent production in ~~2012~~2013 from 10nine offshore fields was ~~66,000~~55,000 barrels per day, composed of ~~46,000~~40,000 barrels of liquids and ~~122~~94 million cubic feet of natural gas. Most of the 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 jointly operated Britannia Field.

At the 73.7 percent-owned and operated Alder Project, FEED activities were completed and a final investment decision was made in late 2013. The project is proceeding as a single subsea well tied back 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. First production is scheduled for 2016. The initial recognition of proved reserves occurred in 2013 for this project.

Procurement and fabrication activities ~~began in 2012~~continued during 2013 for the Clair Ridge ~~project,~~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. Total ~~planned~~ design capacity is 120,000 barrels of crude oil and 100 million cubic feet of natural gas per ~~day, and the~~day. The total estimated cost of the project is $7 billion. Production is scheduled to begin in 2016, and the project's estimated economic life exceeds 40 years from the time of start-up. Proved reserves have been recognized for the Clair Ridge ~~project.~~Project.

At the ~~70 percent-owned and operated Alder discovery, FEED activities progressed during 2012, and a final investment decision is planned for late 2013. The~~ 40 percent-owned and operated Rosebank Project northwest of the Shetland Islands, ~~entered FEED in July 2012. A final investment decision is planned~~the company continues to assess alternatives for ~~2014. Maximum total daily production is expected to reach 64,000 barrels~~the optimum development of ~~liquids and 42 million cubic feet of natural gas.~~the Rosebank Field. At the end of ~~2012,~~2013, proved reserves had not been recognized for ~~these projects.~~this project.

An ~~unsuccessful~~ exploration well was drilled atin License P1189, and the ~~Aberlour prospect west~~results of this well are under evaluation. In License P1191, 3-D seismic data was acquired to map the area southwest of the ~~Shetland Islands. Full~~Rosebank Field. In the North Sea, an exploration well to further delineate the southern extension of the Jade Field was drilled in second-half 2013, and ~~partial block relinquishments were made during 2012~~the results are under ~~Licenses P119 (Strathspey area), P1026, P1191 and P1194 (Aberlour).~~evaluation.

Bulgaria: In ~~June~~ 2011, the Bulgarian government advised that Chevron had submitted a winning tender for aan exploration permit ~~for exploration in a 1.1 million-acre area~~ in northeast Bulgaria. ~~In January 2012,~~However, prior to execution of the license agreement, the ~~Bulgarian~~ government announced the withdrawal of the decision ~~awarding the permit and~~as the Bulgarian parliament imposed a ban on hydraulic ~~fracturing, a technology commonly used for shale development and production.~~fracturing. Chevron continues to work with the government of Bulgaria to provide the necessary assurances ~~to both the government and the public~~ that shale hydrocarbons ~~from shale~~ can be developed safely and responsibly.

Lithuania: ~~In October 2012,~~ Chevron ~~acquired~~holds a 50 percent interest in a Lithuanian exploration and production company. In 2013, ~~the affiliate plans to commence shale~~two exploration ~~activities~~wells were drilled in the 394,000-acre Rietavas ~~block.~~Block, and the results of the wells are under evaluation. Drilling of a third exploration well commenced in January 2014 and is planned to be completed during second quarter 2014.

Poland: Chevron holds four shale concessions in southeast Poland (Frampol, Grabowiec, Krasnik and Zwierzyniec). All four exploration licenses are 100 percent-owned and operated

and comprise a total of 1.1 million acres. ~~During 2012, drilling was completed on~~In 2013, the first ~~well~~exploration wells were drilled in the Zwierzyniec and Krasnik concessions. A 3-D seismic survey is under way on the Grabowiec concession and ~~evaluation of this well continued into early 2013. An initial well was also drilled in the Frampol concession in 2012. Drilling of a well in the Zwierzyniec concession commenced in~~

~~December 2012, and continued exploratory drilling of the concessions~~ is planned ~~for 2013.~~to be completed in second quarter 2014. Exploration activities are planned to continue during 2014.

Romania: The company holds a 100 percent interest in and operates the 1.6 million-acre Barlad ~~shale concession. This license is located~~Shale concession in northeast ~~Romania and covers 1.6 million acres.~~Romania. Drilling of anthe first exploration well is planned ~~for second-half 2013.~~to commence in second quarter 2014. In ~~March 2012, three additional petroleum concession agreements, covering approximately 670,000 acres in southeast Romania, were approved by the government of Romania.~~addition, Chevron holds a 100 percent interest in and operates three concessions covering 670,000 acres in southeast Romania. In October 2013, the ~~concessions. Acquisition~~company commenced acquisition of 2-D seismic data across ~~these concessions is expected to commence in second-half 2013.~~two of the three concessions.

Ukraine: In ~~2012,~~November 2013, Chevron ~~was the successful bidder for the right to exclusively negotiate~~signed a ~~50-year~~ PSC with the government of Ukraine for ~~the Oleska block in western Ukraine. Chevron is expected to operate and hold~~ a 50 percent interest in and operatorship of the 1.6 ~~million-acre concession.~~million acre Oleska Shale block in western Ukraine. As of early ~~2013,~~2014, the ~~PSC and~~ Joint Operating Agreement terms were being negotiated.

Sales of Natural Gas and Natural Gas Liquids

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

During ~~2012~~2013, U.S. and international sales of natural gas were 5.5 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, Canada, Europe, Kazakhstan, Indonesia, Latin America, Myanmar, Nigeria, the Philippines and Thailand.

U.S. and international sales of natural gas liquids were ~~157~~142,000 ~~thousand~~ and 8888,000 ~~thousand~~ barrels per day, respectively, in ~~2012~~2013. Substantially all of the international sales of natural gas liquids from the company's producing interests are from operations in Africa, Kazakhstan, Indonesia and the United Kingdom.

Refer to “Selected Operating Data,” on page FS-10 in Management’s Discussion and Analysis of Financial Condition and Results of Operations, for further information on the company’s sales volumes of natural gas and natural gas liquids. Refer also to “Delivery Commitments” on page 7 for information related to the company’s delivery commitments for the sale of crude oil and natural gas.

Downstream

Refining Operations

At the end of ~~2012~~2013, the company had a refining network capable of processing ~~about 2.0~~nearly 2 million barrels of crude oil per day. Operable capacity at December 31, ~~2012~~2013, and daily refinery inputs for ~~2010~~2011 through ~~2012~~2013 for the company and affiliate refineries are summarized in the table below.

Average crude oil distillation capacity utilization during ~~2012~~2013 was 8884 percent, compared with 8988 percent in ~~2011~~2012. At the U.S. refineries, crude oil distillation capacity utilization averaged 81 percent in 2013, compared with 87 percent in 2012~~, compared with 89 percent in~~ ~~2011~~. Chevron processes both imported and domestic crude oil in its U.S. refining operations. Imported crude oil accounted for about 7776 percent and 8577 percent of Chevron’s U.S. refinery inputs in ~~2012~~2013 and ~~2011~~2012, respectively.

At the Pascagoula Refinery, construction progressed during 2013 on a facility to produce approximately 25,000 barrels per day of premium base ~~oil for use in manufacturing high-performance finished lubricants, such as motor oils for consumer and commercial applications.~~oil. Mechanical completion of the plant is expected ~~by year-end 2013. In July 2012,~~in first quarter 2014, and ramp up to full production is planned during second quarter 2014.

During 2013, work continued on projects to improve refinery flexibility and enhance the ~~company completed the sale of its idled 80,000-barrel-per-day Perth Amboy, New~~capability to process lower

~~Jersey, refinery, which~~cost feedstocks. In early 2013, start-up was ~~operating as~~achieved on a ~~terminal.~~

Atproject at the ~~refinery in El Segundo, a new processing unit designed to further improve the facility’s overall reliability, enhance high-value product yield and provide~~Pascagoula Refinery that provides additional flexibility to process a ~~broad~~broader range of ~~crude slates came online in July 2012. Similar projects were progressed in 2012~~crudes. A project to improve flexibility at the Salt Lake City ~~and Pascagoula refineries and are~~Refinery is scheduled to be completed ~~in late 2013.~~by mid-2014.

Outside the United States, GS Caltex, a 50 percent-owned ~~equity~~ affiliate, ~~reached mechanical completion~~started commercial operations of a 53,000-barrel-per-day gas oil fluid catalytic cracking unit at the Yeosu Refinery in South Korea in ~~early~~second quarter 2013. ~~The unit is designed to increase high-value product yield and lower feedstock costs.~~ In ~~2012, construction was completed on modifications to the 64 percent-owned Star Petroleum Refinery in Thailand to meet regional specifications for cleaner fuels. Also in 2012,~~2013, Caltex Australia Ltd., a 50 percent-owned ~~equity~~ affiliate, ~~announced~~progressed its plans to convert the Kurnell, Australia, refinery to an import terminal in 2014. In February 2014, Singapore Refining Company, Chevron's 50 percent-owned joint venture, reached a final investment decision to install a gasoline clean fuels facility and cogeneration plant. Addition of the facilities is expected to increase the refinery's capability to produce higher value gasoline and improve energy efficiency.

Petroleum Refineries: Locations, Capacities and Inputs
(Crude-unit capacities and crude oil inputs in thousands of barrels per day; includes equity share in affiliates)


		December 31, 2012		Refinery Inputs				December 31, 2013		Refinery Inputs
Locations	Locations	Number	Operable Capacity	2012	2011	2010	Locations	Number	Operable Capacity	2013	2012	2011

Pascagoula	Mississippi	1	330	335	327	325	Mississippi	1	330	304	335	327
El Segundo	California	1	269	265	244	250	California	1	269	235	265	244
Richmond	California	1	257	142	192	228	California	1	257	153	142	192
Kapolei	Hawaii	1	54	46	47	46	Hawaii	1	54	39	46	47
Salt Lake City	Utah	1	45	45	44	41	Utah	1	45	43	45	44
Total Consolidated Companies — United States	Total Consolidated Companies — United States	5	955	833	854	890	Total Consolidated Companies — United States	5	955	774	833	854
Pembroke¹	United Kingdom	—	—	—	122	211	United Kingdom	—	—	—	—	122
Map Ta Phut²	Thailand	1	158	95	—	—	Thailand	1	165	161	95	—
Cape Town³	South Africa	1	110	79	77	70	South Africa	1	110	78	79	77
Burnaby, B.C.	Canada	1	55	49	43	40	Canada	1	55	42	49	43
Total Consolidated Companies — International	Total Consolidated Companies — International	3	323	223	242	321	Total Consolidated Companies — International	3	330	281	223	242
Affiliates^2,4	Various Locations	6	675	646	691	683
Affiliates²							Various Locations	6	675	583	646	691
Total Including Affiliates — International	Total Including Affiliates — International	9	998	869	933	1,004	Total Including Affiliates — International	9	1,005	864	869	933
Total Including Affiliates — Worldwide	Total Including Affiliates — Worldwide	14	1,953	1,702	1,787	1,894	Total Including Affiliates — Worldwide	14	1,960	1,638	1,702	1,787


¹	Pembroke was sold in August 2011.


²	As of June 2012, Star Petroleum Refining Company crude input volumes are reported on a consolidated basis. Prior to June 2012, crude volumes reflect a 64 percent equity interest and are reported in ~~equity~~ affiliates.


³	Chevron holds ~~100 percent of~~a controlling interest in the ~~common stock~~shares issued by Chevron South Africa (Pty) Limited, which owns the Cape Town Refinery. A consortium of South African partners owns preferred shares ultimately convertible to a 25 percent equity interest in Chevron South Africa (Pty) Limited. ~~None of the preferred shares had been converted as of February 2013.~~


⁴	~~Includes 1,000 and 2,000 barrels per day of refinery inputs in~~ ~~2011~~ ~~and~~ ~~2010, respectively, for interests in refineries that were sold during those periods.~~

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, ~~2012~~2013.

Refined Products Sales Volumes
(Thousands of Barrels per Day)


	2012	2011	2010	2013	2012	2011
United States
Gasoline	624	649	700	613	624	649
Jet Fuel	212	209	223	215	212	209
Gas Oil and Kerosene	213	213	232	195	213	213
Residual Fuel Oil	68	87	99	69	68	87
Other Petroleum Products¹	94	99	95	90	94	99
Total United States	1,211	1,257	1,349	1,182	1,211	1,257

International²
Gasoline	412	447	521	398	412	447
Jet Fuel	243	269	271	245	243	269
Gas Oil and Kerosene	496	543	583	510	496	543
Residual Fuel Oil	210	233	197	179	210	233
Other Petroleum Products¹	193	200	192	197	193	200
Total International	1,554	1,692	1,764	1,529	1,554	1,692
Total Worldwide²	2,765	2,949	3,113	2,711	2,765	2,949

¹ Principally naphtha, lubricants, asphalt and coke.	¹ Principally naphtha, lubricants, asphalt and coke.			¹ Principally naphtha, lubricants, asphalt and coke.
² Includes share of equity affiliates’ sales:	522	556	562
² Includes share of affiliates’ sales:				471	522	556

In the United States, the company markets under the Chevron and Texaco brands. At year-end ~~2012~~2013, the company supplied directly or through retailers and marketers approximately ~~8,060~~8,050 Chevron- and Texaco-branded motor vehicle service stations, primarily in the southern and western states. Approximately ~~470~~400 of these outlets are company-owned or -leased stations.

Outside the United States, Chevron supplied directly or through retailers and marketers approximately ~~8,700~~8,600 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, Egypt and Pakistan, the company uses the Caltex brand. The company also operates through affiliates under various brand names. In South Korea, the company operates through its 50 percent-owned ~~equity~~ affiliate, GS Caltex, and in Australia through its 50 percent-owned ~~equity~~ affiliate, Caltex Australia Limited.

~~The company continued its ongoing effort to concentrate downstream resources and capital on strategic assets. In~~ ~~2012, Chevron completed the sale of the company's fuels marketing, finished lubricants and aviation fuels businesses in Spain as well as certain fuels marketing and aviation businesses in eight~~

countries in the Caribbean. The company's GS Caltex affiliate also completed the sale of certain power and other assets in South Korea. In addition, the company converted more than 240 company-operated service stations into retailer-owned sites in various countries outside the United States.

Chevron markets commercial aviation fuel at approximately ~~120~~115 airports worldwide. The company also markets an extensive line of lubricant and coolant products under the ~~brand names~~product lines Havoline, Delo, Ursa, Meropa, Rando, Clarity and

Taro in the United States and worldwide under the three ~~master~~ brands: Chevron, Texaco and Caltex.

Chemicals Operations

Chevron owns a 50 percent interest in its Chevron Phillips Chemical Company LLC (CPChem) ~~equity~~ affiliate. At the end of ~~2012~~2013, CPChem owned or had joint-venture interests in 3635 manufacturing facilities and two research and development centers around the world.

CPChem’s 35 percent-owned equity affiliate, Saudi Polymers Company, announced commercial production at its new olefins and derivatives facility in Al-Jubail, Saudi Arabia, in October 2012. In the United States, During 2013, CPChem ~~commenced~~progressed construction of a 1-hexene plant at the company’s Cedar Bayou complex in Baytown, Texas, with a design capacity of 250,000 metric tons per year. Start-up is expected in second quarter 2014. In ~~2012,~~October 2013, CPChem ~~also commenced front-end engineering and design for several projects~~announced a final investment decision on ~~the~~its U.S. Gulf Coast Petrochemicals Project, which ~~are~~is expected to capitalize on advantaged feedstock sourced from ~~emerging~~ shale gas development in North America. ~~These include~~The $6 billion 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 complex in Baytown, Texas, and two polyethylene facilities to be located in Old Ocean, Texas, each with an annual design capacity of 500,000 metric tons.

Chevron’s Oronite brand lubricant and fuel additives business is a leading developer, manufacturer and marketer of performance additives for lubricating oils and fuels. The company owns and operates facilities in Brazil, France, Japan, the Netherlands, Singapore and the United States and has equity interests in facilities in India and Mexico. Oronite lubricant additives are blended ~~into~~with refined base oil to produce finished ~~lubricant packages~~lubricants, used primarily in engine applications such as passenger ~~car,~~cars, heavy-duty diesel ~~marine, locomotive~~trucks, buses, ships, locomotives and ~~motorcycle engines, and additives~~motorcycles. Additives for fuels ~~that~~ are blended to improve engine performance and extend engine life. In ~~2012, the company began~~2013, construction continued on a project to expand the capacity of the existing additives plant on Jurong Island in Singapore. ~~The project~~Commercial operations are expected to begin by third quarter 2014. Upon start-up, the plant is expected to double ~~the plant's~~its capacity since it was commissioned in ~~1999~~1999. In Gonfreville, France, a project to expand dispersant production by more than 25 percent was completed in third quarter 2013, and a project to ~~begin commercial operations~~effectively double detergent capacity began construction with expected completion in late 2014.

Transportation

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

Pipeline Mileage at December 31, ~~2012~~2013



	Net Mileage^1,2
United ~~States:~~States
Crude Oil	~~1,969~~1,883
Natural Gas	~~2,396~~2,638
Petroleum Products	~~6,009~~4,395
Total United States	~~10,374~~8,916
~~International:~~International
Crude Oil	~~696~~667
Natural Gas	199
Petroleum Products	~~334~~290
Total International	~~1,229~~1,156
Worldwide	~~11,603~~10,072


¹	Includes company’s share of pipeline mileage owned by ~~equity~~ affiliates.


²	Excludes gathering pipelines relating to the crude oil and natural gas production function.

The company ~~continues to lead~~is leading the construction of a 136-mile, 24-inch crude oil pipeline from the planned Jack/St. Malo deepwater production facility to a platform in Green Canyon Block 19 on the U.S. Gulf of Mexico shelf, where there is an interconnect to pipelines delivering crude oil into Texas and Louisiana. ~~The project~~In early 2014, the company completed laying the pipe, which included the installation of two subsea connections for future tie-ins. All remaining work on the pipeline is expected to be completed by start-up of the production facility in late 2014.

In ~~December 2012,~~June 2013, the company ~~executed agreements to sell~~completed the sale of the 100 percent-owned and operated Northwest Products System. This system consisted of a 760-mile refined products pipeline running from Salt Lake City, Utah, to Spokane, Washington, a dedicated jet fuel pipeline serving the Salt Lake City International Airport, and three refined products terminals located in Idaho and Washington. The sale is pending regulatory approval and is expected to be completed in first-half 2013.~~In addition, the company is in the process of relinquishing its interest in the Trans Alaska Pipeline System.~~

Refer to pages ~~14,~~ 15, 16 and 17 in the Upstream section for information on the Chad/Cameroon pipeline, the West African Gas Pipeline, the Baku-Tbilisi-Ceyhan Pipeline, the Western Route Export Pipeline and the Caspian Pipeline Consortium.

~~Tankers:~~Shipping: All tankers in Chevron’s controlled seagoing fleet were utilized during ~~2012~~2013. During ~~2012~~2013, the company had 5158 deep-sea vessels chartered on a voyage basis, or for a period of less than one year. The following table summarizes the capacity of the company’s controlled fleet.

Controlled Tankers at December 31, ~~2012~~2013¹


	U.S. Flag		Foreign Flag		U.S. Flag		Foreign Flag
		Cargo Capacity		Cargo Capacity		Cargo Capacity		Cargo Capacity
	Number	(Millions of Barrels)	Number	(Millions of Barrels)	Number	(Millions of Barrels)	Number	(Millions of Barrels)

Owned	—	—	1	1.1	—	—	1	1.0
Bareboat-Chartered	4	1.4	18	27.2	4	1.4	17	25.0
Time-Chartered²	3	1.0	11	8.9	3	1.0	9	8.5
Total	7	2.4	30	37.2	7	2.4	27	34.5


¹	Consolidated companies only. Excludes tankers chartered on a voyage basis, those with dead-weight tonnage less than 25,000 and those used exclusively for storage.


²	Tankers chartered for more than one year.

The company’s U.S.-flagged fleet is engaged primarily in transporting refined products 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. The company’s foreign-flagged vessels also transport refined products and feedstocks to and from various locations worldwide.

In ~~2012,~~2013, the company ~~ordered eight new~~took delivery of two vessels that included one bareboat charter VLCC and a ~~combination of~~dynamically positioned shuttle tanker. Progress continued on contracts in place for bareboat charters and new builds, ~~contracts,~~ to modernize the fleet and increase LNG coverage. ~~In addition to the vessels ordered in 2012, the company has prior contracts in place to build LNG carriers and a dynamic-positioning shuttle tanker to support future upstream projects.~~ The company also owns a one-sixth interest in each of seven LNG carriers transporting cargoes for the North West Shelf Venture in Australia.

Other Businesses

Mining:Chevron’s U.S.-based mining company concluded the divestment of its remaining coal mining operations. In 2012, the company completed the sale of its Kemmerer, Wyoming, surface coal mine and the sale of its 50 percent interest in Youngs Creek Mining Company, LLC, which was formed to develop a coal mine in northern Wyoming. Activities related to final reclamation continued in 2012 at the company-operated surface coal mine in McKinley, New Mexico.

Chevron ~~also~~ owns and operates the Questa molybdenum mine in New Mexico. At year-end ~~2012~~,2013, Chevron had 160 million pounds of proven molybdenum reserves at Questa. Production and underground development at Questa continued at reduced levels in ~~2012~~2013 in response to weak prices for molybdenum.

Power ~~Generation:~~and Energy Services: ~~Chevron’s~~In 2014, Chevron Energy Solutions is being combined with Chevron Global Power ~~Company~~Company. As the company's power and energy services provider, this business delivers comprehensive commercial, engineering and operational support services to improve power reliability and energy efficiency of Chevron operations worldwide. The responsibilities also include developing and building sustainable energy projects for the production of renewable power and to reduce energy costs that benefit third parties and the environment.

This business also manages ~~interests~~Chevron's interest in 11a variety of gas-fired and renewable power ~~assets with a total operating capacity of more than 2,200 megawatts, primarily through joint ventures in the United States and Asia. Ten of these are efficient combined-cycle and~~generation assets. The gas-fired cogeneration facilities ~~that~~produce electricity and steam and utilize recovered waste heat to ~~produce electricity~~support enhanced oil recovery operations. The renewable facilities consist of wind, geothermal, photovoltaic and support industrial thermal hosts. The 11th facility is a wind farm, located in Casper, Wyoming, that is designed to optimize the use of a decommissioned refinery site for delivery of clean, renewable energy to the local utility.solar-to-steam production assets.

Chevron also has major geothermal operations in Indonesia and the Philippines and is evaluating several advanced solar technologies for use in oil field operations as part of its renewable energy strategy. For additional information on the company’s geothermal operations and renewable energy projects, refer to page 19 in the Upstream section and “Research and Technology” below.

~~Chevron Energy Solutions (CES):~~CES is a wholly owned subsidiary that develops and builds sustainable energy projects that increase energy efficiency and production of renewable power, reduce energy costs, and ensure reliable, high-quality energy for government, education and business facilities. CES has developed hundreds of projects that have helped customers reduce their energy costs and environmental impact. In 2012, CES completed several public sector programs, including a first-of-its-kind microgrid at the Santa Rita jail in Alameda County, and renewable and efficiency programs for Huntington Beach City School District, South San Francisco Unified School District and Union City, all in California, plus Rootstown Local School District in Ohio. CES also completed an energy efficiency program at the Detroit Arsenal and a combined renewable power production and heating project at the Marine Corps Logistics Base in Albany, Georgia. CES is also guiding the work of the new Chevron Center for Sustainable Energy Efficiency in Qatar. In December 2012, CES and its partners inaugurated the first large scale solar testing in Qatar. The evaluation will help determine the most appropriate solar technologies for the Middle East.

Research and Technology: The company’s energy technology organization supports Chevron’s upstream and downstream businesses by conducting research, developing and qualifying technology, providing ~~technology,~~technical services, and providing competency development in earth sciences; reservoir and production engineering; drilling and completions; facilities engineering; manufacturing; process technology; catalysis; technical computing; and health, environment and safety disciplines. The

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

Chevron's ~~venture capital investment~~technology ventures group manages investments in venture capital and projects in emerging energy technologies and their integration into Chevron’s core businesses. As of the end of ~~2012~~2013, the ~~venture capital~~ventures group continued to explore technologies such as next-generation biofuels, advanced solar and enhanced pipeline inspection ~~methods. In~~ ~~2012~~,methods, and made investments in the company continued evaluation of a solar-to-steam generation project in use to support enhanced-oil-recovery operations in Coalinga, California. This project was commissioned to test the viability of using solar power to produce steam to improve oil recovery.

In 2012, the company launched a new tank technology for storing water at hydraulic fracturing operations. These patent-pending modular metal tanks can be quickly assembled and taken apart for reuse at other wells. This enables drilling and fracturing without the need for water storage pits and is intended to result in enhanced safety, less land disturbance, smaller drill site pads and significantly lower costs. The first fully operational tank was brought into service in Ohio.primary carbon market.

Chevron’s research and development expenses were $750 million, $648 million ~~$627 million~~ and ~~$526~~$627 million for the years ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011, respectively.

Some of the investments the company makes in the areas described above are in new or unproven technologies and business processes, and ultimate technical or commercial successes are not certain.

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

To complement the company’s capabilities, Chevron maintains active membership in international oil spill response cooperatives, including the Marine Spill Response Corporation, which operates in U.S. territorial waters, and Oil Spill Response, Ltd. (OSRL), which operates globally. The company is a founding member of the Marine Well Containment Company, whose primary mission is to expediently deploy containment equipment and systems to capture and contain crude oil in the unlikely event of a future loss of control of a deepwater well in the Gulf of Mexico.

In addition, the company is a member of the Subsea Well Response Project (SWRP). SWRP’s objective is to further develop the industry’s capability to contain and shut in subsea well control incidents in different regions of the world.

Refer to Management's Discussion and Analysis of Financial Condition and Results of Operations on ~~pages~~page FS-15 ~~and FS-16~~ for additional information on environmental matters and their impact on Chevron, and on the company's ~~2012~~2013 environmental expenditures. Refer to page FS-15 and Note 2423 on page ~~FS-58~~FS-55 for a discussion of environmental remediation provisions and year-end reserves. Refer also to Item 1A. Risk Factors on pages 2827 through 3029 for a discussion of greenhouse gas regulation and climate change.

~~Web Site~~Website Access to SEC Reports

The company’s ~~Internet Web site~~website is www.chevron.com. Information contained on the company’s ~~Internet Web site~~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 ~~Web site~~website soon after such reports are filed with or furnished to the Securities and Exchange Commission (SEC). The reports are also available on the SEC’s ~~Web site~~website at www.sec.gov.


Item 1A.	Risk Factors

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

Chevron is exposed to the effects of changing commodity prices: Chevron is primarily in a commodities business 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, production quotas imposed by the Organization of Petroleum Exporting Countries (OPEC), weather-related damage and disruptions, competing fuel prices, and geopolitical risk. Chevron accepts

the risk of changing commodity prices as part of its business planning process. As such, an investment in the company carries significant exposure to fluctuations in global crude oil prices.

During extended periods of historically low prices for crude oil, the company’s upstream earnings and capital and exploratory expenditure programs will be negatively affected. Upstream assets may also become impaired. The impact on downstream earnings is dependent upon the supply and demand for refined products and the associated margins on refined product sales.

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

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

The company’s operations have inherent risks and hazards that require significant and continuous oversight: Chevron’s results depend on its ability to identify and mitigate the risks and hazards inherent to operating in the crude oil and natural gas industry. The company seeks to minimize these operational risks by carefully designing and building its facilities and conducting its operations in a safe and reliable manner. However, failure to manage these risks effectively could result in unexpected incidents, including releases, explosions or mechanical failures resulting in personal injury, loss of life, environmental damage, loss of revenues, legal liability and/or disruption to operations. Chevron has implemented and maintains a system of corporate policies, behaviors and compliance mechanisms to manage safety, health, environmental, reliability and efficiency risks; to verify compliance with applicable laws and policies; and to respond to and learn from unexpected incidents. ~~Nonetheless, in~~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 1314 to the Consolidated Financial Statements, beginning on ~~FS-40.~~page FS-39.

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 imposed or proposed restrictions on the company’s operations, export and exchange controls, burdensome taxes, and public disclosure requirements that might harm the company’s competitiveness or relations with other governments or third parties. In other countries, political conditions have existed that may threaten the safety of employees and the company’s continued presence in those countries, and internal unrest,

acts of violence or strained relations between a government and the company or other governments may adversely affect the company’s operations. Those developments have, at times, significantly affected the company’s related operations and results and are carefully considered by management when evaluating the level of current and future activity in such countries. At December 31, ~~2012~~2013, 21 percent of the company’s net proved reserves were located in Kazakhstan. The company also has significant interests in OPEC-member countries, including Angola, Nigeria and Venezuela, and in the Partitioned Zone between Saudi Arabia

and Kuwait. Twenty-one percent of the company’s net proved reserves, including affiliates, were located in OPEC countries at December 31, ~~2012~~2013.

Regulation of greenhouse gas emissions could increase Chevron’s operational costs and reduce demand for Chevron’s products: Continued political attention to issues concerning climate change, the role of human activity in it, and potential mitigation through regulation could have a material impact on the company’s operations and financial results.

International agreements and national or regional legislation and regulatory measures to limit greenhouse emissions are currently in various stages of discussion or implementation. These and other greenhouse gas emissions-related laws, policies and regulations may result in substantial capital, compliance, operating and maintenance costs. The level of expenditure required to comply with these laws and regulations is uncertain and is expected to vary depending on the laws enacted in each jurisdiction, the company’s activities in it and market conditions. Greenhouse gas emissions that could be regulated include those arising from the company’s exploration and production of crude oil and natural gas; the upgrading of production from oil sands into synthetic oil; power generation; the conversion of crude oil and natural gas into refined products; the processing, liquefaction and regasification of natural gas; the transportation of crude oil, natural gas and related products and consumers’ or customers’ use of the company’s products. Some of these activities, such as consumers’ and customers’ use of the company’s products, as well as actions taken by the company’s competitors in response to such laws and regulations, are beyond the company’s control.

The effect of regulation on the company’s financial performance will depend on a number of factors including, among others, the sectors covered, the greenhouse gas emissions reductions required by law, the extent to which Chevron would be entitled to receive emission allowance allocations or would need to purchase compliance instruments on the open market or through auctions, the price and availability of emission allowances and credits, and the impact of legislation or other regulation on the company’s ability to recover the costs incurred through the pricing of the company’s products. Material price increases or incentives to conserve or use alternative energy sources could reduce demand for

products the company currently sells and adversely affect the company’s sales volumes, revenues and margins.

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


Item1B.	Unresolved Staff Comments

None.


Item 2.	Properties

The location and character of the company’s crude oil, natural gas and mining properties and its refining, marketing, transportation and chemicals facilities are described on page 3 under Item 1. Business. Information required by Subpart 1200 of Regulation S-K (“Disclosure by Registrants Engaged in Oil and Gas Producing Activities”) is also contained in Item 1 and in Tables I through VII on pages ~~FS-62~~FS-59 through ~~FS-75.~~FS-71. Note ~~12,~~13, “Properties, Plant and Equipment,” to the company’s financial statements is on page ~~FS-40.~~FS-39.

Item 3. Legal Proceedings

Ecuador: Information related to Ecuador matters is included in Note 1314 to the Consolidated Financial Statements under the heading Ecuador, beginning on page ~~FS-40.~~FS-39.

Certain Governmental Proceedings:

InAs initially disclosed in the first quarter 2011 Form 10-Q, the ~~California Air Resources Board (CARB) made~~Environmental Protection Agency (EPA) indicated that it would assess the company's Salt Lake City Refinery a civil penalty ~~demands with respect to four notices of violation against Chevron~~ for alleged violations of ~~CARB's fuel blend regulations~~federal requirements and Utah's air quality laws. These alleged violations were

the subject of an August 20, 2008, EPA Notice of Violation (NOV) for which no penalty was assessed at the time. On October 21, 2013, the U.S. District Court in Utah entered a Consent Decree resolving the NOV. Pursuant to the Consent Decree, Chevron paid a penalty of $384,000 and agreed to implement certain ~~California terminals~~other measures.

On August 6, 2012, a piping failure and ~~refineries. In November 2011,~~fire occurred at the ~~statute of limitations expired with respect to two~~Chevron U.S.A. Inc. refinery in Richmond, California. Various federal, state, and local agencies initiated investigations as a result of the ~~notices~~incident. Based on its civil investigation, the United States EPA issued a Finding of ~~violation. On January 28,~~Violations (FOV) to Chevron on December 17, 2013, ~~settlements were executed,~~ which ~~resolved~~includes 62 findings of alleged noncompliance at the ~~remaining two notices~~refinery. The majority of ~~violation. One settlement, with respect~~these findings relate to the ~~Richmond Refinery, resulted~~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 ~~in the amount~~ of ~~$192,500, and the other settlement, relating to~~$100,000 or more.

~~the San Jose and Sacramento terminals, resulted in the payment of a civil penalty in the amount of $205,000.~~

In July 2009, the Hawaii Department of Health (DOH) alleged that Chevron is obligated to pay stipulated civil penalties ~~exceeding $100,000~~ in conjunction with commitments Chevron undertook to install and operate certain air emission control equipment at its Hawaii Refinery pursuant to a Clean Air Act settlement with the United States ~~Environmental Protection Agency (EPA)~~EPA and the DOH. ~~Chevron~~The company has disputed many of the allegations.

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

The South Coast Air Quality Management District (SCAQMD) issued an NOV to Chevron's Huntington Beach, California, terminal seeking a civil penalty for alleged violations involving the repair of two holes in the roof of a tank at the terminal. On January 24, 2013, Chevron U.S.A. Inc. executed a settlement agreement with the SCAQMD and made payment of $100,000 ~~to resolve the NOV issued to the Huntington Beach terminal.~~or more.

InAs initially disclosed in the 2012 Form 10-K, in September and November 2012, Chevron's Richmond Refinery received from the Bay Area Air Quality Management District (BAAQMD) proposals to resolve 47 alleged NOVs related to air quality regulations. ~~A single~~In December 2012, a settlement agreement ~~has been~~was finalized covering 28 of those NOVs for payment of $145,600 in civil penalties. ~~Resolution~~The company reached a settlement agreement with BAAQMD and paid $190,000 in civil penalties to resolve 17 of the remaining NOVs, ~~is pending~~ and the BAAQMD has informed the company that it will not seek penalties for the last two remaining NOVs.

On June 10, 2013, the company received correspondence from the California Air Resources Board regarding an alleged violation of California's Regulation for the Mandatory Reporting of Greenhouse Gas Emissions based on alleged delay in the reporting of emissions data for Chevron's San Joaquin Valley Business Unit. Chevron has reached an agreement-in-principle with the California Air Resources Board under which the company would pay a $328,500 civil penalty to resolve the alleged violations.

The California Air Resources Board (CARB) has alleged that greenhouse gas (GHG) emissions reported by Chevron’s El Segundo Refinery for the 2011 calendar year contained an error in violation of California’s GHG reporting regulation, and that the reporting error resulted in an over-allocation of GHG allowances. The company has reached an agreement-in-

principle with the CARB under which Chevron would pay a $364,500 civil penalty to resolve the alleged violations.

As initially disclosed in the third quarter 2013 Form 10-Q, in July 2013, Chevron Products Company, a division of Chevron U.S.A. Inc., received a NOV from the CARB for the Richmond and Montebello (California) terminals alleging the selling or offering for sale of gasoline containing more than the maximum allowable ethanol content. Resolution of the alleged violation may result in the payment of a civil penalty ~~exceeding $100,000.~~of $100,000 or more.

~~In April~~On October 18, 2013, the CARB issued a Notice of Violation alleging that Chevron’s San Diego terminal sold gasoline with less than the required detergent content for 34 months from 2010 to 2012. Resolution of the alleged violation may result in the payment of a civil penalty of $100,000 or more.

On December 18, 2013, EPA declared certain renewable fuel credits (also referred to as Renewable Identification Numbers or RINs) generated by E-Biofuel to be invalid. The company previously submitted RINs generated by E-Biofuel for 2012 compliance with federal renewable fuels requirements. Under current EPA policy, the company's earlier submittal of those now-invalid RINs generated by E-Biofuel may result in the payment of a civil penalty of $100,000 or more.

As previously disclosed in the third quarter 2013 Form 10-Q, Chevron U.S.A. Inc. has participated in settlement discussions and received a proposed settlement agreement from the South Coast Air Quality Management District ~~(SCAQMD) issued a letter seeking~~ to ~~settle five separate and unrelated NOVs issued to Chevron's El Segundo Refinery in 2011 for~~resolve alleged violations of ~~various~~the El Segundo Refinery's Clean Air Act Title V Operating Permit. Resolution of the alleged violations may result in the payment of a civil penalty of $100,000 or more.

The State of New Mexico provided to Chevron a NOV on December 11, 2013, alleging that the flaring of fuel gas that occurred during periodic compressor purging events at the Chevron Buckeye CO2 plant resulted in hourly air emissions during these events in excess of the plant permit limits and alleging that the company had failed to timely report these excess emissions. The resolution of this NOV may result in the payment of a civil penalty of $100,000 or more.

As initially disclosed in the second quarter 2013 Form 10-Q, Chevron Pipe Line Company (CPL) received a NOV from the Utah Division of Water Quality (DWQ) in April 2013 alleging state ~~and local rules relating to air emissions. On January 24, 2013, Chevron U.S.A. Inc. executed~~law violations resulting from a pipeline spill near Willard Bay State Park, Utah. CPL has concluded a settlement agreement with ~~SCAQMD~~the DWQ and ~~made payment~~the Utah Department of ~~$300,000~~Natural Resources, State Parks and Recreation Division to resolve ~~the five NOVs issued to the El Segundo Refinery.~~these alleged violations, which includes a monetary penalty of $350,000 as well as $5 million for environmentally beneficial mitigation projects and for lost use damages.


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.~~FS-19.

Chevron Corporation Issuer Purchases of Equity Securities

Maximum
Total Number of Number of Shares
Total Number Average Shares Purchased as that May Yet be
of Shares Price Paid Part of Publicly Purchased Under
Period

Purchased⁽¹⁾⁽²⁾

per Share

Announced Program

the Program⁽²⁾
Oct. 1 – Oct. 31, 2012 3,644,071
$114.16 3,644,045
—
Nov. 1 – Nov. 30, 2012 4,290,367
105.23
4,290,000
—
Dec. 1 – Dec. 31, 2012 3,555,702
107.59
3,555,702
—
Total Oct. 1 – Dec. 31, 2012 11,490,140
$108.79 11,489,747
—



				Maximum
			Total Number of	Number of Shares
	Total Number	Average	Shares Purchased as	that May Yet be
	of Shares	Price Paid	Part of Publicly	Purchased Under
Period	Purchased^1,2	per Share	Announced Program	the Program²
Oct. 1 - Oct. 31, 2013	3,936,342	$119.22	3,935,677	—
Nov. 1 - Nov. 30, 2013	4,700,264	120.10	4,699,917	—
Dec. 1 - Dec. 31, 2013	1,739,623	124.34	1,739,623	—
Total Oct. 1 - Dec. 31, 2013	10,376,229	$120.48	10,375,217	—


~~(1)~~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 and Unocal stock option plans.

~~(2)~~2

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 ~~(some pursuant to a Rule 10b5-1 plan)~~or in negotiated transactions at prevailing prices, as permitted by securities laws and other legal requirements and subject to market conditions and other factors. As of December 31, ~~2012~~2013, ~~97,698,628~~139,340,805 shares had been acquired under this program (some pursuant to a Rule 10b5-1 plan and some pursuant to accelerated share repurchase plans) for $1015 billion. at an average price of approximately $108 per share.

Item 6. Selected Financial Data

The selected financial data for years ~~2008~~2009 through ~~2012~~2013 are presented on page ~~FS-61.~~FS-58.

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 ~~Instruments,~~Instrument Market Risk,” beginning on page ~~FS-14~~FS-13 and in Note 910 to the

Consolidated Financial Statements, “Financial and Derivative Instruments,” beginning on page ~~FS-35.~~FS-34.

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, the Chief Executive Officer and the Chief Financial Officer concluded that the company’s disclosure controls and procedures were effective as of December 31, ~~2012~~2013.

(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). 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 (1992)issued by the Committee of Sponsoring Organizations of the Treadway ~~Commission.~~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, ~~2012~~2013.

The effectiveness of the company’s internal control over financial reporting as of December 31, ~~2012~~2013, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report included on page ~~FS-22.~~FS-21.

During the quarter ended December 31, ~~2012~~2013, 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.

On May 14, 2013, COSO published an updated Internal Control — Integrated Framework (2013) and related illustrative documents. As of December 31, 2013, the company is utilizing the original framework published in 1992. The transition period for adoption of the updated framework ends December 15, 2014.

Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Executive Officers of the Registrant at February ~~22, 2013~~21, 2014

The Executive Officers of the Corporation consist of the Chairman of the Board, the Vice Chairman of the Board and such other officers of the Corporation who are members of the Executive Committee.



Name ~~and Age~~	Age	Current and Prior Positions (up to five years)	Current Areas of Responsibility
J.S. Watson	5657	Chairman of the Board and Chief Executive Officer (since 2010)	Chief Executive Officer
		Vice Chairman of the Board (2009)
		Executive Vice President (2008 to 2009)
		~~Vice President and President of Chevron International Exploration~~ ~~and Production Company (2005 through 2007)~~
G.L. Kirkland	6263	Vice Chairman of the Board and Executive Vice President (since 2010) Executive Vice President (2005 through 2009)	~~Worldwide Exploration~~Vice Chairman of the Board and ~~Production Activities and Global Gas Activities, including Natural Gas Trading~~
~~J.R. Blackwell~~	54	Executive Vice President ~~(since 2011)~~ ~~President of Chevron Asia Pacific Exploration and Production~~ ~~Company (2008 through 2011)~~ ~~Managing Director of Chevron Southern Africa Strategic Business~~ ~~Unit (2003 to 2007)~~	~~Technology; Mining; Project~~ ~~Resources Company;~~ ~~Procurement~~
M.K. Wirth	5253	Executive Vice President (since 2006) ~~President of Global Supply and Trading (2004 to 2006)~~	Worldwide Refining, Marketing ~~Lubricants,~~ and ~~Supply and Trading Activities, excluding Natural Gas Trading;~~Lubricants; Chemicals
R.I. Zygocki	5556	Executive Vice President (since 2011) Vice President, Policy, Government and Public Affairs (2007 through 2011) ~~Vice President, Health, Environment and Safety (2003 through 2007)~~	Strategy and Planning; Health, Environment and Safety; Policy, Government and Public ~~Affairs~~Affairs; Mining
J.C. Geagea	54	Senior Vice President, Technology, Projects and Services (since 2014) Corporate Vice President and President, Gas and Midstream (2012 through 2013) Managing Director, Asia South Business Unit (2008 through 2011)	Technology; Project Resources Company; Procurement
J.W. Johnson	54	Senior Vice President, Upstream (since 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	49	Corporate Vice President and President, Gas and Midstream (since 2014) 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 Natural Gas Commercialization; Supply and Trading Activities, including Natural Gas Trading; Shipping; Pipeline; and Power and Energy Services
P.E. Yarrington	5657	Vice President and Chief Financial Officer (since 2009) ~~Vice President and Treasurer (2007 through 2008)~~ ~~Vice President, Policy, Government and Public Affairs~~ ~~(2002 to 2007)~~	Finance
R.H. Pate	5051	Vice President and General Counsel (since 2009) Partner and Head of Global Competition Practice of Hunton & Williams LLP, a major U.S. law firm (2005 to 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 ~~2013~~2014 Annual Meeting and ~~2013~~2014 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 ~~2013~~2014 Annual Meeting of Stockholders (the “~~2013~~2014 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 ~~2013~~2014 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 ~~“Board Operations~~“Corporate Governance — Business Conduct and Ethics Code” in the ~~2013~~2014 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 ~~“Board Operations~~“Corporate Governance — Board ~~Committee Membership and Functions”~~Committees” in the ~~2013~~2014 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

There were no changes to the process by which stockholders may recommend nominees to the Board of Directors during the last fiscal year.

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 ~~2013~~2014 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 ~~“Board Operations~~“Corporate Governance — Board ~~Committee Membership and Functions”~~Committees” in the ~~2013~~2014 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 ~~“Board Operations~~“Corporate Governance — Management Compensation Committee Report” in the ~~2013~~2014 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 ~~2013~~2014 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 ~~2013~~2014 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 ~~2013~~2014 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 ~~“Board Operations~~“Corporate Governance — Transactions with Related ~~Persons”~~Parties” in the ~~2013~~2014 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 ~~“Election of Directors~~“Corporate Governance — ~~Independence of Directors”~~Director Independence” in the ~~2013~~2014 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 ~~“Proposal~~“Board Proposal to Ratify the

Appointment of the Independent Registered Public Accounting Firm” in the ~~2013~~2014 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~~FS-21
Consolidated Statement of Income for the three years ended December 31, ~~2012~~2013	~~FS-23~~FS-22
Consolidated Statement of Comprehensive Income for the three years ended December 31, ~~2012~~2013	~~FS-24~~FS-23
Consolidated Balance Sheet at December 31, ~~2012~~2013 and ~~2011~~2012	~~FS-25~~FS-24
Consolidated Statement of Cash Flows for the three years ended December 31, ~~2012~~2013	~~FS-26~~FS-25
Consolidated Statement of Equity for the three years ended December 31, ~~2012~~2013	~~FS-27~~FS-26
Notes to the Consolidated Financial Statements	~~FS-28~~FS-27 to ~~FS-60~~FS-57

(2) Financial Statement Schedules:

Included on page 36 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~~And Qualifying Accounts

(Millions ofOf Dollars)


	Year Ended December 31									Year Ended December 31
	2012			2011			2010			2013			2012			2011
Employee Termination Benefits
Balance at January 1	$	63		$	145		$	13		$	30		$	63		$	145
Additions charged to expense	3			—			235
(Reductions) additions charged to expense										(6		)	3			—
Payments	(36		)	(82		)	(103		)	(10		)	(36		)	(82		)
Balance at December 31	$	30		$	63		$	145		$	14		$	30		$	63

Allowance for Doubtful Accounts
Balance at January 1	$	167		$	239		$	293		$	155		$	167		$	239
Additions (reductions) to expense	(4		)	4			(13		)	1			(4		)	4
Bad debt write-offs	(8		)	(76		)	(41		)	(61		)	(8		)	(76		)
Balance at December 31	$	155		$	167		$	239		$	95		$	155		$	167

Deferred Income Tax Valuation Allowance*
Balance at January 1	$	11,096		$	9,185		$	7,921		$	15,443		$	11,096		$	9,185
Additions to deferred income tax expense	5,471			2,216			1,454			2,665			5,471			2,216
Reduction of deferred income tax expense	(1,124		)	(305		)	(190		)	(937		)	(1,124		)	(305		)
Balance at December 31	$	15,443		$	11,096		$	9,185		$	17,171		$	15,443		$	11,096


^* ^*See also Note 15 to the Consolidated Financial Statements, beginning on page FS-43.	~~See also Note 14 to the Consolidated Financial Statements, beginning on page FS-43.~~

~~SIGNATURES~~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 ~~22nd~~21st day of February, ~~2013.~~2014.



	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 ~~22nd~~21st day of February, ~~2013.~~2014.



Principal Executive Officers
(and Directors)	Directors

/s/JOHN S. WATSON John S. Watson, Chairman of the Board and Chief Executive Officer	LINNET F. DEILY* Linnet F. Deily

/s/GEORGE L. KIRKLAND George L. Kirkland, Vice Chairman of the Board	ROBERT E. DENHAM* Robert E. Denham

	ALICE P. GAST* Alice P. Gast


~~Principal Financial Officer~~	ENRIQUE HERNANDEZ, JR.* Enrique Hernandez, Jr.

Principal Financial Officer	JON M. HUNTSMAN, JR.* Jon M. Huntsman, Jr.

/s/PATRICIA E. YARRINGTON Patricia E. Yarrington, Vice President and Chief Financial Officer	CHARLES W. MOORMAN* Charles W. Moorman KEVIN W. SHARER* Kevin W. Sharer

Principal Accounting Officer

/s/MATTHEW J. FOEHR Matthew J. Foehr, Vice President and Comptroller	JOHN G. STUMPF* John G. Stumpf RONALD D. SUGAR* Ronald D. Sugar

*By: /s/LYDIA I. BEEBE Lydia I. Beebe, Attorney-in-Fact	CARL WARE* Carl Ware

~~THIS PAGE INTENTIONALLY LEFT BLANK~~



Financial Table of Contents

FS-2		~~FS-28~~FS-27

Management’s Discussion and Analysis of Financial Condition and Results of Operations		Notes to the Consolidated Financial Statements
Key Financial Results FS-2		Note 1		Summary of Significant Accounting Policies~~FS-28~~ FS-27
Earnings by Major Operating Area FS-2		Note 2		~~Noncontrolling Interests~~ ~~FS-30~~Changes in Accumulated Other Comprehensive Losses FS-29
Business Environment and Outlook FS-2		Note 3		~~Information Relating to the Consolidated~~ ~~Statement of Cash Flows~~Noncontrolling Interests ~~FS-31~~FS-30
Operating Developments FS-5		Note 4		~~Summarized Financial Data – Chevron U.S.A. Inc.~~Information Relating to the Consolidated Statement of Cash Flows ~~FS-32~~FS-30
Results of Operations FS-6		Note 5		Summarized Financial Data – Chevron ~~Transport Corporation Ltd.~~U.S.A. Inc. ~~FS-32~~FS-31
Consolidated Statement of Income FS-9		Note 6		Summarized Financial Data – ~~Tengizchevroil LLP~~ Chevron Transport Corporation Ltd. ~~FS-33~~FS-31
Selected Operating Data FS-10		Note 7		~~Lease Commitments~~Summarized Financial Data – Tengizchevroil LLP ~~FS-33~~FS-32
Liquidity and Capital Resources FS-11		Note 8		~~Fair Value Measurements~~Lease Commitments ~~FS-33~~FS-32
Financial Ratios FS-13		Note 9		~~Financial and Derivative Instruments~~Fair Value Measurements ~~FS-35~~FS-32
Guarantees, Off-Balance-Sheet Arrangements and Contractual Obligations, and Other Contingencies FS-13		Note 10		Financial and Derivative Instruments FS-34
Financial and Derivative Instrument Market Risk FS-13		Note 11		Operating Segments and Geographic Data ~~FS-36~~
~~Financial and Derivative Instruments~~ ~~FS-14~~		~~Note 11~~		~~Investments and Advances~~ ~~FS-38~~FS-35
Transactions With Related Parties ~~FS-15~~FS-14		Note 1212		~~Properties, Plant~~Investments and ~~Equipment~~Advances ~~FS-40~~FS-37
Litigation and Other Contingencies ~~FS-15~~FS-14		Note 1313		~~Litigation~~Properties, Plant and Equipment ~~FS-40~~FS-39
Environmental Matters FS-15		Note 1414		Litigation FS-39
Critical Accounting Estimates and Assumptions FS-15		Note 15		Taxes FS-43
~~Critical~~New Accounting ~~Estimates and Assumptions~~Standards ~~FS-16~~FS-18		Note 1516		Short-Term Debt ~~FS-46~~
~~New Accounting Standards~~ ~~FS-19~~		~~Note 16~~		~~Long-Term Debt~~ ~~FS-46~~FS-45
Quarterly Results and Stock Market Data ~~FS-20~~FS-19		Note 1717		~~New Accounting Standards~~Long-Term Debt ~~FS-47~~FS-46
		Note 1818		New Accounting Standards FS-46
		Note 19		Accounting for Suspended Exploratory Wells ~~FS-47~~FS-46
FS-20		Note 1920		Stock Options and Other Share-Based Compensation ~~FS-48~~FS-47
FS-20	~~FS-21~~		Note 2021		Employee Benefit Plans ~~FS-49~~
	~~Note 21~~		~~Equity~~ ~~FS-55~~FS-48
		Note 2222		~~Other Contingencies and Commitments~~Equity ~~FS-55~~FS-54
Consolidated Financial Statements		Note 2323		Other Contingencies and Commitments FS-54
Reports of Management FS-20		Note 24		Asset Retirement Obligations ~~FS-58~~
~~Report of Management~~ ~~FS-21~~		~~Note 24~~		~~Other Financial Information~~ ~~FS-58~~FS-56
Report of Independent Registered Public Accounting Firm ~~FS-22~~FS-21		Note 2525		~~Earnings Per Share~~Other Financial Information ~~FS-59~~FS-57
Consolidated Statement of Income ~~FS-23~~FS-22		Note 2626		~~Acquisition of Atlas Energy, Inc.~~Assets Held for Sale ~~FS-60~~FS-57
Consolidated Statement of Comprehensive Income ~~FS-24~~FS-23		Note 27		Earnings Per Share FS-57
Consolidated Balance Sheet ~~FS-25~~FS-24
Consolidated Statement of Cash Flows ~~FS-26~~FS-25		Five-Year Financial Summary ~~FS-61~~FS-58
Consolidated Statement of Equity ~~FS-27~~FS-26		Supplemental Information on Oil and Gas Producing Activities ~~FS-62~~FS-59

FS-1



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

Key Financial Results


Millions of dollars, except per-share amounts	2012			2011			2010			2013			2012			2011
Net Income Attributable to
Chevron Corporation	$	26,179		$	26,895		$	19,024		$	21,423		$	26,179		$	26,895
Per Share Amounts:
Net Income Attributable to
Chevron Corporation
– Basic	$	13.42		$	13.54		$	9.53		$	11.18		$	13.42		$	13.54
– Diluted	$	13.32		$	13.44		$	9.48		$	11.09		$	13.32		$	13.44
Dividends	$	3.51		$	3.09		$	2.84		$	3.90		$	3.51		$	3.09
Sales and Other
Operating Revenues	$	230,590		$	244,371		$	198,198		$	220,156		$	230,590		$	244,371
Return on:
Capital Employed	18.7		%	21.6		%	17.4		%	13.5		%	18.7		%	21.6		%
Stockholders’ Equity	20.3		%	23.8		%	19.3		%	15.0		%	20.3		%	23.8		%
Earnings by Major Operating Area
Millions of dollars	2012			2011			2010			2013			2012			2011
Upstream
United States	$	5,332		$	6,512		$	4,122		$	4,044		$	5,332		$	6,512
International	18,456			18,274			13,555			16,765			18,456			18,274
Total Upstream	23,788			24,786			17,677			20,809			23,788			24,786
Downstream
United States	2,048			1,506			1,339			787			2,048			1,506
International	2,251			2,085			1,139			1,450			2,251			2,085
Total Downstream	4,299			3,591			2,478			2,237			4,299			3,591
All Other	(1,908		)	(1,482		)	(1,131		)	(1,623		)	(1,908		)	(1,482		)
Net Income Attributable to
Chevron Corporation^1,2	$	26,179		$	26,895		$	19,024		$	21,423		$	26,179		$	26,895
¹ Includes foreign currency effects:	$	(454	)	$	121		$	(423	)	$	474		$	(454	)	$	121
²Also referred to as “earnings” in the discussions that follow.
²Income net of tax, also referred to as “earnings” in the discussions that follow.										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, ~~2012~~2013.

Business Environment and Outlook

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

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

earnings during the year.

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

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

The company 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 ~~2012~~2013. Asset dispositions and restructurings may also occur in future periods and could result in significant gains or losses.

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

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

UpstreamEarnings for the upstream segment are closely aligned with industry ~~price levels~~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, production quotas imposed by the Organization of Petroleum Exporting Countries (OPEC), weather-related damage and disruptions, competing fuel prices, and regional supply interruptions or fears thereof that may be caused by military conflicts, civil unrest or political uncertainty. Any of these factors could also inhibit the

FS-2

~~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. External factors include not only the general level of inflation, but also commodity prices and prices charged by the industry’s material and service providers, which can be affected by the volatility of the industry’s own supply-and-demand conditions for such materials and services. 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. Capital and exploratory expenditures and operating expenses can also be affected by damage to production facilities caused by severe weather or civil unrest.

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 ~~$112~~$109 per barrel for the full-year ~~2012~~2013, compared to ~~$111~~$112 in ~~2011~~2012. As of mid-February ~~2013~~2014, the Brent price was ~~about $118~~$109 per barrel. The majority of the company’s equity crude production is priced based on the Brent benchmark. The WTI price averaged ~~$94~~$98 per barrel for the full-year ~~2012~~2013, compared to ~~$95~~$94 in ~~2011~~2012. As of mid-February ~~2013~~2014, the WTI price was ~~about $97~~$100 per barrel. WTI ~~traded~~continued to trade at a discount to Brent ~~throughout 2012~~in 2013 due to historically high inventories ~~in the U.S. midcontinent market driven by~~stemming from strong growth in domestic ~~production.~~production and limitations on outbound pipeline capacity from the U.S. midcontinent. After narrowing during the first six months of 2013, the WTI discount slowly widened into

the fourth quarter as seasonal refinery turnarounds contributed to surplus supply conditions for WTI, while Brent prices were supported by supply disruptions due to international events.

A differential in crude oil prices exists between high-quality (high-gravity, low-sulfur) crudes and those of lower quality (low-gravity, high-sulfur). The amount of the differential in any period is associated with the supply of heavy crude ~~available~~ versus the demand, which is a function of the capacity of refineries that are

able to process this lower quality feedstock into light products (motor gasoline, jet fuel, aviation gasoline and diesel fuel). During ~~2012,~~2013, the differential between ~~U.S.~~North American light and heavy crude oil remained below historical norms asdue to growth in U.S. light sweet crude ~~oil~~ production in the midcontinent region ~~increased~~ and ~~outbound~~pipeline capacity constraints at ~~Cushing remained constrained.~~Cushing. Outside of North America, the ~~U.S., the~~light-heavy crude differential narrowed modestly ~~during 2012~~in 2013 as supply disruptions in key producing countries tightened light sweet crude markets and additional heavy crude oil conversion capacity came ~~on line.~~online.

Chevron produces or shares in the production of heavy crude oil in California, Chad, Indonesia, the Partitioned Zone between Saudi Arabia and Kuwait, Venezuela and in certain fields in Angola, China and the United Kingdom sector of the North Sea. (See page FS-10 for the company’s average U.S. and international crude oil realizations.)

In contrast to price movements in the global market for crude oil, price changes for natural gas in many regional markets are more closely aligned with supply-and-demand conditions in those markets. In the United States, prices at Henry Hub averaged ~~$2.71~~$3.70 per thousand cubic feet (MCF) during ~~2012~~2013, compared with ~~about $4.00~~$2.71 during ~~2011~~2012. As of mid-February ~~2013~~2014, the Henry Hub spot price was ~~about $3.30~~$5.53 per

FS-3



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

MCF. Fluctuations in the price of natural gas in the United States are closely associated with customer demand relative to the volumes produced in North America.

Outside the United States, price changes for natural gas depend on a wide range of supply, demand and regulatory circumstances. In some locations, Chevron is investing in long-term projects to install infrastructure to produce and liquefy natural gas for transport by tanker to other markets. International natural gas realizations averaged about ~~$6.00~~$5.91 per MCF during ~~2012~~2013, compared with ~~about $5.40~~$5.99 per MCF during ~~2011~~2012. (See page FS-10 for the company’s average natural gas realizations for the U.S. and international regions.)

~~FS-3~~



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

The company’s worldwide net oil-equivalent production in ~~2012~~2013 averaged ~~2.610~~2.597 million barrels per day. About one-fifth of the company’s net oil-equivalent production in ~~2012~~2013 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 ~~2012~~2013 or ~~2011~~2012. At their December ~~2012~~2013 meeting, members of OPEC supported maintaining the current production quota of 30 million barrels per day, which has been in effect since December 2008.

The company estimates that oil-equivalent production in ~~2013~~2014 will average approximately ~~2.650~~2.610 million barrels per day, based on an average Brent price of $~~112~~109 per barrel for the full-year ~~2012~~2013. This estimate is subject to many factors and uncertainties, including quotas that may be imposed by ~~OPEC,~~OPEC; price effects on entitlement ~~volumes,~~volumes; changes in fiscal terms or restrictions on the scope of company ~~operations,~~operations; delays in ~~project startups~~construction, start-up or ~~ramp-ups,~~ramp-up of projects; fluctuations in demand for natural gas in various ~~markets,~~markets; weather conditions that may shut in ~~production,~~production; civil ~~unrest,~~unrest; changing ~~geopolitics,~~geopolitics; delays in completion of maintenance ~~turnarounds,~~turnarounds; greater-than-expected declines in production from mature ~~fields,~~fields; or other disruptions to operations. The outlook for future production levels is also affected by the size and number of economic investment opportunities and, for new, large-scale projects, the time lag between initial exploration and the beginning of production. Investments in upstream projects generally begin well in advance of the start of the associated crude oil and natural gas production. A significant majority of Chevron’s upstream investment is made outside the United States.

Refer to the “Results of Operations” section on pages FS-6 through ~~FS-7~~FS-8 for additional discussion of the company’s upstream business.

Refer to Table V beginning on page ~~FS-67~~FS-64 for a tabulation of the company’s proved net oil and gas reserves by geographic area, at the beginning of ~~2010~~2011 and each year-end from ~~2010~~2011 through ~~2012~~2013, and an accompanying discussion of major changes to proved reserves by geographic area for the three-year period ending December 31, ~~2012~~2013.

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. ~~No evidence of any coastal or wildlife impacts related to this seep has emerged.~~ On March 14, 2012, the company identified a small, second seep in a different part of the field. As a precautionary measure, the company and its partners decided to temporarily suspend field production and received approval from Brazil’s National Petroleum Agency (ANP) to do so. Chevron and its partners are cooperating with the Brazilian authorities. On July 19, 2012, ANP issued its final investigative report on the November 2011 incident. A Brazilian federal district prosecutor filed two civil lawsuits seeking $10.7 billion in damages for

~~each of the two seeps. The company is not aware~~No evidence of any basis for damages to be awarded in any civil lawsuit. On July 31, 2012, a court presiding over the civil litigation entered a preliminary injunction barring Chevron from conducting oil production and transportation activities in Brazil pending completion of the legal proceedings commenced by the federal district prosecutor and the ongoing proceedings of ANP and the Brazilian environment and natural resources regulatory agency. On September 28, 2012, the injunction was modified to clarify that Chevron may continue its containment and mitigation activities under supervision of ANP. On appeal, on November 27, 2012, the injunction was revoked in its entirety.The federal district prosecutor also filed criminal charges against 11 Chevron employees. Jurisdiction for all three matters was moved from Campos to a court in Rio de Janeiro. On February 19, 2013, the court dismissed the criminal matter, which is subject to appeal by the prosecutor. Chevron has submitted to ANP a plan for restarting limited

coastal or wildlife impacts

FS-4

~~production~~

related to these seeps have emerged. A Brazilian federal district prosecutor filed two civil lawsuits seeking $10.7 billion in damages for each of the ~~Frade Field.~~two seeps. On October 1, 2013, the Court dismissed the two civil lawsuits and approved a settlement under which Chevron and its consortium partners agreed to spend approximately $43 million on social and environmental programs. On November 11, 2013, the Court announced that the settlement is final. The federal district prosecutor also filed criminal charges against Chevron and eleven Chevron employees. On February 19, 2013, the court dismissed the criminal matter, and on appeal, the appellate court reinstated two of the ten allegations, specifically those charges alleging environmental damage and failure to provide timely notification to authorities. The company is assessing its legal options. The company’s ultimate exposure related to the incident is not currently determinable, but could be significant to net income in any one period.

The company entered into a nonbinding financing term sheet with Petroboscan, a joint stock company owned 39.2 percent by Chevron, which operates the Boscan Field in Venezuela. When finalized, the financing is expected to occur in stages over a limited drawdown period and is intended to support a specific work program to maintain and increase production to an agreed-upon level. The terms are designed to support cash needs for ongoing operations and new development, as well as distributions to shareholders — including current outstanding obligations. The loan will be repaid from future Petroboscan crude sales. Definitive documents are under negotiation.

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. The company completed a multiyear plan in 2012 to streamline the downstream asset portfolio to concentrate resources and capital on strategic assets. In third quarter 2012, the company completed the sale of its Perth Amboy, New Jersey, refinery, which had been operated as a products terminal in recent years. In 2012, the company completed the sale of its fuels marketing and aviation businesses in eight countries in the Caribbean.

Refer to the “Results of Operations” section on pages ~~FS-7~~FS-6 through FS-8 for additional discussion of the company’s downstream operations.

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

Operating Developments

Key operating developments and other events during ~~2012~~2013 and early ~~2013~~2014 included the following:

Upstream

AngolaFirst shipment of liquefied natural gas was made from the Angola LNG project.

ArgentinaSigned agreements advancing the Loma Compana Project to develop the Vaca Muerta Shale.

Australia ~~In October 2012, the company acquired additional interests in the Clio~~Signed binding long-term LNG Sales and ~~Acme fields in the Carnarvon Basin in exchange for Chevron's interests in the Browse development. Consolidating interests in the Carnarvon Basin fits strategically~~Purchase Agreements with two Asian customers. Binding long-term ~~plans to grow the Wheatstone area resource base and creates expansion opportunities for~~agreements now cover approximately 85 percent of Chevron’s equity LNG offtake from the Wheatstone Project.

~~In September 2012, the company completed the sale of an equity interest in the Wheatstone Project to Tokyo Electric.~~

~~During 2012 and early 2013, the company announced~~Announced two natural gas discoveries atin the 47.3 percent-owned and operated Pontus prospect in Block WA-37-L, the 50 percent-owned and operated Satyr prospect in Block WA-374-P, the 50 percent-owned and operated Pinhoe prospect in Block WA-383-P, the 50 percent-owned and operated Arnhem prospect in Block WA-364-P, andCarnarvon Basin. These include discoveries at the 50 percent-owned and operated Kentish Knock South prospect in Block ~~WA-365-P. These discoveries are expected~~WA-365-P and

the 50 percent-owned and operated Elfin prospect in Block

WA-268-P.

Reached agreement to ~~contribute to potential expansion opportunities at company-operated LNG facilities.~~acquire interests in two onshore natural gas blocks in the Cooper Basin region of central Australia.

~~During 2012, Chevron signed nonbinding Heads~~Acquired exploration interests in two blocks located in the deepwater Bight Basin offshore South Australia.

Brazil Confirmed the start of ~~Agreement with Tohoku Electric and Chubu Electric and additional binding agreements with Tokyo Electric for LNG offtake~~crude oil production from the ~~Wheatstone Project. To date, more than~~Papa-Terra Field.

Awarded participation in a deepwater block in the Ceará Basin.

Canada Announced an agreement to acquire additional, complementary acreage in the Duvernay Shale.

Announced the successful conclusion of the initial twelve-well exploration drilling program in the liquids-rich portion of the Duvernay Shale located in western Canada.

Kurdistan Region of IraqAnnounced the acquisition of an 80 percent ~~of Chevron's equity LNG from Wheatstone is covered under long-term agreements with customers in Asia.~~

~~AngolaIn early 2013, the company announced it plans to proceed with the development~~interest and operatorship of the ~~Mafumeira Sul Project located in Block 0.~~Qara Dagh Block.

~~Angola-Republic~~Republic of the Congo ~~Joint Development AreaIn third quarter 2012,~~Announced the ~~company reached a~~ final investment decision on the ~~cross-border~~deepwater Moho Nord Project.

United StatesAnnounced a joint development ofagreement for additional Delaware Basin acreage and access to related infrastructure.

Announced a crude oil discovery at the Coronado prospect in the deepwater ~~Lianzi Field.~~Gulf of Mexico.

~~BangladeshIn July 2012, the company reached~~Announced a ~~final investment decision on the Bibiyana Expansion Project.~~

~~Canada~~ ~~In February 2013, Chevron~~ ~~acquired~~successful production test of a ~~50 percent-owned and operated interest~~St. Malo well in the ~~Kitimat LNG project and proposed Pacific Trail Pipeline, and a 50 percent nonoperated interest in approximately 644,000 acres in the Horn River and Liard Basins.~~deepwater Gulf of Mexico.

~~China~~ ~~In 2012, Chevron entered into an agreement to acquire two exploration blocks in the South China Sea's Pearl River Mouth Basin. Government approval is expected in 2013.~~

FS-5



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

~~Kurdistan Region of IraqIn third quarter 2012, Chevron acquired an 80 percent interest and operatorship in the Rovi and Sarta blocks.~~

~~Lithuania~~ ~~In October 2012, Chevron acquired a 50 percent interest in a company with exploration interests in a shale gas block.~~

~~Morocco~~ ~~In January 2013, the company announced that it had signed agreements to explore three offshore areas.~~

~~Nigeria~~ ~~In February 2012, production commenced at the deepwater Usan project.~~

~~Sierra Leone~~ ~~In September 2012, the company was awarded a 55 percent interest and operatorship in two deepwater exploration blocks.~~

~~SurinameIn November 2012, the company acquired a 50 percent interest in two offshore exploration blocks.~~

~~UkraineIn second quarter 2012, the company bid successfully for the right to exclusively negotiate a 50 percent interest and operatorship in a shale gas block.~~

~~United KingdomIn July 2012, the company initiated front-end engineering and design (FEED) for the deepwater Rosebank project west of the Shetland Islands.~~

~~United StatesIn October 2012, the company acquired additional acreage in New Mexico. A major portion of the acreage is located in the Delaware Basin, where the company is already one of the largest leaseholders.~~

In second quarter 2012, the company successfully bid for additional shelf and deepwater exploration acreage in the central Gulf of Mexico. In fourth quarter 2012, the company submitted high bids for additional deepwater acreage in the western Gulf of Mexico.

~~In the first quarter 2012, production commenced at the Caesar/Tonga project in the deepwater Gulf of Mexico.~~

Downstream

~~Caribbean~~ South Korea~~During 2012, the company completed the sale~~The company's 50 percent-owned GS Caltex affiliate started commercial operations of its ~~fuels marketing and aviation businesses in eight countries in~~gas oil fluid catalytic cracking unit at the ~~Caribbean.~~Yeosu Refinery.

~~EuropeDuring first quarter 2012, the company completed the sale of its fuels marketing, finished lubricants and aviation businesses in Spain.~~

~~Saudi Arabia~~United States ~~In October 2012, the~~The company's 50 percent-owned Chevron Phillips Chemical Company LLC (CPChem) announced ~~that~~a final investment decision on its ~~35 percent-owned Saudi Polymers Company began commercial production at its new petrochemical facility in Al-Jubail.~~

~~South KoreaDuring 2012, the company's 50 percent-owned GS Caltex affiliate completed the sale of certain power and other assets.~~

~~United States~~ ~~In third quarter 2012, the company completed the sale of its idled Perth Amboy, New Jersey, refinery, which had been operating as a terminal.~~

~~In April 2012, the company's 50 percent-owned Chevron Phillips Chemical Company LLC announced the execution of FEED contracts for~~U.S. Gulf Coast Petrochemicals Project. This project will include an ethane cracker ~~at its Cedar Bayou facility in Baytown, Texas,~~with an annual design capacity of 1.5 million metric tons per year and two polyethylene facilities, ~~near~~each with an annual design capacity of 500,000 metric tons per year.

CPChem announced plans to expand annual ethylene production by 200 million pounds at its Sweeny ~~facility~~complex in Old Ocean, Texas.

Other

Common Stock Dividends The quarterly common stock dividend was increased by 11.1 percent in April ~~2012~~2013 to ~~$0.90~~$1.00 per common share, making ~~2012~~2013 the ~~25th~~26th consecutive year that the company increased its annual dividend payment.

Common Stock Repurchase Program The company purchased $5.0 billion of its common stock in ~~2012~~2013 under its share repurchase program. The program began in 2010 and has no set term or monetary limits.

Results of Operations

Major Operating Areas The following section presents the results of operations 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 ~~10,~~11, beginning on page ~~FS-36,~~FS-35, for a discussion of the company’s “reportable ~~segments,~~segments.” ~~as defined in accounting standards for segment reporting (Accounting Standards Codification (ASC) 280).~~ This section should also be read in conjunction with the discussion in “Business Environment and Outlook” on pages FS-2 through FS-5.

U.S. Upstream


Millions of dollars	2012		2011		2010		2013		2012		2011
Earnings	$	5,332	$	6,512	$	4,122	$	4,044	$	5,332	$	6,512

U.S. upstream earnings of $4.0 billion in 2013 decreased $1.3 billion from 2012, primarily due to higher operating, depreciation and exploration expenses of $420 million, $350 million, and $190 million, respectively, and lower crude oil production of $170 million. Higher natural gas realizations of approximately $200 million were mostly offset by lower crude oil realizations of $170 million.

U.S. upstream earnings of $5.3 billion in 2012 decreased $1.2 billion from 2011, primarily due to lower natural gas and crude oil realizations of $340 million and $200 million, respectively, lower crude oil production of $240 million, and lower gains on asset sales of $180 million.

~~U.S. upstream earnings of~~ ~~$6.5 billion~~ in ~~2011~~ ~~increased~~ ~~$2.4 billion~~ ~~from~~ ~~2010~~. The benefit of higher crude oil realizations increased earnings by $2.8 billion between periods. Partly offsetting this effect were lower net oil-equivalent production, which decreased earnings by about $400 million, and higher operating expenses of $200 million.

The company’s average realization for U.S. crude oil and natural gas liquids in ~~2012~~2013 was $~~95.21~~93.46 per barrel, compared with $95.21 in 2012 and $97.51 in 2011 ~~and~~ ~~$71.59~~ in ~~2010~~. The average natural gas realization was $~~2.64~~3.37 per thousand cubic feet in ~~2012~~2013, compared with $~~4.04~~2.64 and $~~4.26~~4.04 in ~~2011~~2012 and ~~2010~~2011, respectively.

~~FS-6~~

Net oil-equivalent production in ~~2012~~2013 averaged ~~655,000~~657,000 barrels per day, essentially unchanged from 2012 and down 3 percent from 2011. Between 2013 and ~~7 percent~~2012 ~~from~~ ~~2010. Between~~, new production in the Marcellus Shale in western Pennsylvania and the Delaware Basin in New Mexico, along with the absence of weather-related downtime in the Gulf of Mexico, was largely offset by normal field declines. The decrease in production between 2012 and 2011~~, the decrease in production~~ was associated with normal field declines and an absence of volumes associated with Cook Inlet, Alaska, assets sold in 2011. Partially offsetting this decrease was a ramp-up of projects in the Gulf of Mexico and Marcellus Shale and improved operational performance in the Gulf of Mexico. The net liquids component of oil-equivalent production for ~~2012~~2013 averaged ~~455,000~~449,000 barrels per day, down 21 percent from ~~2011~~2012 and 73 percent from ~~2010~~2011. Net natural gas production averaged about 1.2 billion cubic feet per day in ~~2012~~2013, ~~down~~up approximately 64 percent from ~~2011~~2012 and down about 83 percent from ~~2010~~2011. Refer to the “Selected Operating Data” table on page FS-10 for a three-year comparative of production volumes in the United States.

FS-6

International Upstream



Millions of dollars	2013		2012			2011
Earnings*	$	16,765	$	18,456		$	18,274

*Includes foreign currency effects:	$	559	$	(275	)	$	211

Millions of dollars 2012
2011
2010
Earnings* $ 18,456
$ 18,274
$ 13,555

*Includes foreign currency effects: $ (275 ) $ 211
$ (293 )
International upstream earnings were $16.8 billion in 2013 compared with $18.5 billion in 2012. The decrease was

mainly due to the absence of 2012 gains of approximately

$1.4 billion on an asset exchange in Australia and $600

million on the sale of an equity interest in the Wheatstone

Project, lower crude oil prices of $500 million, and higher operating expense of $400 million. Partially offsetting these effects were lower income tax expenses of $430 million. Foreign currency effects increased earnings by $559 million in 2013, compared with a decrease of $275 million a year earlier.

International upstream earnings were $18.5 billion in 2012 compared with ~~$18.3~~$18.3 billion in 2011. The increase was mainly due to athe gain of ~~approximate~~approximately $1.4 billion on an asset exchange in Australia, higher natural gas realizations of about $610 million and athe nearly $600 million gain on sale of an equity interest in the Wheatstone Project. Mostly offsetting these effects were lower crude oil volumes of about $1.3 billion and higher exploration expenses of about $430 million. Foreign currency effects decreased earnings by $275 million in 2012, compared with an increase of $211 million a year earlier.

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

The company’s average realization for international crude oil and natural gas liquids in ~~2012~~2013 was $~~101.88~~100.26 per barrel, compared with $101.88 in 2012 and $101.53 in 2011 ~~and~~ ~~$72.68~~ in ~~2010~~. The average natural gas realization was $~~5.99~~5.91 per thousand cubic feet in ~~2012~~2013, compared with $~~5.39~~5.99 and $~~4.64~~5.39 in ~~2011~~2012 and ~~2010~~2011, respectively.

International net oil-equivalent production of ~~1.96~~1.94 million barrels per day in ~~2012~~2013 decreased 21 percent from 2012 and decreased about 3 percent from 2011. Project ramp-ups in Nigeria and ~~decreased about~~Angola in 2013 were more than offset by normal field declines. The decline between ~~5 percent~~2012 ~~from~~and ~~2010~~2011~~. New~~ was a result of new production in Thailand and Nigeria in 2012 ~~was~~ being more than offset by normal field declines, the shut-in of the Frade ~~field~~Field in Brazil and a major planned turnaround at Tengizchevroil. ~~The decline between 2011 and 2010 was primarily due to price effects on entitlement volumes.~~

The net liquids component of international oil-equivalent production was ~~about~~ 1.3 million barrels per day in ~~2012~~2013, a decrease of approximately 52 percent from ~~2011~~2012 and a decrease of approximately 97 percent from ~~2010~~2011. International net natural gas production of 3.9 billion cubic feet per day in ~~2012~~2013 was up

62 percent from 2012 and up 8 percent from 2011 ~~and up~~ ~~4 percent~~ ~~from~~ ~~2010~~.

Refer to the “Selected Operating Data” table, on page FS-10, for a three-year comparative of international production volumes.

U.S. Downstream


Millions of dollars	2012		2011		2010		2013		2012		2011
Earnings	$	2,048	$	1,506	$	1,339	$	787	$	2,048	$	1,506

U.S. downstream operations earned $787 million in 2013, compared with $2.0 billion in 2012. The decrease was mainly due to lower margins on refined product sales of $860 million and higher operating expenses of $600 million reflecting repair and maintenance activities at the company's refineries. The decrease was partially offset by higher earnings of $150 million from the 50 percent-owned CPChem.

U.S. downstream operations earned $2.0 billion in 2012, compared with ~~$1.5~~$1.5 billion in 2011. The increase was mainly due to higher margins on refined ~~product~~products sales of $520 ~~million~~ and higher earnings of $140 ~~million~~ from ~~the 50 percent-owned Chevron Phillips Chemical Company LLC (CPChem).~~CPChem. These benefits were partly offset by higher operating expenses of $130 million.

~~Earnings of~~ ~~$1.5 billion~~ ~~in 2011 increased~~ ~~$167 million~~ ~~from~~ ~~2010~~. Earnings benefited by $300 million from improved margins on refined products, $200 million from higher earnings from CPChem and $50 million from the absence of 2010 charges related to employee reductions. These benefits were partly offset by the absence of a $400 million gain on the sale of the company’s ownership interest in the Colonial Pipeline Company recognized in 2010.

~~Refined product sales of~~ ~~1.21 million~~ ~~barrels per day in~~ ~~2012~~ ~~declined~~ ~~4 percent, mainly reflecting lower gasoline and fuel oil sales. Sales volumes of refined products were~~ ~~1.26 million~~ ~~barrels per day in~~ ~~2011, a decrease of 7 percent from~~ ~~2010. The decline was mainly in gasoline, gas oil and kerosene sales. U.S. branded gasoline sales of 516,000 barrels per day in~~ ~~2012~~ ~~were essentially flat from 2011 and declined approximately 10 percent from~~ ~~2010. The decline in~~ ~~2012~~ ~~and~~

FS-7



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

~~2011~~Refined product sales of 1.18 million barrels per day in 2013 declined 2 percent, mainly reflecting lower gas oil, kerosene and gasoline sales. Sales volumes of refined products were 1.21 million barrels per day in 2012, a decrease of 4 percent from ~~2010~~2011, mainly reflecting lower gasoline and fuel oil sales. U.S. branded gasoline sales of 517,000 barrels per day in 2013 ~~was primarily due to weaker demand~~were essentially unchanged from 2012 and ~~previously completed exits from selected eastern U.S. retail markets.~~2011.

Refer to the “Selected Operating Data” table on page FS-10 for a three-year comparison of sales volumes of gasoline and other refined products and refinery input volumes.

International Downstream


Millions of dollars	2012			2011			2010			2013			2012			2011
Earnings*	$	2,251		$	2,085		$	1,139		$	1,450		$	2,251		$	2,085

*Includes foreign currency effects:	$	(173	)	$	(65	)	$	(135	)	$	(76	)	$	(173	)	$	(65	)

International downstream earned $1.5 billion in 2013, compared with $2.3 billion in 2012. Earnings decreased due to lower gains on asset sales of $540 million and higher income tax expenses of $110 million. Foreign currency effects decreased earnings by $76 million in 2013, compared to $173 million a year earlier.

International downstream earned $2.3 billion in 2012, compared with ~~$2.1~~$2.1 billion in 2011. Earnings increased due to a favorable change in effects on derivative instruments of $190 million and higher margins on refined product sales of $100 million. Foreign currency effects decreased earnings by $173 million in 2012, compared with a decrease of $65 million a year earlier.

~~Earnings of~~ ~~$2.1 billion~~ in ~~2011~~ ~~increased~~ ~~$946 million~~ ~~from~~ ~~2010~~. Gains on asset sales benefited earnings by $700 million, primarily from the sale of the Pembroke Refinery and related marketing assets in the United Kingdom and Ireland. Also contributing to earnings were improved margins of $200 million and the absence of 2010 charges of $90 million related to employee reductions. These benefits were partly offset by an unfavorable change in effects on derivative instruments of about $180 million. Foreign currency effects decreased earnings by ~~$65 million~~ in ~~2011, compared with a decrease of~~ ~~$135 million~~ in ~~2010~~.



Total refined product sales of 1.53 million barrels per day in 2013 declined 2 percent from 2012, mainly reflecting lower fuel oil and gasoline sales. Sales of 1.55 million barrels per day in 2012 declined 8 percent from 2011, primarily related to the third quarter 2011 sale of the company’s refining and marketing assets in the United Kingdom and Ireland. Excluding the impact of 2011 asset sales, sales volumes were flat between the comparative periods. International refined product sales volumes of 1.69 million barrels per day in 2011 were 4 percent lower than in 2010, primarily due to the sale of the company's refining and marketing assets in the United Kingdom and Ireland. Excluding the impact of 2011 asset sales, sales volumes were up 3 percent between the comparative periods.

Refer to the “Selected Operating Data” table, on page FS-10, for a three-year comparison of sales volumes of gasoline and other refined products and refinery input volumes.

All Other


Millions of dollars	2012			2011			2010			2013			2012			2011
Net charges*	$	(1,908	)	$	(1,482	)	$	(1,131	)	$	(1,623	)	$	(1,908	)	$	(1,482	)

*Includes foreign currency effects:	$	(6	)	$	(25	)	$	5		$	(9	)	$	(6	)	$	(25	)

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

Net charges in 2013 decreased $285 million from 2012, mainly due to lower corporate tax items and other corporate charges.

Net charges in 2012 increased $426 million from 2011, mainly due to higher environmental ~~reserve~~reserves additions, corporate tax items and other corporate charges, partially offset by lower employee compensation and benefits expenses.

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

FS-8

Consolidated Statement of Income

Comparative amounts for certain income statement categories are shown below:


Millions of dollars	2012		2011		2010		2013		2012		2011
Sales and other operating revenues	$	230,590	$	244,371	$	198,198	$	220,156	$	230,590	$	244,371

Sales and other operating revenues decreased in ~~2012~~2013 mainly due to lower refined product prices and lower crude oil volumes and prices. The decrease between 2012 and 2011 was mainly due to the 2011 sale of the company’s refining and marketing assets in the United Kingdom and Ireland, and lower crude oil volumes. ~~Higher 2011 prices for crude oil and refined products resulted in increased sales and other operating revenues compared with 2010.~~


Millions of dollars	2012		2011		2010		2013		2012		2011
Income from equity affiliates	$	6,889	$	7,363	$	5,637	$	7,527	$	6,889	$	7,363

Income from equity affiliates increased in 2013 from 2012 mainly due to higher upstream-related earnings from Tengizchevroil in Kazakhstan and Petropiar in Venezuela, and higher earnings from CPChem, partially offset by 2013 impairments of power-related affiliates.

Income from equity affiliates decreased in 2012 from 2011 mainly due to lower upstream-related earnings from Tengizchevroil in Kazakhstan as a result of lower crude oil production, and higher operating expenses at Angola LNG Limited and Petropiar in Venezuela. Downstream-related earnings were higher between comparative periods, primarily due to higher margins at CPChem.

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

Refer to Note ~~11,~~12, beginning on page ~~FS-38,~~FS-37, for a discussion of Chevron’s investments in affiliated companies.


Millions of dollars	2012		2011		2010		2013		2012		2011
Other income	$	4,430	$	1,972	$	1,093	$	1,165	$	4,430	$	1,972

Other income of $~~4.4~~1.2 billion in ~~2012~~2013 included net gains from asset sales of ~~approximately $4.2 billion.~~$710 million before-tax. Other income in ~~both 2011~~2012 and ~~2010~~2011 included net gains from asset sales of $4.2 billion and $1.5 billion ~~and $1.1 billion,~~before-tax, respectively. Interest income was approximately $136 million in 2013, $166 million in 2012, and $145 million in 2011 ~~and $120 million in~~ ~~2010~~. Foreign currency effects ~~decreased~~increased other income by $103 million in 2013, while decreasing other income by $207 million in 2012~~, while~~ and increasing other income by $103 million in ~~2011 and decreasing other income by $251 million in~~ ~~2010~~2011.


Millions of dollars	2012		2011		2010		2013		2012		2011
Purchased crude oil and products	$	140,766	$	149,923	$	116,467	$	134,696	$	140,766	$	149,923

Crude oil and product purchases of $~~140.8~~134.7 billion were down in 2013 mainly due to lower prices for refined products and lower volumes for crude oil, partially offset by higher refined product volumes. Crude oil and product purchases in 2012 decreased by $9.2 billion from the prior year mainly due to the 2011 sale of the company’s refining and marketing assets in the United Kingdom and Ireland and lower natural gas prices. ~~Crude oil and product purchases in 2011 increased by $33.5 billion from the prior year due to higher prices for crude oil, natural gas and refined products.~~


Millions of dollars	2012		2011		2010		2013		2012		2011
Operating, selling, general and administrative expenses	$	27,294	$	26,394	$	23,955	$	29,137	$	27,294	$	26,394

Operating, selling, general and administrative expenses increased $~~900 million~~1.8 billion between ~~2012~~2013 and 2012due to higher employee compensation and benefits costs of $720 million, construction and maintenance expenses of $590 million, and professional services costs of $500 million.

Operating, selling, general and administrative expenses increased $900 million between 2012 and 2011 mainly due to higher contract labor and professional services of $590 million, and higher employee compensation and benefits of $280 million.

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


Millions of dollars	2012		2011		2010		2013		2012		2011
Exploration expense	$	1,728	$	1,216	$	1,147	$	1,861	$	1,728	$	1,216

Exploration expenses in ~~2012~~2013 increased from 2012 mainly due to higher charges for well write-offs.

Exploration expenses in 2012 increased from 2011 mainly due to higher geological and geophysical costs and well write-offs.



Millions of dollars	2013		2012		2011
Depreciation, depletion and amortization	$	14,186	$	13,413	$	12,911

~~Exploration expenses~~The increase in ~~2011 increased~~2013 from ~~2010~~2012 was mainly due to higher ~~geological~~depreciation rates for certain oil and ~~geophysical costs, partly~~gas producing fields, higher upstream impairments and higher accretion expense, partially offset by lower ~~well write-offs.~~

Millions of dollars 2012
2011
2010
Depreciation, depletion and
amortization
$ 13,413
$ 12,911
$ 13,063

production levels. The increase in 2012 from 2011 was mainly due to higher depreciation rates for certain oil and gas producing fields, partially offset by lower production levels. The decrease in 2011 from 2010 mainly reflected lower production levels and the 2011 sale of the Pembroke Refinery, partially offset by higher depreciation rates for certain oil and gas producing fields.


Millions of dollars	2012		2011		2010		2013		2012		2011
Taxes other than on income	$	12,376	$	15,628	$	18,191	$	13,063	$	12,376	$	15,628

Taxes other than on income increased in 2013 from 2012 mainly due to the consolidation of the 64 percent-owned Star Petroleum Refining Company, beginning June 2012, and higher consumer excise taxes in the United States. Taxes other than on income decreased in 2012 from 2011 primarily due to lower import duties in the United Kingdom reflecting the sale of the company’s refining and marketing assets in the United Kingdom and Ireland in 2011. Partially offsetting the decrease were excise taxes associated with consolidation of Star Petroleum Refining Company beginning June 2012. Taxes other than on income decreased in 2011 from 2010 primarily due to lower import duties in the United Kingdom reflecting the 2011 sale of the Pembroke Refinery and other downstream assets, partly offset by higher excise taxes in the company’s South Africa downstream operations.

Millions of dollars 2012
2011
2010
Interest and debt expense $ —
$ —
$ 50

~~Total interest and debt expenses were fully capitalized in 2012 and 2011.~~

FS-9



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


Millions of dollars	2012		2011		2010		2013		2012		2011
Income tax expense	$	19,996	$	20,626	$	12,919	$	14,308	$	19,996	$	20,626

Effective income tax rates were40 percent in 2013, 43 percent in 2012, and 43 percent in 2011. The decrease in the effective tax rate between 2013 and ~~40 percent~~2012 was primarily due to a lower effective tax rate in international upstream operations. The lower international upstream effective tax rate was driven by a greater portion of equity income in 2013 than in 2012 (equity income is included as part of before-tax income and is generally recorded net of income taxes) and foreign currency remeasurement impacts.

~~2010~~. The rate was unchanged between 2012 and 2011. The impact of lower effective tax rates in international upstream operations ~~were~~was offset by foreign currency remeasurement impacts between periods. For international upstream, the lower effective tax rates in the ~~current~~2012 period were driven primarily by the effects of asset sales, one-time tax benefits and reduced withholding taxes, which were partially offset by a lower utilization of tax credits during the year. ~~The rate was higher in~~ ~~2011~~ ~~than in~~ ~~2010~~ primarily due to higher effective tax rates in certain international upstream jurisdictions. The higher international upstream effective tax rates were driven primarily by lower utilization of non-U.S. tax credits in 2011 and the effect of changes in income tax rates between periods, which were partially offset by foreign currency remeasurement impacts.

Selected Operating Data^1,2


	2012		2011		2010		2013		2012		2011
U.S. Upstream
Net Crude Oil and Natural Gas
Liquids Production (MBPD)	455		465		489		449		455		465
Net Natural Gas Production (MMCFPD)³	1,203		1,279		1,314		1,246		1,203		1,279
Net Oil-Equivalent Production (MBOEPD)	655		678		708		657		655		678
Sales of Natural Gas (MMCFPD)	5,470		5,836		5,932		5,483		5,470		5,836
Sales of Natural Gas Liquids (MBPD)	16		15		22		17		16		15
Revenues From Net Production
Liquids ($/Bbl)	$	95.21	$	97.51	$	71.59	$	93.46	$	95.21	$	97.51
Natural Gas ($/MCF)	$	2.64	$	4.04	$	4.26	$	3.37	$	2.64	$	4.04
International Upstream
Net Crude Oil and Natural Gas
Liquids Production (MBPD)⁴	1,309		1,384		1,434		1,282		1,309		1,384
Net Natural Gas Production (MMCFPD)³	3,871		3,662		3,726		3,946		3,871		3,662
Net Oil-Equivalent Production (MBOEPD)
Production (MBOEPD)⁴	1,955		1,995		2,055		1,940		1,955		1,995
Sales of Natural Gas (MMCFPD)	4,315		4,361		4,493		4,251		4,315		4,361
Sales of Natural Gas Liquids (MBPD)	24		24		27		26		24		24
Revenues From Liftings
Liquids ($/Bbl)	$	101.88	$	101.53	$	72.68	$	100.26	$	101.88	$	101.53
Natural Gas ($/MCF)	$	5.99	$	5.39	$	4.64	$	5.91	$	5.99	$	5.39
Worldwide Upstream
Net Oil-Equivalent Production (MBOEPD)⁴	Net Oil-Equivalent Production (MBOEPD)⁴						Net Oil-Equivalent Production (MBOEPD)⁴
United States	655		678		708		657		655		678
International	1,955		1,995		2,055		1,940		1,955		1,995
Total	2,610		2,673		2,763		2,597		2,610		2,673
U.S. Downstream
Gasoline Sales (MBPD)⁵	624		649		700		613		624		649
Other Refined Product Sales (MBPD)	587		608		649		569		587		608
Total Refined Product Sales (MBPD)	1,211		1,257		1,349		1,182		1,211		1,257
Sales of Natural Gas Liquids (MBPD)	141		146		139		125		141		146
Refinery Input (MBPD)	833		854		890		774		833		854
International Downstream
Gasoline Sales (MBPD)⁵	412		447		521		398		412		447
Other Refined Product Sales (MBPD)	1,142		1,245		1,243		1,131		1,142		1,245
Total Refined Product Sales (MBPD)⁶	1,554		1,692		1,764		1,529		1,554		1,692
Sales of Natural Gas Liquids (MBPD)	64		63		78		62		64		63
Refinery Input (MBPD)⁷	869		933		1,004		864		869		933


¹	Includes company share of equity affiliates.				Includes company share of equity affiliates.
²	MBPD – 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.				MBPD – 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):				Includes natural gas consumed in operations (MMCFPD):
	United States	63	69	62	United States ⁸	72	65	69
	International	523	513	475	International ⁸	452	457	447
⁴	Includes: Canada – synthetic oil	43	40	24	Includes: Canada – synthetic oil	43	43	40
	Venezuela affiliate – synthetic oil	17	32	28	Venezuela affiliate – synthetic oil	25	17	32
⁵	Includes branded and unbranded gasoline.				Includes branded and unbranded gasoline.
⁶	Includes sales of affiliates (MBPD):	522	556	562	Includes sales of affiliates (MBPD):	471	522	556
⁷	As of June 2012, Star Petroleum Refining Company crude-input volumes are reported on a 100 percent consolidated basis. Prior to June 2012, crude-input volumes reflect a 64 percent equity interest.				As of June 2012, Star Petroleum Refining Company crude-input volumes are reported on a 100 percent consolidated basis. Prior to June 2012, crude-input volumes reflect a 64 percent equity interest.
⁸					2012 and 2011 conform to 2013 presentation.

FS-10

Liquidity and Capital Resources

Cash, ~~cash equivalents, time deposits~~Cash Equivalents, Time Deposits and ~~marketable securities~~Marketable Securities Total balances were $~~21.9~~16.5 billion and $~~20.1~~21.9 billion at December 31, ~~2012~~2013 and ~~2011~~2012, respectively. Cash provided by operating activities in ~~2012~~2013 was $~~38.8~~35.0 billion, compared with $~~41.1~~38.8 billion in ~~2011~~2012 and ~~$31.4~~$41.1 billion in ~~2010~~2011. Cash provided by operating activities was net of contributions to employee pension plans of approximately $1.2 billion, ~~$1.5~~$1.2 billion and ~~$1.4~~$1.5 billion in ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011, respectively. Cash provided by investing activities included proceeds and deposits related to asset sales of ~~$2.7~~$1.1 billion in 2013, $2.8 billion in 2012, and $3.5 billion in 2011~~, and $2.0 billion in~~ ~~2010~~.

Restricted cash of $~~1.5~~1.2 billion and $~~1.2~~1.5 billion ~~associated with tax payments, upstream abandonment activities, funds held in escrow for an asset acquisition and capital investment projects~~ at December 31, ~~2012~~2013 and ~~2011~~2012, respectively, was ~~invested~~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 tax payments, upstream abandonment activities, funds held in escrow for asset acquisitions and capital investment projects.

Dividends Dividends paid to common stockholders were $7.5 billion in 2013, $6.8 billion in 2012, ~~$6.1~~ and $6.1 billion in 2011 ~~and $5.7 billion in~~ ~~2010~~. In April ~~2012,~~2013, the company increased its quarterly dividend by 11.1 percent to ~~90 cents~~$1.00 per common share.

Debt and ~~capital lease obligations~~Capital Lease Obligations Total debt and capital lease obligations were $~~12.2~~20.4 billion at December 31, ~~2012~~2013, up from ~~$10.2~~$12.2 billion at year-end ~~2011~~2012.

The $~~2.0~~8.2 billion increase in total debt and capital lease obligations during ~~2012~~2013 included ~~the net effect of~~ a $4$6 billion bond issuance ~~and the early redemption~~in June 2013, timed in part to take advantage of ~~a $2 billion bond due in March 2014.~~historically low interest rates. 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 ~~$6.0~~$8.4 billion at December 31, ~~2012~~2013, compared with ~~$5.9~~$6.0 billion at year-end ~~2011~~2012. Of these amounts, ~~$5.9~~$8.0 billion and ~~$5.6~~$5.9 billion were reclassified to long-term at the end of each period, respectively. At year-end ~~2012~~2013, settlement of these obligations was not expected to require the use of working capital in ~~2013~~2014, as the company had the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis.

At ~~December 31, 2012~~, the company had $6.0 billion in committed credit facilities with various major banks, expiring in December 2016, which enable the refinancing of short-term obligations on a long-term basis. These facilities support commercial paper borrowing and can also be used for general corporate purposes. The company’s practiceChevron 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, 2012. In addition, in November 2012, the company filed with the Securities and Exchange Commission a new~~automatic shelf registration statement that expires in November ~~2015. This registration statement is~~2015 for an unspecified amount of nonconvertible debt securities issued or guaranteed by

the company.

The major debt rating agencies routinely evaluate the company’s debt, and the company’s cost of borrowing can increase or decrease depending on these debt ratings. The company has outstanding public bonds issued by Chevron Corporation ~~Chevron Corporation Profit Sharing/Savings Plan Trust Fund~~ and Texaco Capital Inc. All of these securities are the obligations of, or guaranteed by, Chevron Corporation and are rated AA by Standard & Poor’s Corporation and Aa1 by Moody’s Investors 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. The company also can modify capital spending plans during any extended periods of low prices for crude oil and natural gas and narrow margins for refined products and commodity chemicals to provide flexibility to continue paying the common stock dividend and maintain the company’s high-quality debt ratings.

Committed Credit Facilities Information related to committed credit facilities is included in Note 16 to the Consolidated Financial Statements, Short-Term Debt, beginning on page FS-45.

Common ~~stock repurchase program~~Stock Repurchase Program In July 2010, the Board of Directors approved an ongoing share repurchase program with no set term or monetary limits. The company expects to repurchase between $500 million and $2 billion of its common shares per quarter, at prevailing prices, as permitted by securities laws and other legal requirements and subject to market conditions and other factors. During ~~2012~~2013, the company purchased ~~46.6~~41.6 million common shares for $5.0 billion. From the inception of the program through

2013, the company had purchased 139.3 million shares for $15.0 billion.

FS-11



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

Capital and Exploratory Expenditures


	2012						2011						2010						2013						2012						2011
Millions of dollars	U.S.		Int’l.		Total		U.S.		Int’l.		Total		U.S.		Int’l.		Total		U.S.		Int’l.		Total		U.S.		Int’l.		Total		U.S.		Int’l.		Total
Upstream¹	$	8,531	$	21,913	$	30,444	$	8,318	$	17,554	$	25,872	$	3,450	$	15,454	$	18,904	$	8,480	$	29,378	$	37,858	$	8,531	$	21,913	$	30,444	$	8,318	$	17,554	$	25,872
Downstream	1,913		1,259		3,172		1,461		1,150		2,611		1,456		1,096		2,552		1,986		1,189		3,175		1,913		1,259		3,172		1,461		1,150		2,611
All Other	602		11		613		575		8		583		286		13		299		821		23		844		602		11		613		575		8		583
Total	$	11,046	$	23,183	$	34,229	$	10,354	$	18,712	$	29,066	$	5,192	$	16,563	$	21,755	$	11,287	$	30,590	$	41,877	$	11,046	$	23,183	$	34,229	$	10,354	$	18,712	$	29,066
Total, Excluding Equity in Affiliates	$	10,738	$	21,374	$	32,112	$	10,077	$	17,294	$	27,371	$	4,934	$	15,433	$	20,367	$	10,562	$	28,617	$	39,179	$	10,738	$	21,374	$	32,112	$	10,077	$	17,294	$	27,371

¹ Excludes the acquisition of Atlas Energy, Inc., in 2011.

~~2012, the company had purchased~~ ~~97.7~~ ~~million shares for~~ ~~$10.0~~ ~~billion.~~

Capital and ~~exploratory expenditures~~Exploratory Expenditures Total expenditures for ~~2012~~2013 were $~~34.2~~41.9 billion, including $~~2.1~~2.7 billion for the company’s share of equity-affiliate ~~expenditures.~~expenditures, which did not require cash outlays by the company. In ~~2011~~2012 and ~~2010~~2011, expenditures were $~~29.1~~34.2 billion and $~~21.8~~29.1 billion, respectively, including the company’s share of affiliates’ expenditures of $~~1.7~~2.1 billion and $~~1.4~~1.7 billion, respectively.

Expenditures for 2013 include approximately $4 billion for major resource acquisitions in Argentina, Australia, the Permian Basin and the Kurdistan Region of Iraq, along with additional acreage in the Duvernay Shale and interests in the Kitimat LNG Project in Canada. In addition, work progressed on a number of major capital projects, particularly two Australian LNG projects and two deepwater Gulf of Mexico projects.

Of the $~~34.2~~41.9 billion of expenditures in ~~2012~~2013, 8990 percent, or $~~30.4~~37.9 billion, was related to upstream activities. Approximately,

89 percent ~~and~~ 87 ~~percent were~~was expended for upstream operations in ~~2011~~2012 and ~~2010~~2011. International upstream accounted for ~~about~~ 7278 percent of the worldwide upstream investment in ~~2012~~2013, ~~about~~72 percent in 2012 and 68 percent in 2011 ~~and about~~ 82 ~~percent in~~ ~~2010~~. These amounts exclude the acquisition of Atlas Energy, Inc., in 2011.

The company estimates that ~~2013~~2014 capital and exploratory expenditures will be ~~$36.7~~$39.8 billion, including ~~$3.3~~$4.8 billion of

spending by affiliates. Approximately 90 percent of the total, or ~~$33~~$35.8 billion, is budgeted for exploration and production activities. Approximately ~~$25.5~~$27.9 billion, or 7778 percent, of this amount is for projects outside the United States. Spending in ~~2013~~2014 is primarily focused on major development projects in Angola, Argentina, Australia, ~~Brazil,~~ Canada, ~~China,~~ Kazakhstan, Nigeria, Republic of the Congo, Russia, the United Kingdom and the U.S. ~~Gulf of Mexico.~~ Also included is funding for enhancing recovery and mitigating natural field declines for currently-producing assets, and for focused exploration and appraisal activities.

Worldwide downstream spending in ~~2013~~2014 is estimated at ~~$2.7~~$3.1 billion, with ~~about $1.4~~$1.8 billion for projects in the United States. Major capital outlays include projects under construction at refineries in the United States and expansion of additives production capacity in ~~Singapore and~~Singapore. Additional investments are expected to be funded by CPChem for chemicals projects in the United States.

Investments in technology companies, power ~~generation~~and energy services, and other corporate businesses in ~~2013~~2014 are budgeted at $1 billion.

Noncontrolling ~~interests~~Interests The company had noncontrolling interests of $1.3 billion at both December 31, ~~$1,308 million~~2013 and ~~$799 million~~ ~~at December 31,~~ 2012 ~~and~~ ~~2011, respectively.~~. Distributions to noncontrolling interests totaled $4199 million and $7141 million in ~~2012~~2013 and ~~2011~~2012, respectively.

Pension Obligations Information related to pension plan contributions is included on page ~~FS-54~~FS-53 in Note 2021 to the Consolidated Financial Statements under the heading “Cash Contributions and Benefit Payments.” ~~Refer also to the discussion of pension accounting in “Critical Accounting Estimates and Assumptions,” beginning on page FS-16.~~

FS-12

Financial Ratios


	At December 31						At December 31
	2012		2011		2010		2013		2012		2011
Current Ratio	1.6		1.6		1.7		1.5		1.6		1.6
Interest Coverage Ratio	191.3		165.4		101.7		126.2		191.3		165.4
Debt Ratio	8.2	%	7.7	%	9.8	%	12.1	%	8.2	%	7.7	%

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 ~~2012~~2013, the book value of inventory was lower than replacement costs, based on average acquisition costs during the year, by approximately ~~$9.3~~$9.1 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 ~~2012~~2013 was ~~higher~~lower than ~~2011~~2012 and ~~2010~~2011 due to lower ~~before-tax interest costs.~~income.

Debt Ratio – total debt as a percentage of total debt plus Chevron Corporation Stockholders' Equity, which indicates the company’s leverage. The ~~increase between~~company's debt ratio in 2013 was higher than 2012 and 2011 ~~was~~ due to higher debt, partially offset by a higher ~~Chevron Corporation stockholders' equity balance. The decrease between~~ ~~2011~~ ~~and~~ ~~2010~~ ~~was due to a higher Chevron Corporation~~ stockholders' equity balance.

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

Direct Guarantees


Millions of dollars	Commitment Expiration by Period					Commitment Expiration by Period
			2014–	2016–	After			2015–	2017–	After
	Total	2013	2015	2017	2017	Total	2014	2016	2018	2018
Guarantee of non- consolidated affiliate or joint-venture obligations	$562	$38	$76	$76	$372	$524	$38	$76	$76	$334

The company’s guarantee of $~~562~~524 million is associated with certain payments under a terminal use agreement entered into by an equity affiliate. Over the approximate 1514-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-56~~FS-55 in Note 2223 to the Consolidated Financial Statements under the heading “Indemnifications.”

Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay

Agreements The company and its subsidiaries have certain other contingent liabilities with respect to long-term unconditional purchase obligations and commitments, including throughput and take-or-pay agreements, some of which relate to suppliers’

financing arrangements. The agreements typically provide goods and services, such as pipeline and storage capacity, drilling rigs, utilities, and petroleum products, to be used or sold in the ordinary course of the company’s business. The aggregate approximate amounts of required payments under these various commitments are: ~~2013~~ ~~– $3.7 billion;~~ 2014 – ~~$3.9~~$4.2 billion; 2015 – ~~$4.1~~$4.5 billion; 2016 – ~~$2.4~~$3.2 billion; 2017 – ~~$1.8~~$2.6 billion; 2018 – $2.2 billion; 2019 and after – ~~$6.5~~$6.9 billion. A portion of these commitments may ultimately be shared with project partners. Total payments under the agreements were approximately $3.6 billion in 2013, $3.6 billion in 2012, and $6.6 billion in 2011 ~~and $6.5 billion in~~ ~~2010~~.

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

Contractual Obligations¹


Millions of dollars	Payments Due by Period										Payments Due by Period
					2014–		2016–		After						2015–		2017–		After
	Total		2013		2015		2017		2017		Total		2014		2016		2018		2018
On Balance Sheet:²
Short-Term Debt³	$	127	$	127	$	—	$	—	$	—	$	374	$	374	$	—	$	—	$	—
Long-Term Debt³	11,966		—		5,923		2,000		4,043		19,960		—		8,750		4,000		7,210
Noncancelable Capital Lease Obligations	189		45		60		25		59		177		45		52		34		46
Interest	1,983		210		408		402		963		2,611		335		659		606		1,011
Off Balance Sheet:
Noncancelable Operating Lease Obligations	3,548		727		1,276		929		616		3,709		798		1,327		778		806
Throughput and Take-or-Pay Agreements⁴	17,164		2,705		5,480		2,904		6,075		15,320		2,679		4,372		2,587		5,682
Other Unconditional Purchase Obligations⁴	5,285		1,003		2,470		1,342		470		8,257		1,527		3,386		2,188		1,156


¹	Excludes contributions for pensions and other postretirement benefit plans. Information on employee benefit plans is contained in Note 2021 beginning on page ~~FS-49.~~FS-48.


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 these liabilities may become payable. The company does not expect settlement of such liabilities will have a material effect on its consolidated financial position or liquidity in any single period.


³	$~~5.9~~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 ~~2014~~2015–~~2015~~2016 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-13~~



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

Financial and Derivative ~~Instruments~~Instrument Market Risk

The market risk associated with the company’s portfolio of financial and derivative instruments is discussed ~~below.~~on the next page. 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 ~~2012~~2013 Annual Report on Form 10-K.

FS-13



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

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 ~~2012~~2013.

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

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

Derivatives beyond those designated as normal purchase and normal sale contracts are recorded at fair value on the Consolidated Balance Sheet ~~in accordance with accounting standards for derivatives (ASC 815),~~ with resulting gains and losses reflected in income. Fair values are derived principally from published market quotes and other independent third-party quotes. The change in fair value of Chevron’s derivative commodity instruments in ~~2012~~2013 was ~~a quarterly average decrease~~not material to the company's results of ~~$31 million in total assets and a quarterly average increase of $12 million in total liabilities.~~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 ~~on a single day~~ from the effect of adverse changes in market conditions on derivative commodity instruments held or issued. VaR is the maximum projected loss not to be exceeded within a given probability or confidence level over a given period of time. The company’s VaR model uses the Monte Carlo simulation method that involves generating hypothetical scenarios from the specified probability distributions and constructing a full distribution of a portfolio’s potential values.

~~The VaR model utilizes an exponentially weighted moving average for computing historical volatilities and correlations, a 95 percent confidence level, and a one-day holding period. That is,~~

the company’s 95 percent, one-day VaR corresponds to the unrealized loss in portfolio value that would not be exceeded on average more than one in every 20 trading days, if the portfolio were held constant for one day.

~~The~~A one-day holding period is ~~based~~used on the assumption that market-risk positions can be liquidated or hedged within one day. ~~For hedging and risk management,~~Based on these inputs, the company uses conventional exchange-traded instruments such as futures and options as well as non-exchange-traded swaps, most of which can be liquidated or hedged effectively within one day. The following table presents the 95 percent/one-day VaR for ~~each of~~ the ~~company’s~~company's primary risk exposures in the area of derivative commodity instruments at December 31, ~~2012~~2013 and ~~2011~~2012. was not material to the company's cash flows or results of operations.

Millions of dollars 2012
2011
Crude Oil $ 3
$ 22
Natural Gas 3
4
Refined Products 12
11

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, ~~2012~~2013.

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 ~~2012~~2013, the company had no interest rate swaps.

~~FS-14~~

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 1112 of the Consolidated Financial Statements, page ~~FS-39,~~FS-38, for further discussion. Management believes these agreements have been negotiated on terms consistent with those that would have been negotiated with an unrelated party.

Litigation and Other Contingencies

MTBE Information related to methyl tertiary butyl ether (MTBE) matters is included on page ~~FS-40~~FS-39 in Note 1314 to the Consolidated Financial Statements under the heading “MTBE.”

Ecuador Information related to Ecuador matters is included in Note 1314 to the Consolidated Financial Statements under the heading “Ecuador,” beginning on page ~~FS-40.~~FS-39.

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	2012			2011			2010			2013			2012			2011
Balance at January 1	$	1,404		$	1,507		$	1,700		$	1,403		1,403.844			$	1,507
Net Additions	428			343			220			488			428.475			343
Expenditures	(429		)	(446		)	(413		)	(435		)	(429		)	(446		)
Balance at December 31	$	1,403		$	1,404		$	1,507		$	1,456		$	1,403		$	1,404

FS-14

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 $~~13.3~~14.3 billion for asset retirement obligations at year-end ~~2012~~2013 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 ~~2012~~2013 environmental expenditures. Refer to Note 2223 on pages ~~FS-56~~FS-55 through ~~FS-57~~FS-56 for additional discussion of environmental remediation provisions and year-end reserves. Refer also to Note 2324 on page ~~FS-58~~FS-56 for additional discussion of the company's asset retirement obligations.

Suspended WellsInformation related to suspended wells is included in Note 1819 to the Consolidated Financial Statements, Accounting for Suspended Exploratory Wells, beginning on page ~~FS-47.~~FS-46.

Income Taxes Information related to income tax contingencies is included on pages FS-43 through FS-45 in Note 1415 and pages ~~FS-55~~FS-54 through ~~FS-56~~FS-55 in Note 2223 to the Consolidated Financial Statements under the heading “Income Taxes.”

The American Taxpayer Relief Act of 2012 (the Act) was signed into U.S. law on January 2, 2013. Several tax provisions that expired at the end of 2011 were extended retroactive to January 1, 2012, including the research and development credit and certain rules for controlled foreign corporations. There were no impacts from the Act included in Chevron's 2012 financial statements and the company does not expect the impacts of the Act to have a material effect on its results of operations, consolidated financial position or liquidity in any future reporting period.

Other Contingencies Information related to other contingencies is included on page ~~FS-57~~FS-56 in Note 2223 to the Consolidated Financial Statements under the heading “Other Contingencies.”

Environmental Matters

Virtually all aspects of the businesses in which the company engages are subject to various international, federal, state and local environmental, health and safety laws, regulations and market-based programs. These regulatory requirements continue to increase in both number and complexity over time and govern not only the manner in which the company conducts its operations, but also the products it sells. Regulations intended to address concerns about greenhouse gas emissions and global climate change also continue to evolve and include those at the international or multinational (such as the mechanisms under the Kyoto Protocol and the European Union's Emissions Trading System), national (such as the U.S. Environmental Protection Agency's emission standards and renewable transportation fuel content requirements or domestic market-based programs such as those in effect in Australia and New Zealand), and state or regional (such as California's Global Warming Solutions Act) levels.

Most of the costs of complying with laws and regulations pertaining to company operations and products are embedded in the normal costs of doing business. It is not possible to predict with certainty the amount of additional investments in new or existing facilities or amounts of incremental operating costs to be incurred in the future to: prevent, control, reduce or eliminate releases of hazardous materials into the environment; comply with existing

and new environmental laws or regulations; or remediate and restore areas damaged by prior releases of hazardous materials. Although these costs may be significant to the results of operations in any single period, the company does not expect them to have a material effect on the company's liquidity or financial position.

Accidental leaks and spills requiring cleanup may occur in the ordinary course of business. In addition to the costs for environmental protection associated with its ongoing operations and products, the company may incur expenses for corrective actions at various owned and previously owned facilities and at third-party-owned waste disposal sites used by the company. An obligation may arise when operations are closed or sold or at non-Chevron sites where company products have been handled or disposed of. Most of the

~~FS-15~~



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

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 ~~2012~~2013 at approximately ~~$2.8~~$2.7 billion for its consolidated companies. Included in these expenditures were approximately ~~$1.1~~$1.0 billion of environmental capital expenditures and $1.7 billion of costs associated with the prevention, control, abatement or elimination of hazardous substances and pollutants from operating, closed or divested sites, and the abandonment and restoration of sites.

For ~~2013~~2014, total worldwide environmental capital expenditures are estimated at ~~$1.2~~$1.1 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. All such estimates and assumptions affect reported amounts of assets, liabilities, revenues and expenses, as well as disclosures of contingent assets and liabilities. Estimates and assumptions are based on management’s experience and other information available prior to the issuance of the financial statements. Materially different results can occur as circumstances change and additional information becomes known.

FS-15



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

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:

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

~~Note 20, beginning on page FS-49, includes information on the funded status of the company’s pension and OPEB plans at the end of~~ ~~2012~~ ~~and~~ ~~2011; the components of pension and OPEB expense for the three years ended December 31,~~ ~~2012; and the underlying assumptions for those periods.~~

Pension and OPEB expense is reported on the Consolidated Statement of Income as “Operating expenses” or “Selling, general and administrative expenses” and applies to all business segments. The year-end ~~2012~~ ~~and~~ ~~2011~~ funded status, measured as the difference between plan assets and obligations, of each of the company’s pension and OPEB plans is recognized on the Consolidated Balance Sheet. The differences related to overfunded pension plans are reported as a long-term asset in “Deferred charges and other assets.” The differences associated with underfunded or unfunded pension and OPEB plans are reported as “Accrued liabilities” or “Reserves for employee benefit plans.” Amounts yet to be recognized as components of pension or OPEB expense are reported in “Accumulated other comprehensive loss.”

To estimate the long-term rate of return on pension assets, the company uses a process that incorporates actual historical asset-class returns and an assessment of expected future performance and takes into consideration external actuarial advice and asset-class factors. Asset allocations are periodically updated using pension plan asset/liability studies, and the determination of the company’s estimates of long-term rates of return are consistent with these studies. For 2012, the company used an expected long-term rate of return of 7.5 percent for U.S. pension plan assets, which account for 70 ~~percent of the company’s pension plan assets. In~~ ~~2011~~ ~~and~~ ~~2010, the company used a long-term rate of return of 7.8 percent for this plan. For the 10 years ending December 31,~~ ~~2012, actual asset returns averaged 7.1 percent for this plan. The actual return for~~ ~~2012~~ was more than 7.5 percent and was associated with a broad recovery in the financial markets during the year. Additionally, with the exception of two other years within this 10-year period, actual asset returns for this plan equaled or exceeded 7.5 percent.

~~FS-16~~

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

The discount rate assumptions used to determine the U.S. and international pension and postretirement benefit plan obligations and expense reflect the at which benefits could be effectively settled and is 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, ~~2012, the company used a~~ ~~3.6 percent~~ ~~discount rate for the U.S. pension plans and~~ ~~3.9 percent~~ ~~for the main U.S. OPEB plan. The discount rates at the end of~~ ~~2011~~ ~~and~~ ~~2010~~ ~~were~~ ~~3.8~~ ~~and~~ ~~4.0~~ ~~percent and~~ ~~4.8~~ ~~and~~ ~~5.0~~ ~~percent for the U.S. pension plans and the main U.S. OPEB plans, respectively.~~

~~An increase in the expected long-term return on plan assets or the discount rate would reduce pension plan expense, and vice versa. Total pension expense for~~ ~~2012~~ ~~was $1.3~~ billion. As an indication of the sensitivity of pension expense to the long-term rate of return assumption, a 1 percent increase in the expected rate of return on assets of the company’s primary U.S. pension plan would have reduced total pension plan expense for ~~2012~~ by approximately $80 million. A 1 percent increase in the discount rate for this same plan, which accounted for about 62 percent of the companywide pension obligation, would have reduced total pension plan expense for ~~2012~~ ~~by approximately $165 million.~~

An increase in the discount rate would decrease the pension obligation, thus changing the funded status of a plan reported on the Consolidated Balance Sheet. The aggregate funded status recognized on the Consolidated Balance Sheet at December 31, ~~2012, was a net liability of approximately $5.9~~ billion. As an indication of the sensitivity of pension liabilities to the discount rate assumption, a 0.25 percent increase in the discount rate applied to the company’s primary U.S. pension plan would have reduced the plan obligation by approximately $335 million, which would have decreased the plan’s underfunded status from approximately $2.6 billion to $2.2 billion. Other plans would be less underfunded as discount rates increase. The actual rates of return on plan assets and discount rates may vary significantly from estimates because of unanticipated changes in the world’s financial markets.

In ~~2012, the company’s pension plan contributions were $1.2~~ ~~billion (including $844 million~~ ~~to the U.S. plans). In~~ ~~2013, the company estimates contributions will be approximately~~ ~~$1.0 billion~~. Actual contribution amounts are dependent upon investment results, changes in pension obligations, regulatory requirements and other economic factors. Additional funding may be required if investment returns are insufficient to offset increases in plan obligations.

~~For the company’s OPEB plans, expense for~~ ~~2012~~ ~~was $172 million, and the total liability, which reflected the unfunded status of the plans at the end of~~ ~~2012, was $3.8~~ ~~billion.~~

~~As an indication of discount rate sensitivity to the determination~~

~~of OPEB expense in~~ ~~2012~~, a 1 percent increase in the discount rate for the company’s primary U.S. OPEB plan, which accounted for about 82 percent of the companywide OPEB expense, would have decreased OPEB expense by approximately $17 million. A 0.25 percent increase in the discount rate for the same plan, which accounted for about 83 percent of the companywide OPEB liabilities, would have decreased total OPEB liabilities at the end of ~~2012~~ ~~by approximately $80 million.~~

~~For the main U.S. postretirement medical plan, the annual increase to company contributions is limited to~~ ~~4 percent~~ ~~per year. For active employees and retirees under age 65 whose claims experiences are combined for rating purposes, the assumed health care cost-trend rates start with~~ ~~7.5 percent~~ in ~~2013~~ ~~and gradually drop to~~ ~~4.5 percent~~ ~~for~~ ~~2025~~ ~~and beyond. As an indication of the health care cost-trend rate sensitivity to the determination of OPEB expense in~~ ~~2012, a 1 percent increase in the rates for the main U.S. OPEB plan, would have increased OPEB expense by $15 million.~~

Differences between the various assumptions used to determine expense and the funded status of each plan and actual experience are not included in benefit plan costs in the year the difference occurs. Instead, the differences are included in actuarial gain/loss and unamortized amounts have been reflected in “Accumulated other comprehensive loss” on the Consolidated Balance Sheet. Refer to Note 20, beginning on page FS-49, for information on the $~~9.7~~ ~~billion of before-tax actuarial losses recorded by the company as of December 31,~~ ~~2012; a description of the method used to amortize those costs; and an estimate of the costs to be recognized in expense during~~ ~~2013~~.

Oil and Gas ReservesCrude 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 and economic conditions.

~~FS-17~~



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

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:

Amortization - Proved reserves are used in amortizing capitalized costs related to oil and gas producing activities on the unit-of-production (UOP) method. Capitalized exploratory drilling and development costs are depreciated on a UOP basis using proved developed reserves. Acquisition costs of proved properties are amortized on a UOP basis using total proved reserves. During ~~2012~~2013, Chevron's UOP Depreciation, Depletion and Amortization (DD&A) for oil and gas properties was ~~$10.7~~$11.6 billion, and proved developed reserves at the beginning of ~~2012~~2013 were 4.8 billion barrels. 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 ~~2012~~2013 would have increased by approximately $~~540~~600 million.


2.	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. In assessing whether the property is impaired, the fair value of the property must be determined. Frequently, a discounted cash flow methodology is the best estimate of fair value. 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-67,~~FS-64, for the changes in proved reserve estimates for the three years ending December 31, ~~2012~~2013, and to Table VII, “Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves” on page ~~FS-75~~FS-72 for estimates of proved reserve values for each of the three years ended December 31, ~~2012~~2013.

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,~~FS-27, 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. Such indicators include changes in the company’s business plans, changes in commodity prices and, for crude oil and natural gas properties, significant downward revisions of estimated proved reserve quantities. If the carrying value of an asset exceeds the future undiscounted cash

flows expected from the asset, an impairment charge is recorded for the excess of carrying value of the asset over its estimated fair value.

Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters, such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles, and the outlook for global or regional market supply-and-demand conditions for crude oil, natural gas, commodity chemicals and refined products. However, the impairment reviews and calculations are based on

FS-16

assumptions that are consistent with the company’s business plans and long-term investment decisions. Refer also to the discussion of impairments of properties, plant and equipment in Note 89 beginning on page FS-33 and to the section on Properties, Plant and Equipment in Note 1, ~~Summary~~"Summary of Significant Accounting Policies," beginning on page ~~FS-28.~~FS-27.

No material individual impairments of PP&E or Investments were recorded for the three years ending December 31, ~~2012~~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.

Investments in common stock of affiliates that are accounted for under the equity method, as well as investments in other securities of these equity investees, are reviewed for impairment when the fair value of the investment falls below the company’s carrying value. When such a decline is deemed to be other than temporary, an impairment charge is recorded to the income statement for the difference between the investment’s carrying value and its estimated fair value at the time.

~~FS-18~~

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

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

Asset Retirement ObligationsIn 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 ~~2012~~2013 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 2324 on page ~~FS-58~~FS-56 for additional discussions on asset retirement obligations.

Pension and Other Postretirement Benefit Plans Note 21, beginning on page FS-48, 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-48 in Note 21 under the relevant headings. Actual rates may vary significantly from estimates because of unanticipated changes in the world's financial markets.

For 2013, the company used an expected long-term rate of return of 7.5 percent and a discount rate of 3.6 percent for U.S. pension plans. For the 10 years ending December 31, 2013, actual asset returns averaged 6.4 percent for the plan. The actual return for 2013 was more than 7.5 percent and was associated with a continuing recovery in the financial markets during the year. Additionally, with the exception of two other years within this 10-year period, actual asset returns for this plan equaled or exceeded 7.5 percent.

Total pension expense for 2013 was $1.3 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 59 percent of companywide pension expense, would have reduced total pension plan expense for 2013 by approximately $85 million. A 1 percent increase in the discount rate for this same plan would have reduced pension expense for 2013 by approximately $190 million.

The aggregate funded status recognized at December 31, 2013, was a net liability of approximately $2.4 billion. An increase in the discount rate would decrease the pension obligation, thus changing the funded status of a plan. At December 31, 2013, the company used a discount rate of

FS-17



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

4.3 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 59 percent of the companywide pension obligation, would have reduced the plan obligation by approximately $345 million, which would have increased the plan’s overfunded status from approximately $0.4 billion to $0.7 billion.

For the company’s OPEB plans, expense for 2013 was $218 million, and the total liability, which reflected the unfunded status of the plans at the end of 2013, was $3.1 billion. For the main U.S. OPEB plan, the company used a 3.9 percent discount rate to measure expense in 2013, and a 4.7 percent discount rate to measure the benefit obligations at December 31, 2013. Discount rate changes, similar to those used in the pension sensitivity analysis, resulted in an immaterial impact on 2013 OPEB expense and OPEB liabilities at the end of 2013. For information on the sensitivity of the health care cost-trend rate, refer to FS-51 in Note 21 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-50 in Note 21 for a description of the method used to amortize the $5.2 billion of before-tax actuarial losses recorded by the company as of December 31, 2013, and an estimate of the costs to be recognized in expense during 2014. In addition, information related to company contributions is included on Page FS-53 in Note 21 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 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 1423 beginning on page ~~FS-43.~~FS-54. 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, ~~2012~~2013.

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 ~~17,~~18, on page ~~FS-47~~FS-46 in the Notes to Consolidated Financial Statements, for information regarding new accounting standards.

~~FS-19~~FS-18

Quarterly Results and Stock Market Data

Unaudited


	2012								2011									2013								2012
Millions of dollars, except per-share amounts	4th Q		3rd Q		2nd Q		1st Q			4th Q		3rd Q		2nd Q		1st Q		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	$	56,254	$	55,660	$	59,780	$	58,896		$	58,027	$	61,261	$	66,671	58,412		$	53,950	$	56,603	$	55,307	$	54,296		$	56,254	$	55,660	$	59,780	58,896
Income from equity affiliates	1,815		1,274		2,091		1,709			1,567		2,227		1,882		$	1,687	1,824		1,635		1,784		2,284			1,815		1,274		2,091		$	1,709
Other income	2,483		1,110		737		100			391		944		395		242		384		265		278		238			2,483		1,110		737		100
Total Revenues and Other Income	60,552		58,044		62,608		60,705			59,985		64,432		68,948		60,341		56,158		58,503		57,369		56,818			60,552		58,044		62,608		60,705
Costs and Other Deductions
Purchased crude oil and products	33,959		33,982		36,772		36,053			36,363		37,600		40,759		35,201		32,691		34,822		34,273		32,910			33,959		33,982		36,772		36,053
Operating expenses	6,273		5,694		5,420		5,183			5,948		5,378		5,260		5,063		6,521		6,066		6,278		5,762			6,273		5,694		5,420		5,183
Selling, general and administrative expenses	1,182		1,352		1,250		940			1,330		1,115		1,200		1,100		1,176		1,197		1,139		998			1,182		1,352		1,250		940
Exploration expenses	357		475		493		403			386		240		422		168		726		559		329		247			357		475		493		403
Depreciation, depletion and amortization	3,554		3,370		3,284		3,205			3,313		3,215		3,257		3,126		3,635		3,658		3,412		3,481			3,554		3,370		3,284		3,205
Taxes other than on income¹	3,251		3,239		3,034		2,852			2,680		3,544		4,843		4,561		3,211		3,366		3,349		3,137			3,251		3,239		3,034		2,852
Interest and debt expense	—		—		—		—			–		–		–		–
Total Costs and Other Deductions	48,576		48,112		50,253		48,636			50,020		51,092		55,741		49,219		47,960		49,668		48,780		46,535			48,576		48,112		50,253		48,636
Income Before Income Tax Expense	11,976		9,932		12,355		12,069			9,965		13,340		13,207		11,122		8,198		8,835		8,589		10,283			11,976		9,932		12,355		12,069
Income Tax Expense	4,679		4,624		5,123		5,570			4,813		5,483		5,447		4,883		3,240		3,839		3,185		4,044			4,679		4,624		5,123		5,570
Net Income	$	7,297	$	5,308	$	7,232	$	6,499		$	5,152	$	7,857	$	7,760	$	6,239	$	4,958	$	4,996	$	5,404	$	6,239		$	7,297	$	5,308	$	7,232	$	6,499
Less: Net income attributable to noncontrolling interests	52		55		22		28			29		28		28		28		28		46		39		61			52		55		22		28
Net Income Attributable to Chevron Corporation	$	7,245	$	5,253	$	7,210	$	6,471		$	5,123	$	7,829	$	7,732	$	6,211	$	4,930	$	4,950	$	5,365	$	6,178		$	7,245	$	5,253	$	7,210	$	6,471
Per Share of Common Stock
Net Income Attributable to Chevron Corporation
– Basic	$	3.73	$	2.71	$	3.68	$	3.30		$	2.61	$	3.94	$	3.88	$	3.11	$2.60		$2.58		$2.80		$3.20			$3.73		$2.71		$3.68		$3.30
– Diluted	$	3.70	$	2.69	$	3.66	$	3.27		$	2.58	$	3.92	$	3.85	$	3.09	$2.57		$2.57		$2.77		$3.18			$3.70		$2.69		$3.66		$3.27
Dividends	$	0.90	$	0.90	$	0.90	$	0.81		$	0.81	$	0.78	$	0.78	$	0.72	$1.00		$1.00		$1.00		$0.90			$0.90		$0.90		$0.90		$0.81
Common Stock Price Range – High²	$	118.38	$	118.53	$	108.79	$	112.28		$	110.01	$	109.75	$	109.94	$	109.65	$125.65		$127.83		$127.40		$121.56			$118.38		$118.53		$108.79		$112.28
– Low²	$	100.66	$	103.29	$	95.73	$	102.08		$	86.68	$	87.30	$	97.00	$	90.12	$114.44		$117.22		$114.12		$108.74			$100.66		$103.29		$95.73		$102.08
¹ Includes excise, value-added and similar taxes:	$	2,131	$	2,163	$	1,929	$	1,787		$	1,713	$	1,974	$	2,264	$	2,134	$	2,128	$	2,223	$	2,108	$	2,033		$	2,131	$	2,163	$	1,929	$	1,787
² Intraday price.
The company’s common stock is listed on the New York Stock Exchange (trading symbol: CVX). As of February 11, 2013, stockholders of record numbered approximately 168,000. There are no restrictions on the company’s ability to pay dividends.
The company’s common stock is listed on the New York Stock Exchange (trading symbol: CVX). As of February 10, 2014, stockholders of record numbered approximately 160,000. There are no restrictions on the company’s ability to pay dividends.																		The company’s common stock is listed on the New York Stock Exchange (trading symbol: CVX). As of February 10, 2014, stockholders of record numbered approximately 160,000. There are no restrictions on the company’s ability to pay dividends.

~~FS-20~~FS-19



Management’s Responsibility for Financial Statements

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

Management’s Report on Internal Control Over Financial Reporting
The company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). The company’s management, including the Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of the company’s internal control over financial reporting based on the Internal Control – Integrated Framework (1992)issued by the Committee of Sponsoring Organizations of the Treadway ~~Commission.~~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, ~~2012.~~2013. On May 14, 2013, COSO published an updated Internal Control - Integrated Framework (2013) and related illustrative documents. As of December 31, 2013, the company is utilizing the original framework published in 1992. The transition period for adoption of the updated framework ends December 15, 2014. The effectiveness of the company’s internal control over financial reporting as of December 31, ~~2012,~~2013, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report included herein.



John S. Watson	Patricia E. Yarrington	Matthew J. Foehr
Chairman of the Board	Vice President	Vice President
and Chief Executive Officer	and Chief Financial Officer	and Comptroller

February ~~22, 2013~~21, 2014

~~FS-21~~FS-20

Report of Independent Registered Public Accounting Firm



To the Stockholders and the Board of Directors of Chevron Corporation:	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.
In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of income, comprehensive income, equity and of cash flows present fairly, in all material respects, the financial position of Chevron Corporation and its subsidiaries at December 31, ~~2012,~~2013, and December 31, ~~2011,~~2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, ~~2012,~~2013, 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, ~~2012,~~2013, based on criteria established in Internal Control – Integrated Framework (1992)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,


	San Francisco, California
	February ~~22, 2013~~21, 2014

~~FS-22~~FS-21

Consolidated Statement of Income

Millions of dollars, except per-share amounts


	Year ended December 31						Year ended December 31
	2012		2011		2010		2013		2012		2011
Revenues and Other Income
Sales and other operating revenues*	$	230,590	$	244,371	$	198,198	$	220,156	$	230,590	$	244,371
Income from equity affiliates	6,889		7,363		5,637		7,527		6,889		7,363
Other income	4,430		1,972		1,093		1,165		4,430		1,972
Total Revenues and Other Income	241,909		253,706		204,928		228,848		241,909		253,706
Costs and Other Deductions
Purchased crude oil and products	140,766		149,923		116,467		134,696		140,766		149,923
Operating expenses	22,570		21,649		19,188		24,627		22,570		21,649
Selling, general and administrative expenses	4,724		4,745		4,767		4,510		4,724		4,745
Exploration expenses	1,728		1,216		1,147		1,861		1,728		1,216
Depreciation, depletion and amortization	13,413		12,911		13,063		14,186		13,413		12,911
Taxes other than on income*	12,376		15,628		18,191		13,063		12,376		15,628
Interest and debt expense	—		—		50
Total Costs and Other Deductions	195,577		206,072		172,873		192,943		195,577		206,072
Income Before Income Tax Expense	46,332		47,634		32,055		35,905		46,332		47,634
Income Tax Expense	19,996		20,626		12,919		14,308		19,996		20,626
Net Income	26,336		27,008		19,136		21,597		26,336		27,008
Less: Net income attributable to noncontrolling interests	157		113		112		174		157		113
Net Income Attributable to Chevron Corporation	$	26,179	$	26,895	$	19,024	$	21,423	$	26,179	$	26,895
Per Share of Common Stock
Net Income Attributable to Chevron Corporation
– Basic	$	13.42	$	13.54	$	9.53	$	11.18	$	13.42	$	13.54
– Diluted	$	13.32	$	13.44	$	9.48	$	11.09	$	13.32	$	13.44


*Includes excise, value-added and similar taxes.	$	8,010	$	8,085	$	8,591	$	8,492	$	8,010	$	8,085
See accompanying Notes to the Consolidated Financial Statements.

~~FS-23~~FS-22

Consolidated Statement of Comprehensive Income
Millions of dollars


	Year ended December 31									Year ended December 31
	2012			2011			2010			2013			2012			2011
Net Income	$	26,336		$	27,008		$	19,136		$	21,597		$	26,336		$	27,008
Currency translation adjustment
Unrealized net change arising during period	23			17			6			42			23			17
Unrealized holding gain (loss) on securities
Net gain (loss) arising during period	1			(11		)	(4		)
Unrealized holding (loss) gain on securities
Net (loss) gain arising during period										(7		)	1			(11		)
Derivatives
Net derivatives gain on hedge transactions	20			20			25
Net derivatives (loss) gain on hedge transactions										(111		)	20			20
Reclassification to net income of net realized (gain) loss	(14		)	9			5			(1		)	(14		)	9
Income taxes on derivatives transactions	(3		)	(10		)	(10		)	39			(3		)	(10		)
Total	3			19			20			(73		)	3			19
Defined benefit plans
Actuarial loss
Amortization to net income of net actuarial loss	920			773			635
Actuarial loss arising during period	(1,180		)	(3,250		)	(857		)
Prior service cost
Actuarial gain (loss)
Amortization to net income of net actuarial loss and settlements										866			920			773
Actuarial gain (loss) arising during period										3,379			(1,180		)	(3,250		)
Prior service credits (cost)
Amortization to net income of net prior service credits	(61		)	(26		)	(61		)	(27		)	(61		)	(26		)
Prior service cost arising during period	(142		)	(27		)	(12		)
Prior service credits (cost) arising during period										60			(142		)	(27		)
Defined benefit plans sponsored by equity affiliates	(54		)	(81		)	(12		)	164			(54		)	(81		)
Income taxes on defined benefit plans	143			1,030			140			(1,614		)	143			1,030
Total	(374		)	(1,581		)	(167		)	2,828			(374		)	(1,581		)
Other Comprehensive Loss, Net of Tax	(347		)	(1,556		)	(145		)
Other Comprehensive Gain (Loss), Net of Tax										2,790			(347		)	(1,556		)
Comprehensive Income	25,989			25,452			18,991			24,387			25,989			25,452
Comprehensive income attributable to noncontrolling interests	(157		)	(113		)	(112		)	(174		)	(157		)	(113		)
Comprehensive Income Attributable to Chevron Corporation	$	25,832		$	25,339		$	18,879		$	24,213		$	25,832		$	25,339
See accompanying Notes to the Consolidated Financial Statements.	See accompanying Notes to the Consolidated Financial Statements.									See accompanying Notes to the Consolidated Financial Statements.

~~FS-24~~FS-23

Consolidated Balance Sheet
Millions of dollars, except per-share amounts


	At December 31						At December 31
	2012			2011			2013			2012
Assets
Cash and cash equivalents	$	20,939		$	15,864		$	16,245		$	20,939
Time deposits	708			3,958			8			708
Marketable securities	266			249			263			266
Accounts and notes receivable (less allowance: 2012 - $80; 2011 - $98)	20,997			21,793
Accounts and notes receivable (less allowance: 2013 - $62; 2012 - $80)							21,622			20,997
Inventories:
Crude oil and petroleum products	3,923			3,420			3,879			3,923
Chemicals	475			502			491			475
Materials, supplies and other	1,746			1,621			2,010			1,746
Total inventories	6,144			5,543			6,380			6,144
Prepaid expenses and other current assets	6,666			5,827			5,732			6,666
Total Current Assets	55,720			53,234			50,250			55,720
Long-term receivables, net	3,053			2,233			2,833			3,053
Investments and advances	23,718			22,868			25,502			23,718
Properties, plant and equipment, at cost	263,481			233,432			296,433			263,481
Less: Accumulated depreciation, depletion and amortization	122,133			110,824			131,604			122,133
Properties, plant and equipment, net	141,348			122,608			164,829			141,348
Deferred charges and other assets	4,503			3,889			5,120			4,503
Goodwill	4,640			4,642			4,639			4,640
Assets held for sale							580			—
Total Assets	$	232,982		$	209,474		$	253,753		$	232,982
Liabilities and Equity
Short-term debt	$	127		$	340		$	374		$	127
Accounts payable	22,776			22,147			22,815			22,776
Accrued liabilities	5,738			5,287			5,402			5,738
Federal and other taxes on income	4,341			4,584			3,092			4,341
Other taxes payable	1,230			1,242			1,335			1,230
Total Current Liabilities	34,212			33,600			33,018			34,212
Long-term debt	11,966			9,684			19,960			11,966
Capital lease obligations	99			128			97			99
Deferred credits and other noncurrent obligations	21,502			19,181			22,982			21,502
Noncurrent deferred income taxes	17,672			15,544			21,301			17,672
Reserves for employee benefit plans	9,699			9,156
Noncurrent employee benefit plans							5,968			9,699
Total Liabilities	95,150			87,293			103,326			95,150
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, 2012 and 2011)	1,832			1,832
Common stock (authorized 6,000,000,000 shares; $0.75 par value; 2,442,676,580 shares issued at December 31, 2013 and 2012)							1,832			1,832
Capital in excess of par value	15,497			15,156			15,713			15,497
Retained earnings	159,730			140,399			173,677			159,730
Accumulated other comprehensive loss	(6,369		)	(6,022		)	(3,579		)	(6,369		)
Deferred compensation and benefit plan trust	(282		)	(298		)	(240		)	(282		)
Treasury stock, at cost (2012 - 495,978,691 shares; 2011 - 461,509,656 shares)	(33,884		)	(29,685		)
Treasury stock, at cost (2013 - 529,073,512 shares; 2012 - 495,978,691 shares)							(38,290		)	(33,884		)
Total Chevron Corporation Stockholders' Equity	136,524			121,382			149,113			136,524
Noncontrolling interests	1,308			799			1,314			1,308
Total Equity	137,832			122,181			150,427			137,832
Total Liabilities and Equity	$	232,982		$	209,474		$	253,753		$	232,982

See accompanying Notes to the Consolidated Financial Statements.

~~FS-25~~FS-24

Consolidated Statement of Cash Flows
Millions of dollars


	Year ended December 31									Year ended December 31
	2012			2011			2010			2013			2012			2011
Operating Activities
Net Income	$	26,336		$	27,008		$	19,136		$	21,597		$	26,336		$	27,008
Adjustments
Depreciation, depletion and amortization	13,413			12,911			13,063			14,186			13,413			12,911
Dry hole expense	555			377			496			683			555			377
Distributions less than income from equity affiliates	(1,351		)	(570		)	(501		)	(1,178		)	(1,351		)	(570		)
Net before-tax gains on asset retirements and sales	(4,089		)	(1,495		)	(1,004		)	(639		)	(4,089		)	(1,495		)
Net foreign currency effects	207			(103		)	251			(103		)	207			(103		)
Deferred income tax provision	2,015			1,589			559			1,876			2,015			1,589
Net decrease in operating working capital	363			2,318			76
Increase in long-term receivables	(169		)	(150		)	(12		)
Decrease in other deferred charges	1,047			341			48
Net (increase) decrease in operating working capital										(1,331		)	363			2,318
Decrease (increase) in long-term receivables										183			(169		)	(150		)
(Increase) decrease in other deferred charges										(321		)	1,047			341
Cash contributions to employee pension plans	(1,228		)	(1,467		)	(1,450		)	(1,194		)	(1,228		)	(1,467		)
Other	1,713			336			692			1,243			1,713			336
Net Cash Provided by Operating Activities	38,812			41,095			31,354			35,002			38,812			41,095
Investing Activities
Acquisition of Atlas Energy	—			(3,009		)	—			—			—			(3,009		)
Advance to Atlas Energy	—			(403		)	—			—			—			(403		)
Capital expenditures	(30,938		)	(26,500		)	(19,612		)	(37,985		)	(30,938		)	(26,500		)
Proceeds and deposits related to asset sales	2,777			3,517			1,995			1,143			2,777			3,517
Net sales (purchases) of time deposits	3,250			(1,104		)	(2,855		)	700			3,250			(1,104		)
Net purchases of marketable securities	(3		)	(74		)	(49		)
Net sales (purchases) of marketable securities										3			(3		)	(74		)
Repayment of loans by equity affiliates	328			339			338			314			328			339
Net purchases of other short-term investments	(210		)	(255		)	(732		)
Net sales (purchases) of other short-term investments										216			(210		)	(255		)
Net Cash Used for Investing Activities	(24,796		)	(27,489		)	(20,915		)	(35,609		)	(24,796		)	(27,489		)
Financing Activities
Net borrowings (payments) of short-term obligations	264			23			(212		)
Net borrowings of short-term obligations										2,378			264			23
Proceeds from issuances of long-term debt	4,007			377			1,250			6,000			4,007			377
Repayments of long-term debt and other financing obligations	(2,224		)	(2,769		)	(156		)	(132		)	(2,224		)	(2,769		)
Cash dividends - common stock	(6,844		)	(6,136		)	(5,669		)	(7,474		)	(6,844		)	(6,136		)
Distributions to noncontrolling interests	(41		)	(71		)	(72		)	(99		)	(41		)	(71		)
Net purchases of treasury shares	(4,142		)	(3,193		)	(306		)	(4,494		)	(4,142		)	(3,193		)
Net Cash Used for Financing Activities	(8,980		)	(11,769		)	(5,165		)	(3,821		)	(8,980		)	(11,769		)
Effect of Exchange Rate Changes on Cash and Cash Equivalents	39			(33		)	70			(266		)	39			(33		)
Net Change in Cash and Cash Equivalents	5,075			1,804			5,344			(4,694		)	5,075			1,804
Cash and Cash Equivalents at January 1	15,864			14,060			8,716			20,939			15,864			14,060
Cash and Cash Equivalents at December 31	$	20,939		$	15,864		$	14,060		$	16,245		$	20,939		$	15,864
See accompanying Notes to the Consolidated Financial Statements.

~~FS-26~~FS-25

Consolidated Statement of Equity

Shares in thousands; amounts in millions of dollars


	2012					2011					2010					2013					2012					2011
	Shares		Amount			Shares		Amount			Shares		Amount			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		2,442,677		$	1,832		2,442,677		$	1,832		2,442,677		$	1,832
Capital in Excess of Par
Balance at January 1			$	15,156				$	14,796				$	14,631				$	15,497				$	15,156				$	14,796
Treasury stock transactions			341					360					165					216					341					360
Balance at December 31			$	15,497				$	15,156				$	14,796				$	15,713				$	15,497				$	15,156
Retained Earnings
Balance at January 1			$	140,399				$	119,641				$	106,289				$	159,730				$	140,399				$	119,641
Net income attributable to Chevron Corporation	Net income attributable to Chevron Corporation		26,179					26,895					19,024			Net income attributable to Chevron Corporation		21,423					26,179					26,895
Cash dividends on common stock			(6,844		)			(6,136		)			(5,669		)			(7,474		)			(6,844		)			(6,136		)
Stock dividends			(3		)			(3		)			(5		)			(3		)			(3		)			(3		)
Tax (charge) benefit from dividends paid on unallocated ESOP shares and other			(1)					2					2					1					(1		)			2
Balance at December 31			$	159,730				$	140,399				$	119,641				$	173,677				$	159,730				$	140,399
Accumulated Other Comprehensive Loss
Currency translation adjustment
Balance at January 1			$	(88	)			$	(105	)			$	(111	)			$	(65	)			$	(88	)			$	(105	)
Change during year			23					17					6					42					23					17
Balance at December 31			$	(65	)			$	(88	)			$	(105	)			$	(23	)			$	(65	)			$	(88	)
Pension and other postretirement benefit plans
Balance at January 1			$	(6,056	)			$	(4,475	)			$	(4,308	)
Change during year			(374		)			(1,581		)			(167		)
Balance at December 31			$	(6,430	)			$	(6,056	)			$	(4,475	)
Unrealized net holding gain on securities
Unrealized net holding (loss) gain on securities
Balance at January 1			$	—				$	11				$	15				$	1				$	—				$	11
Change during year			1					(11		)			(4		)			(7		)			1					(11		)
Balance at December 31			$	1				$	—				$	11				$	(6	)			$	1				$	—
Net derivatives gain (loss) on hedge transactions	Net derivatives gain (loss) on hedge transactions															Net derivatives gain (loss) on hedge transactions
Balance at January 1																		$	125				$	122				$	103
Change during year																		(73		)			3					19
Balance at December 31																		$	52				$	125				$	122
Pension and other postretirement benefit plans
Balance at January 1			$	122				$	103				$	83				$	(6,430	)			$	(6,056	)			$	(4,475	)
Change during year			3					19					20					2,828					(374		)			(1,581		)
Balance at December 31			$	125				$	122				$	103				$	(3,602	)			$	(6,430	)			$	(6,056	)
Balance at December 31			$	(6,369	)			$	(6,022	)			$	(4,466	)			$	(3,579	)			$	(6,369	)			$	(6,022	)
Deferred Compensation and Benefit Plan Trust	Deferred Compensation and Benefit Plan Trust															Deferred Compensation and Benefit Plan Trust
Deferred Compensation
Balance at January 1			$	(58	)			$	(71	)			$	(109	)			$	(42	)			$	(58	)			$	(71	)
Net reduction of ESOP debt and other			16					13					38					42					16					13
Balance at December 31			$	(42	)			$	(58	)			$	(71	)			$	—				$	(42	)			$	(58	)
Benefit Plan Trust (Common Stock)	14,168		(240		)	14,168		(240		)	14,168		(240		)	14,168		(240		)	14,168		(240		)	14,168		(240		)
Balance at December 31	14,168		$	(282	)	14,168		$	(298	)	14,168		$	(311	)	14,168		$	(240	)	14,168		$	(282	)	14,168		$	(298	)
Treasury Stock at Cost
Balance at January 1	461,510		$	(29,685	)	435,196		$	(26,411	)	434,955		$	(26,168	)	495,979		$	(33,884	)	461,510		$	(29,685	)	435,196		$	(26,411	)
Purchases	46,669		(5,004		)	42,424		(4,262		)	9,091		(775		)	41,676		(5,004		)	46,669		(5,004		)	42,424		(4,262		)
Issuances - mainly employee benefit plans	(12,200	)	805			(16,110	)	988			(8,850	)	532			(8,581	)	598			(12,200	)	805			(16,110	)	988
Balance at December 31	495,979		$	(33,884	)	461,510		$	(29,685	)	435,196		$	(26,411	)	529,074		$	(38,290	)	495,979		$	(33,884	)	461,510		$	(29,685	)
Total Chevron Corporation Stockholders' Equity at December 31			$	136,524				$	121,382				$	105,081				$	149,113				$	136,524				$	121,382
Noncontrolling Interests			$	1,308				$	799				$	730				$	1,314				$	1,308				$	799
Total Equity			$	137,832				$	122,181				$	105,811				$	150,427				$	137,832				$	122,181
See accompanying Notes to the Consolidated Financial Statements.	See accompanying Notes to the Consolidated Financial Statements.															See accompanying Notes to the Consolidated Financial Statements.

~~FS-27~~FS-26

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Note 1

Summary of Significant Accounting Policies

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

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

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

Investments are assessed for possible impairment when events indicate that the fair value of the investment may be below the company’s carrying value. When such a condition is deemed to be other than temporary, the carrying value of the investment is written down to its fair value, and the amount of the write-down is included in net income. In making the determination as to whether a decline is other than temporary, the company considers such factors as the duration and extent of the decline, the investee’s financial performance, and the company’s ability and intention to retain its investment for a period that will be sufficient to

allow for any anticipated

~~allow for any anticipated~~ recovery in the investment’s market value. The new cost basis of investments in these equity investees is not changed for subsequent recoveries in fair value.

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

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

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

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

~~FS-28~~FS-27



Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Note 1 Summary of Significant Accounting Policies - Continued

Properties, Plant and Equipment The successful efforts method is used for crude oil and natural gas exploration and production activities. All costs for development wells, related plant and equipment, proved mineral interests in crude oil and natural gas properties, and related asset retirement obligation (ARO) assets are capitalized. Costs of exploratory wells are capitalized pending determination of whether the wells found proved reserves. Costs of wells that are assigned proved reserves remain capitalized. Costs also are capitalized for exploratory wells that have found crude oil and natural gas reserves even if the reserves cannot be classified as proved when the drilling is completed, provided the exploratory well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project. All other exploratory wells and costs are expensed. Refer to Note ~~18,~~19, beginning on page ~~FS-47,~~FS-46, for additional discussion of accounting for suspended exploratory well costs.

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

Long-lived assets that are held for sale are evaluated for possible impairment by comparing the carrying value of the asset with its fair value less the cost to sell. If the net book value exceeds the fair value less cost to sell, the asset is considered impaired and adjusted to the lower value. Refer to Note 8,9, beginning on page ~~FS-33,~~FS-32, 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 ~~associ-~~

~~ated~~associated with the retirement of a long-lived asset and the amount can be reasonably estimated. Refer also to Note ~~23,~~24, on page ~~FS-58,~~FS-56, relating to AROs.

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

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

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

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

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

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

Liabilities related to future remediation costs are recorded when environmental assessments or cleanups or both are probable and the costs can be reasonably estimated. For the company’s U.S. and Canadian marketing facilities, the accrual is based in part on the probability that a future remediation commitment will be required. For crude oil, natural gas and

~~FS-29~~



~~Notes to the Consolidated Financial Statements~~ ~~Millions of dollars, except per-share amounts~~ ~~Note 1~~ ~~Summary of Significant Accounting Policies - Continued~~

mineral-producing properties, a liability for an ARO is made in accordance with accounting standards for asset retirement and environmental obligations. Refer to Note ~~23,~~24, on page ~~FS-58,~~FS-56, for a discussion of the company’s AROs.

FS-28

Note 1 Summary of Significant Accounting Policies - Continued

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

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

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

Revenue Recognition Revenues associated with sales of crude oil, natural gas, coal, petroleum and chemicals products, and all other sources are recorded when title passes to the customer, net of royalties, discounts and allowances, as applicable. Revenues

from natural gas production from properties in which Chevron

has an interest with other producers are generally recognized 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.~~FS-22. Purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another (including buy/sell arrangements) are combined and recorded on a net basis and reported in “Purchased crude oil and products” on the Consolidated Statement of Income.

Stock Options and Other Share-Based Compensation The company issues stock options and other share-based compensation to ~~its employees and accounts for these transactions under the accounting standards for share-based compensation (ASC 718).~~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, 2013, are reflected in the table below.

Changes in Accumulated Other Comprehensive Losses by Component ¹



	Year Ended December 31, 2013
	Currency Translation Adjustment			Unrealized Holding Gains (Losses) on Securities			Derivatives			Defined Benefit Plans			Total
Balance at January 1	$	(65	)	$	1		$	125		$	(6,430	)	$	(6,369	)
Components of Other Comprehensive Income (Loss):
Before Reclassifications	42			(7		)	(72		)	2,302			2,265
Reclassifications ²	—			—			(1		)	526			525
Net Other Comprehensive Income (Loss)	42			(7		)	(73		)	2,828			2,790
Balance at December 31	$	(23	)	$	(6	)	$	52		$	(3,602	)	$	(3,579	)

¹All amounts are net of tax.

²Refer to Note 21, Employee Benefits for reclassified components totaling $839 that are included in employee benefit costs for the year ending December 31, 2013. Related income taxes for the same period, totaling $313, are reflected in Income Tax Expense on the Consolidated Statement of Income. All other reclassified amounts were insignificant.

FS-29

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Note 3 Noncontrolling Interests

Note 23

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.”

Activity for the equity attributable to noncontrolling interests for ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011 is as follows:


	2012			2011			2010			2013			2012			2011
Balance at January 1	$	799		$	730		$	647		$	1,308		$	799		$	730
Net income	157			113			112			174			157			113
Distributions to noncontrolling interests	(41		)	(71		)	(72		)	(99		)	(41		)	(71		)
Other changes, net*	393			27			43			(69		)	393			27
Balance at December 31	$	1,308		$	799		$	730		$	1,314		$	1,308		$	799

* Includes components of comprehensive income, which are disclosed separately in the Consolidated Statement of Comprehensive Income.

~~FS-30~~

Note 34

Information Relating to the Consolidated Statement of Cash Flows



	Year ended December 31
	2013			2012			2011
Net (increase) decrease in operating working capital was composed of the following:
(Increase) decrease in accounts and notes receivable	$	(1,101	)	$	1,153		$	(2,156	)
Increase in inventories	(237		)	(233		)	(404		)
Decrease (increase) in prepaid expenses and other current assets	834			(471		)	(853		)
Increase in accounts payable and accrued liabilities	160			544			3,839
(Decrease) increase in income and other taxes payable	(987		)	(630		)	1,892
Net (increase) decrease in operating working capital	$	(1,331	)	$	363		$	2,318
Net cash provided by operating activities includes the following cash payments for income taxes:
Income taxes	$	12,898		$	17,334		$	17,374
Net sales (purchases) of marketable securities consisted of the following gross amounts:
Marketable securities purchased	$	(7	)	$	(35	)	$	(112	)
Marketable securities sold	10			32			38
Net sales (purchases) of marketable securities	$	3		$	(3	)	$	(74	)
Net sales (purchases) of time deposits consisted of the following gross amounts:
Time deposits purchased	$	(2,317	)	$	(717	)	$	(6,439	)
Time deposits matured	3,017			3,967			5,335
Net sales (purchases) of time deposits	$	700		$	3,250		$	(1,104	)

Year ended December 31
2012
2011
2010
Net decrease (increase) in operating working capital was composed of the following:
Decrease (increase) in accounts and
notes receivable $ 1,153
$ (2,156 ) $ (2,767 )
(Increase) decrease in inventories (233 ) (404 ) 15
Increase in prepaid expenses and other current assets (471 ) (853 ) (542 )
Increase in accounts payable and accrued liabilities 544
3,839
3,049
(Decrease) increase in income and other taxes payable (630 ) 1,892
321
Net decrease in operating working capital $ 363
$ 2,318
$ 76
Net cash provided by operating activities includes the following cash payments for interest and income taxes:
Interest paid on debt
(net of capitalized interest) $ —
$ —
$ 34
Income taxes $ 17,334
$ 17,374
$ 11,749
Net sales of marketable securities consisted of the following gross amounts:
Marketable securities purchased $ (35 ) $ (112 ) $ (90 )
Marketable securities sold 32
38
41
Net purchases of marketable securities $ (3 ) $ (74 ) $ (49 )
Net sales (purchases) of time deposits consisted of the following gross amounts:
Time deposits purchased $ (717 ) $ (6,439 ) $ (5,060 )
Time deposits matured 3,967
5,335
2,205
Net sales (purchases) of time deposits $ 3,250
$ (1,104 ) $ (2,855 )

~~In accordance with accounting standards for cash-flow classifications for stock options (ASC 718), the~~The “Net (increase) decrease in operating working capital” includes reductions of $9879, $~~121~~98 and $67121 for excess income tax benefits associated with stock options exercised during ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011, respectively. These amounts are offset by an equal amount in “Net purchases of treasury shares.” "Other" includes changes in postretirement benefits obligations and other long-term liabilities.

In February 2011, the company acquired Atlas Energy, Inc. (Atlas) for the aggregate purchase price of approximately $4,500. The purchase price included assumption of debt and certain payments noted below. The “Acquisition of Atlas Energy” reflects the ~~$3,009~~ of$3,009 cash paid for all the common shares of ~~Atlas in February 2011.~~Atlas. An “Advance to Atlas Energy” of ~~$403~~$403 was made to facilitate the purchase of a 49 percent interest in Laurel Mountain Midstream LLC on the day of closing. ~~The “Net decrease (increase) in operating working capital” includes~~ ~~$184~~ ~~for payments made in connection with Atlas equity awards subsequent to the acquisition. Refer to Note 26, beginning on page FS-60 for additional discussion of the Atlas acquisition.~~

The “Repayments of long-term debt and other financing obligations” in 2011 includes $761 for repayment of Atlas debt and ~~$271~~$271 for payoff of the Atlas revolving credit facility. The “Net (increase) decrease in operating working capital” includes $184 for payments made in connection with Atlas equity awards subsequent to the acquisition. The remaining impacts of the acquisition did not have a material impact on the Consolidated Statement of Cash Flows.

The “Net purchases of treasury shares” represents the cost of common shares acquired less the cost of shares issued for share-based compensation plans. Purchases totaled $5,004, $~~4,262~~5,004 and $~~775~~4,262 in ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011, respectively. In2013, 2012 and 2011, the company purchased 41.6 million, 46.6 million and 42.3 million common shares for$5,000, $5,000 and $4,250 under its ongoing share repurchase program, respectively.

In 2013, 2012 and 2011, “Net ~~purchases~~sales (purchases) of other short-term investments” ~~consist~~generally consisted of restricted cash associated with tax payments, upstream abandonment activities, funds held in escrow for an asset ~~acquisition~~acquisitions and capital investment projects 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 company issued $374 ~~and~~ ~~$1,250~~in 2011 ~~and~~ ~~2010, respectively,~~ of tax exempt bonds as a source of funds for U.S. refinery projects, which is included in “Proceeds from issuance of long-term debt.”

The Consolidated Statement of Cash Flows excludes changes to the Consolidated Balance Sheet that did not affect cash. The 2012 period excludes the effects of ~~$800~~$800 of proceeds to be received in future periods for the sale of an equity interest in the Wheatstone ~~Project.~~Project, of which $82 was received in 2013. "Capital expenditures" in the 2012 period excludes a ~~$1,850~~$1,850 increase in "Properties, plant and equipment" related to an upstream asset exchange in Australia. Refer also to Note ~~23,~~24, on page ~~FS-58,~~FS-56, 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, ~~2012~~2013.

~~FS-31~~FS-30

~~Notes to the Consolidated Financial Statements~~

~~Millions of dollars, except per-share amounts~~

Note 34 Information Relating to the Consolidated Statement of Cash Flows - Continued

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									Year ended December 31
	2012			2011			2010			2013			2012			2011
Additions to properties, plant and equipment ^*	$	29,526		$	25,440		$	18,474		$	36,550		$	29,526		$	25,440
Additions to investments	1,042			900			861			934			1,042			900
Current-year dry hole expenditures	475			332			414			594			475			332
Payments for other liabilities and assets, net	(105		)	(172		)	(137		)	(93		)	(105		)	(172		)
Capital expenditures	30,938			26,500			19,612			37,985			30,938			26,500
Expensed exploration expenditures	1,173			839			651			1,178			1,173			839
Assets acquired through capital lease obligations and other financing obligations	1			32			104			16			1			32
Capital and exploratory expenditures, excluding equity affiliates	32,112			27,371			20,367			39,179			32,112			27,371
Company's share of expenditures by equity affiliates	2,117			1,695			1,388			2,698			2,117			1,695
Capital and exploratory expenditures, including equity affiliates	$	34,229		$	29,066		$	21,755		$	41,877		$	34,229		$	29,066

* Excludes noncash additions of $1,661 in 2013, $4,569 in 2012, and $945 in 2011 ~~and~~ ~~$2,753~~ in ~~2010~~.

Note 45

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.

During 2012, Chevron implemented legal reorganizations in which certain Chevron subsidiaries transferred assets to or under CUSA. The summarized financial information for CUSA and its consolidated subsidiaries presented in the following table ~~below~~ gives retroactive effect to the reorganizations as if they had occurred on January 1, ~~2010.~~2011. However, the financial information in the following table may not reflect the financial position and operating results in the periods presented if the reorganization had occurred on that date.

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


	Year ended December 31						Year ended December 31
	2012		2011		2010		2013		2012		2011
Sales and other operating revenues	$	183,215	$	187,929	$	143,352	$	174,318	$	183,215	$	187,929
Total costs and other deductions	175,009		178,510		137,964		169,984		175,009		178,510
Net income attributable to CUSA	6,216		6,898		4,154		3,714		6,216		6,898


	At December 31				At December 31
	2012		2011		2013		2012
Current assets	$	18,983	$	34,490	$	17,626	$	18,983
Other assets	52,082		47,556		57,288		52,082
Current liabilities	18,161		19,081		17,486		18,161
Other liabilities	26,472		26,160		28,119		26,472
Total CUSA net equity	26,432		36,805		29,309		26,432
	—
Memo: Total debt	$	14,482	$	14,763	$	14,482	$	14,482

Note 56

Summarized Financial Data – Chevron Transport Corporation Ltd.

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


	Year ended December 31									Year ended December 31
	2012			2011			2010			2013			2012			2011
Sales and other operating revenues	$	606		$	793		$	885		$	504		$	606		$	793
Total costs and other deductions	745			974			1,008			695			745			974
Net loss attributable to CTC	(135		)	(177		)	(116		)	(191		)	(135		)	(177		)


	At December 31					At December 31
	2012			2011		2013			2012
Current assets	$	199		$	290	$	221		$	199
Other assets	313			228		549			313
Current liabilities	154			114		94			154
Other liabilities	415			346		911			415
Total CTC net (deficit) equity	(57		)	58
Total CTC net deficit						$	(235	)	$	(57	)

There were no restrictions on CTC's ability to pay dividends or make loans or advances at December 31, ~~2012~~2013.

~~FS-32~~FS-31



Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Note 7 Summarized Financial Data – Tengizchevroil LLP

Note 67

Summarized Financial Data – Tengizchevroil LLP

Chevron has a 50 percent equity ownership interest in Tengizchevroil LLP (TCO). Refer to Note ~~11,~~12, on page ~~FS-38,~~FS-37, for a discussion of TCO operations.

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


	Year ended December 31						Year ended December 31
	2012		2011		2010		2013		2012		2011
Sales and other operating revenues	$	23,089	$	25,278	$	17,812	$	25,239	$	23,089	$	25,278
Costs and other deductions	10,064		10,941		8,394		11,173		10,064		10,941
Net income attributable to TCO	9,119		10,039		6,593		9,855		9,119		10,039


	At December 31				At December 31
	2012		2011		2013		2012
Current assets	$	3,251	$	3,477	$	3,598	$	3,251
Other assets	12,020		11,619		12,964		12,020
Current liabilities	2,597		2,995		3,016		2,597
Other liabilities	3,390		3,759		2,761		3,390
Total TCO net equity	$	9,284	$	8,342	$	10,785	$	9,284

Note 78

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				At December 31
	2012		2011		2013		2012
Upstream	$	433	$	585	$	445	$	433
Downstream	316		316		316		316
All Other	—		—		—		—
Total	749		901		761		749
Less: Accumulated amortization	479		568		523		479
Net capitalized leased assets	$	270	$	333	$	238	$	270

Rental expenses incurred for operating leases during ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011 were as follows:


	Year ended December 31						Year ended December 31
	2012		2011		2010		2013		2012		2011
Minimum rentals	$	973	$	892	$	931	$	1,049	$	973	$	892
Contingent rentals	7		11		10		1		7		11
Total	980		903		941		1,050		980		903
Less: Sublease rental income	32		39		41		25		32		39
Net rental expense	$	948	$	864	$	900	$	1,025	$	948	$	864

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, ~~2012~~2013, 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					At December 31
	Operating		Capital			Operating		Capital
	Leases		Leases			Leases		Leases
Year: 2013	$	727	$	45
2014	657		37
Year: 2014						$	798	$	45
2015	618		23			733		32
2016	528		13			594		20
2017	401		12			472		17
2018						306		17
Thereafter	617		59			806		46
Total	$	3,548	$	189		$	3,709	$	177
Less: Amounts representing interest and executory costs			$	(40	)			$	(37	)
Net present values			149					140
Less: Capital lease obligations included in short-term debt			(50		)			(43		)
Long-term capital lease obligations			$	99				$	97

Note 89

Fair Value Measurements

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

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

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

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

~~FS-33~~FS-32



~~Notes to the Consolidated Financial Statements~~ ~~Millions of dollars, except per-share amounts~~ Note 89 Fair Value Measurements - Continued

The ~~table~~tables below ~~shows~~show the fair value hierarchy for assets and liabilities measured at fair value on a recurring and nonrecurring basis at December 31, ~~2012~~2013, and December 31, ~~2011~~2012.

Marketable Securities The company calculates fair value for its marketable securities based on quoted market prices for identical ~~assets and liabilities.~~assets. The fair values reflect the cash that would have been received if the instruments were sold at December 31, ~~2012~~2013.

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

~~The company’s derivative instruments principally include futures, swaps, options and forward contracts for crude oil, natural~~

~~gas and refined products.~~ Derivatives classified as Level 1 include futures, swaps and options contracts traded in active markets such as the New York Mercantile Exchange.

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

Properties, ~~plant~~Plant and ~~equipment~~Equipment The company did not have any material long-lived assets measured at fair value on a nonrecurring basis to report in ~~2012~~2013 or ~~2011~~2012.

Investments and ~~advances~~Advances The company did not have any material investments and advances measured at fair value on a nonrecurring basis to report in ~~2012~~2013 or ~~2011~~2012.

~~Assets and Liabilities Measured at Fair Value on a Recurring Basis~~

At December 31, 2012 At December 31, 2011
Total
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Marketable securities $ 266
$ 266
$ —
$ —
$ 249
$ 249
$ —
$ —
Derivatives 86
21
65
—
208
104
104
—
Total Assets at Fair Value $ 352
$ 287
$ 65
$ —
$ 457
$ 353
$ 104
$ —
Derivatives 149
148
1
—
102
101
1
—
Total Liabilities at Fair Value $ 149
$ 148
$ 1
$ —
$ 102
$ 101
$ 1
$ —

~~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 2012 Total
Level 1
Level 2
Level 3
Year 2011
Properties, plant and
equipment, net (held and used)
$ 84
$ —
$ —
$ 84
$ 213
$ 67
$ —
$ —
$ 67
$ 81
Properties, plant and
equipment, net (held for sale) 16
—
—
16
17
167
—
167
—
54
Investments and advances —
—
—
—
15
—
—
—
—
108
Total Nonrecurring Assets
at Fair Value
$ 100
$ —
$ —
$ 100
$ 245
$ 234
$ —
$ 167
$ 67
$ 243

~~FS-34~~



~~Note 8~~ ~~Fair Value Measurements - Continued~~

Assets and Liabilities Not Required to Be Measured at Fair Value The company holds cash equivalents and bank time deposits in U.S. and non-U.S. portfolios. The instruments classified as cash equivalents are primarily bank time deposits with maturities of 90 days or less and money market funds. “Cash and cash equivalents” had carrying/fair values of $~~20,939~~16,245 and $~~15,864~~20,939 at December 31, ~~2012~~2013, and December 31, ~~2011~~2012, respectively. The instruments held in “Time deposits” are bank time deposits with maturities greater than 90 days, and had carrying/fair values of $~~708~~8 and $~~3,958~~708 at December 31, ~~2012~~2013, and December 31, ~~2011~~2012, 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, ~~2012~~2013.

Assets and Liabilities Measured at Fair Value on a Recurring Basis



	At December 31, 2013								At December 31, 2012
	Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3
Marketable securities	$	263	$	263	$	—	$	—	$	266	$	266	$	—	$	—
Derivatives	28		—		28		—		86		21		65		—
Total Assets at Fair Value	$	291	$	263	$	28	$	—	$	352	$	287	$	65	$	—
Derivatives	89		80		9		—		149		148		1		—
Total Liabilities at Fair Value	$	89	$	80	$	9	$	—	$	149	$	148	$	1	$	—

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 2013		Total		Level 1		Level 2		Level 3		Year 2012
Properties, plant and equipment, net (held and used)	$	102	$	—	$	—	$	102	$	278	$	84	$	—	$	—	$	84	$	213
Properties, plant and equipment, net (held for sale)	69		—		69		—		104		16		—		—		16		17
Investments and advances	38		—		35		3		228		—		—		—		—		15
Total Nonrecurring Assets at Fair Value	$	209	$	—	$	104	$	105	$	610	$	100	$	—	$	—	$	100	$	245

FS-33



Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Note 9 Fair Value Measurements - Continued

"Cash and cash equivalents” do not include investments with a carrying/fair value of $~~1,454~~1,210 and $~~1,240~~1,454 at December 31, ~~2012~~2013, and December 31, ~~2011~~2012, respectively. At December 31, ~~2012~~2013, these investments are classified as Level 1 and include restricted funds related to tax payments and certain upstream abandonment activities ~~funds held in escrow for an asset acquisition and capital investment projects, all of~~ which are reported in “Deferred charges and other assets” on the Consolidated Balance Sheet. Long-term debt of ~~$6,086~~$11,960 and ~~$4,101~~$6,086 at December 31, ~~2012~~2013, and December 31, ~~2011~~2012, had estimated fair values of $~~6,770~~12,267 and $~~4,928~~6,770, respectively. Long-term debt primarily includes corporate issued bonds. The fair value of corporate bonds is $~~5,853~~11,581 and classified as Level 1. The fair value of the other bonds is $~~917~~686 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, ~~2012~~2013 and ~~2011~~2012, were not material.

~~The table on previous page shows the fair value hierarchy for assets and liabilities measured at fair value on a nonrecurring basis at December 31,~~ ~~2012~~ ~~and~~ ~~2011~~.

Note 910

Financial and Derivative Instruments

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

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

The company’s derivative commodity instruments principally include crude oil, natural gas and refined product futures,

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

The company uses 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 ~~to govern derivative contracts with certain counterparties to mitigate credit risk.~~and other master netting arrangements. Depending on the nature of the derivative transactions, bilateral collateral arrangements may also be required. When the company is engaged in more than one outstanding derivative transaction with the same counterparty and also has a legally enforceable netting agreement with that counterparty, the net mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and is a reasonable measure of the company’s credit risk exposure. The company also uses other netting agreements with certain counterparties with which it conducts significant transactions to mitigate credit risk.

Derivative instruments measured at fair value at December 31, ~~2012~~2013, December 31, ~~2011~~2012, and December 31, ~~2010~~2011, and their classification on the Consolidated Balance Sheet and Consolidated Statement of Income are as follows:

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


Type of	Balance Sheet	At December 31		At December 31		Balance Sheet	At December 31		At December 31
Contract	Classification	2012		2011		Classification	2013		2012
Commodity	Accounts and notes receivable, net	$	57	$	133	Accounts and notes receivable, net	$	22	$	57
Commodity	Long-term receivables, net	29		75		Long-term receivables, net	6		29
Total Assets at Fair Value	Total Assets at Fair Value	$	86	$	208	Total Assets at Fair Value	$	28	$	86
Commodity	Accounts payable	$	112	$	36	Accounts payable	$	65	$	112
Commodity	Deferred credits and other noncurrent obligations	37		66		Deferred credits and other noncurrent obligations	24		37
Total Liabilities at Fair Value	Total Liabilities at Fair Value	$	149	$	102	Total Liabilities at Fair Value	$	89	$	149

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


		Gain/(Loss)										Gain/(Loss)
Type of Derivative	Statement of	Year ended December 31									Statement of	Year ended December 31
Contract	Income Classification	2012			2011			2010			Income Classification	2013			2012			2011
Commodity	Sales and other operating revenues	$	(49	)	$	(255	)	$	(98	)	Sales and other operating revenues	$	(108	)	$	(49	)	$	(255	)
Commodity	Purchased crude oil and products	(24		)	15			(36		)	Purchased crude oil and products	(77		)	(24		)	15
Commodity	Other income	6			(2		)	(1		)	Other income	(9		)	6			(2		)
		$	(67	)	$	(242	)	$	(135	)		$	(194	)	$	(67	)	$	(242	)

~~FS-35~~FS-34



~~Notes to the Consolidated Financial Statements~~ ~~Millions of dollars, except per-share amounts~~ Note 910 Financial and Derivative Instruments - Continued

The table below represents gross and net derivative assets and liabilities subject to netting agreements on the Consolidated Balance Sheet at December 31, 2013 and December 31, 2012.

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, 2013	Gross Amount Recognized		Gross Amounts Offset		Net Amounts Presented		Gross Amounts Not Offset		Net Amount
Derivative Assets	$	732	$	704	$	28	$	27	$	1
Derivative Liabilities	$	793	$	704	$	89	$	—	$	89
At December 31, 2012
Derivative Assets	$	749	$	663	$	86	$	64	$	22
Derivative Liabilities	$	812	$	663	$	149	$	5	$	144

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 1011

Operating Segments and Geographic Data

Although each subsidiary of Chevron is responsible for its own affairs, Chevron Corporation manages its investments in these subsidiaries and their affiliates. The investments are grouped into two business segments, Upstream and Downstream, representing the company’s “reportable segments” and “operating ~~segments” as defined in accounting standards for segment reporting (ASC 280).~~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 project. Downstream operations consist primarily of refining of crude oil into petroleum products; marketing of crude oil and refined products; transporting of crude oil and refined products by pipeline, marine vessel, motor equipment and rail car; and manufacturing and marketing of commodity petrochemicals, plastics for industrial uses, and fuel and lubricant additives. All Other activities of the company include

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

The segments are separately managed for investment purposes under a structure that includes “segment managers” who report to the company’s “chief operating decision maker” (CODM) ~~(terms as defined in ASC 280)~~. The CODM is the company’s Executive Committee (EXCOM), a committee of senior officers that includes the Chief Executive Officer, and EXCOM reports to the Board of Directors of Chevron Corporation.

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

~~FS-36~~FS-35



Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Note 1011 Operating Segments and Geographic Data - Continued

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

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

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


	Year ended December 31									Year ended December 31
	2012			2011			2010			2013			2012			2011
Segment Earnings
Upstream
United States	$	5,332		$	6,512		$	4,122		$	4,044		$	5,332		$	6,512
International	18,456			18,274			13,555			16,765			18,456			18,274
Total Upstream	23,788			24,786			17,677			20,809			23,788			24,786
Downstream
United States	2,048			1,506			1,339			787			2,048			1,506
International	2,251			2,085			1,139			1,450			2,251			2,085
Total Downstream	4,299			3,591			2,478			2,237			4,299			3,591
Total Segment Earnings	28,087			28,377			20,155			23,046			28,087			28,377
All Other
Interest expense	—			—			(41		)
Interest income	83			78			70			80			83			78
Other	(1,991		)	(1,560		)	(1,160		)	(1,703		)	(1,991		)	(1,560		)
Net Income Attributable to Chevron Corporation	$	26,179		$	26,895		$	19,024		$	21,423		$	26,179		$	26,895

Segment Assets Segment assets do not include intercompany investments or intercompany receivables. Segment assets at year-end ~~2012~~2013 and ~~2011~~2012 are as follows:


	At December 31				At December 31
	2012		2011		2013		2012
Upstream
United States	$	41,891	$	37,108	$	45,436	$	41,891
International	115,806		98,540		137,096		115,806
Goodwill	4,640		4,642		4,639		4,640
Total Upstream	162,337		140,290		187,171		162,337
Downstream
United States	23,023		22,182		23,829		23,023
International	20,024		20,517		20,268		20,024
Total Downstream	43,047		42,699		44,097		43,047
Total Segment Assets	205,384		182,989		231,268		205,384
All Other*
All Other
United States	7,727		8,824		7,326		7,727
International	19,871		17,661		15,159		19,871
Total All Other	27,598		26,485		22,485		27,598
Total Assets – United States	72,641		68,114		76,591		72,641
Total Assets – International	155,701		136,718		172,523		155,701
Goodwill	4,640		4,642		4,639		4,640
Total Assets	$	232,982	$	209,474	$	253,753	$	232,982


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

Segment Sales and Other Operating Revenues Operating segment sales and other operating revenues, including internal transfers, for the years ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011, are presented in the table that follows. Products are transferred between operating segments at internal product values that approximate market prices.

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

~~FS-37~~FS-36



~~Notes to the Consolidated Financial Statements~~ ~~Millions of dollars, except per-share amounts~~ Note 1011 Operating Segments and Geographic Data - Continued


	Year ended December 31									Year ended December 31
	2012			2011			2010			2013			2012			2011
Upstream
United States	$	6,416		$	9,623		$	10,316		$	8,052		$	6,416		$	9,623
Intersegment	17,229			18,115			13,839			16,865			17,229			18,115
Total United States	23,645			27,738			24,155			24,917			23,645			27,738
International	19,459			20,086			17,300			17,607			19,459			20,086
Intersegment	34,094			35,012			23,834			33,034			34,094			35,012
Total International	53,553			55,098			41,134			50,641			53,553			55,098
Total Upstream	77,198			82,836			65,289			75,558			77,198			82,836
Downstream
United States	83,043			86,793			70,436			80,272			83,043			86,793
Excise and similar taxes	4,665			4,199			4,484			4,792			4,665			4,199
Intersegment	49			86			115			39			49			86
Total United States	87,757			91,078			75,035			85,103			87,757			91,078
International	113,279			119,254			90,922			105,373			113,279			119,254
Excise and similar taxes	3,346			3,886			4,107			3,699			3,346			3,886
Intersegment	80			81			93			859			80			81
Total International	116,705			123,221			95,122			109,931			116,705			123,221
Total Downstream	204,462			214,299			170,157			195,034			204,462			214,299
All Other
United States	378			526			610			358			378			526
Intersegment	1,300			1,072			947			1,524			1,300			1,072
Total United States	1,678			1,598			1,557			1,882			1,678			1,598
International	4			4			23			3			4			4
Intersegment	48			42			39			31			48			42
Total International	52			46			62			34			52			46
Total All Other	1,730			1,644			1,619			1,916			1,730			1,644
Segment Sales and Other Operating Revenues
United States	113,080			120,414			100,747			111,902			113,080			120,414
International	170,310			178,365			136,318			160,606			170,310			178,365
Total Segment Sales and Other Operating Revenues	283,390			298,779			237,065			272,508			283,390			298,779
Elimination of intersegment sales	(52,800		)	(54,408		)	(38,867		)	(52,352		)	(52,800		)	(54,408		)
Total Sales and Other Operating Revenues	$	230,590		$	244,371		$	198,198		$	220,156		$	230,590		$	244,371

Segment Income Taxes Segment income tax expense for the years ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011 is as follows:


	Year ended December 31									Year ended December 31
	2012			2011			2010			2013			2012			2011
Upstream
United States	$	2,820		$	3,701		$	2,285		$	2,333		$	2,820		$	3,701
International	16,554			16,743			10,480			12,470			16,554			16,743
Total Upstream	19,374			20,444			12,765			14,803			19,374			20,444
Downstream
United States	1,051			785			680			364			1,051			785
International	587			416			462			389			587			416
Total Downstream	1,638			1,201			1,142			753			1,638			1,201
All Other	(1,016		)	(1,019		)	(988		)	(1,248		)	(1,016		)	(1,019		)
Total Income Tax Expense	$	19,996		$	20,626		$	12,919		$	14,308		$	19,996		$	20,626

Other Segment Information Additional information for the segmentation of major equity affiliates is contained in Note ~~11 below.~~12. Information related to properties, plant and equipment by segment is contained in Note ~~12,~~13, on page ~~FS-40.~~FS-39.

Note 1112

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	Investments and Advances				Equity in Earnings									Investments and Advances				Equity in Earnings
	At December 31				Year ended December 31									At December 31				Year ended December 31
	2012		2011		2012			2011			2010			2013		2012		2013			2012			2011
Upstream
Tengizchevroil	$	5,451	$	5,306	$	4,614		$	5,097		$	3,398		$	5,875	$	5,451	$	4,957		$	4,614		$	5,097
Petropiar	952		909		55			116			262			858		952		339			55			116
Caspian Pipeline Consortium	1,187		1,094		96			122			124			1,298		1,187		113			96			122
Petroboscan	1,261		1,032		229			247			222			1,375		1,261		300			229			247
Angola LNG Limited	3,186		2,921		(106		)	(42		)	(21		)	3,423		3,186		(111		)	(106		)	(42		)
Other	2,658		2,420		266			166			319			2,835		2,658		214			266			166
Total Upstream	14,695		13,682		5,154			5,706			4,304			15,664		14,695		5,812			5,154			5,706
Downstream
GS Caltex Corporation	2,610		2,572		249			248			158			2,518		2,610		132			249			248
Chevron Phillips Chemical Company LLC	3,451		2,909		1,206			985			704			4,312		3,451		1,371			1,206			985
Star Petroleum Refining Company Ltd.	—		1,022		22			75			122			—		—		—			22			75
Caltex Australia Ltd.	835		819		77			117			101			1,020		835		224			77			117
Colonial Pipeline Company	—		—		—			—			43
Other	837		630		196			183			151			989		837		199			196			183
Total Downstream	7,733		7,952		1,750			1,608			1,279			8,839		7,733		1,926			1,750			1,608
All Other
Other	640		516		(15		)	49			54			375		640		(211		)	(15		)	49
Total equity method	$	23,068	$	22,150	$	6,889		$	7,363		$	5,637		$	24,878	$	23,068	$	7,527		$	6,889		$	7,363
Other at or below cost	650		718											624		650
Total investments and advances	$	23,718	$	22,868										$	25,502	$	23,718
Total United States	$	5,788	$	4,847	$	1,268		$	1,119		$	846		$	6,638	$	5,788	$	1,294		$	1,268		$	1,119
Total International	$	17,930	$	18,021	$	5,621		$	6,244		$	4,791		$	18,864	$	17,930	$	6,233		$	5,621		$	6,244

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 was formed in 1993 to develop the Tengiz and Korolev crude oil fields in ~~Kazakh-~~Kazakhstan over a 40-year period. At December 31, 2013, the company’s carrying value of its investment in TCO was about $160 higher than the amount of underlying equity in TCO’s net assets. This difference results from Chevron acquiring a portion of its interest in TCO at a value greater than the underlying book value for that portion of TCO’s net assets. See Note 7, on page FS-32, for summarized financial information for 100 percent of TCO.

~~FS-38~~FS-37



Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Note 1112 Investments and Advances - Continued

~~stan over a~~ 40~~-year period. At December 31,~~ ~~2012, the company’s carrying value of its investment in TCO was about~~ ~~$170~~ 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 6, on page FS-33, for summarized financial information for ~~100 percent~~ ~~of TCO.~~

Petropiar Chevron has a 30 percent interest in Petropiar, a joint stock company formed in 2008 to operate the Hamaca heavy-oil production and upgrading project. The project, located in Venezuela’s Orinoco Belt, has a 25-year contract term. Prior to the formation of Petropiar, Chevron had a 30 percent interest in the Hamaca project. At December 31, ~~2012~~2013, the company’s carrying value of its investment in Petropiar was approximately $~~180~~170 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 joined the consortium in 1997 and has investments and advances totaling $~~1,187~~1,298, which includes long-term loans of $~~1,179~~1,251 at year-end ~~2012~~2013. 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 percent interest in Petroboscan, a joint stock company formed in 2006 to operate the Boscan Field in Venezuela until 2026. Chevron previously operated the field under an operating service agreement. At December 31, ~~2012~~2013, the company’s carrying value of its investment in Petroboscan was approximately $~~200~~180 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. In 2013, Chevron finalized a financial agreement with Petroboscan.The financing, not to exceed $2 billion, will occur in stages over a limited

drawdown period set to expire on December 31, 2018. The loan will support a specific work program to maintain and increase production to an agreed-upon level. The terms are designed to support cash needs for ongoing operations and new development, as well as distributions.

Angola LNG Ltd. Chevron has a 36 percent interest in Angola LNG Ltd., which ~~will process~~processes and ~~liquefy~~liquefies natural gas produced in Angola for delivery to international markets.

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

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

~~Star Petroleum Refining Company Ltd.Chevron has a~~ ~~64 percent~~ ~~ownership interest in Star Petroleum Refining Company Ltd. (SPRC), which owns the Star Refinery in Thailand. PTT Public Company Limited owns the remaining~~ ~~36 percent~~ ~~of SPRC. Due to a change in control effective June 2012, SPRC is consolidated in Chevron's Consolidated Financial Statements.~~

Caltex Australia Ltd. Chevron has a 50 percent equity ownership interest in Caltex Australia Ltd. (CAL). The remaining 50 percent of CAL is publicly owned. At December 31, ~~2012~~2013, the fair value of Chevron’s share of CAL common stock was approximately $~~2,690~~2,400.

Other Information “Sales and other operating revenues” on the Consolidated Statement of Income includes $~~17,356~~14,635, $~~20,164~~17,356and $~~13,672~~20,164 with affiliated companies for ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011, respectively. “Purchased crude oil and products” includes $~~6,634~~7,063, $~~7,489~~6,634 and $~~5,559~~7,489 with affiliated companies for ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011, respectively.

“Accounts and notes receivable” on the Consolidated Balance Sheet includes $~~1,207~~1,328 and $~~1,968~~1,207 due from affiliated companies at December 31, ~~2012~~2013 and ~~2011~~2012, respectively. “Accounts payable” includes $~~407~~466 and $~~519~~407 due to affiliated companies at December 31, ~~2012~~2013 and ~~2011~~2012, respectively.

~~FS-39~~



~~Notes to the Consolidated Financial Statements~~ ~~Millions of dollars, except per-share amounts~~ ~~Note 11~~ ~~Investments and Advances - Continued~~

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~~Chevron's net loans to affiliates of $~~1,494~~1,129, $~~957~~1,494 and $~~1,543~~957 at December 31, ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011, respectively.


	Affiliates						Chevron Share						Affiliates						Chevron Share
Year ended December 31	2012		2011		2010		2012		2011		2010		2013		2012		2011		2013		2012		2011
Total revenues	$	136,065	$	140,107	$	107,505	$	65,196	$	68,632	$	52,088	$	131,875	$	136,065	$	140,107	$	63,101	$	65,196	$	68,632
Income before income tax expense	23,016		23,054		18,468		9,856		10,555		7,966		24,075		23,016		23,054		11,108		9,856		10,555
Net income attributable to affiliates	16,786		16,663		12,831		6,938		7,413		5,683		15,594		16,786		16,663		7,845		6,938		7,413
At December 31
Current assets	$	37,541	$	35,573	$	30,335	$	14,732	$	14,695	$	12,845	$	39,713	$	37,541	$	35,573	$	15,156	$	14,732	$	14,695
Noncurrent assets	66,065		61,855		57,491		23,523		22,422		21,401		68,593		66,065		61,855		25,059		23,523		22,422
Current liabilities	27,878		24,671		20,428		11,093		11,040		9,363		29,642		27,878		24,671		11,587		11,093		11,040
Noncurrent liabilities	19,366		19,267		19,749		4,879		4,491		4,459		19,442		19,366		19,267		4,559		4,879		4,491
Total affiliates’ net equity	$	56,362	$	53,490	$	47,649	$	22,283	$	21,586	$	20,424	$	59,222	$	56,362	$	53,490	$	24,069	$	22,283	$	21,586

FS-38

Note 13 Properties, Plant and Equipment

Note 1213

Properties, Plant and Equipment¹


	At December 31												Year ended December 31												At December 31												Year ended December 31
	Gross Investment at Cost						Net Investment						Additions at Cost^2,3						Depreciation Expense⁴						Gross Investment at Cost						Net Investment						Additions at Cost^2,3						Depreciation Expense⁴
	2012		2011		2010		2012		2011		2010		2012		2011		2010		2012		2011		2010		2013		2012		2011		2013		2012		2011		2013		2012		2011		2013		2012		2011
Upstream
United States	$	81,908	$	74,369	$	62,523	$	37,909	$	33,461	$	23,277	$	8,211	$	14,404	$	4,934	$	3,902	$	3,870	$	4,078	$	89,555	$	81,908	$	74,369	$	41,831	$	37,909	$	33,461	$	8,188	$	8,211	$	14,404	$	4,412	$	3,902	$	3,870
International	145,799		125,795		110,578		85,318		72,543		64,388		21,343		15,722		14,381		8,015		7,590		7,448		169,623		145,799		125,795		104,100		85,318		72,543		27,383		21,343		15,722		8,336		8,015		7,590
Total Upstream	227,707		200,164		173,101		123,227		106,004		87,665		29,554		30,126		19,315		11,917		11,460		11,526		259,178		227,707		200,164		145,931		123,227		106,004		35,571		29,554		30,126		12,748		11,917		11,460
Downstream
United States	21,792		20,699		19,820		11,333		10,723		10,379		1,498		1,226		1,199		799		776		741		22,407		21,792		20,699		11,481		11,333		10,723		1,154		1,498		1,226		780		799		776
International	8,990		7,422		9,697		3,930		2,995		3,948		2,544		443		361		308		332		451		9,303		8,990		7,422		4,139		3,930		2,995		653		2,544		443		360		308		332
Total Downstream	30,782		28,121		29,517		15,263		13,718		14,327		4,042		1,669		1,560		1,107		1,108		1,192		31,710		30,782		28,121		15,620		15,263		13,718		1,807		4,042		1,669		1,140		1,107		1,108
All Other⁵
United States	4,959		5,117		4,722		2,845		2,872		2,496		415		591		259		384		338		341		5,402		4,959		5,117		3,194		2,845		2,872		721		415		591		286		384		338
International	33		30		27		13		14		16		4		5		11		5		5		4		143		33		30		84		13		14		23		4		5		12		5		5
Total All Other	4,992		5,147		4,749		2,858		2,886		2,512		419		596		270		389		343		345		5,545		4,992		5,147		3,278		2,858		2,886		744		419		596		298		389		343
Total United States	108,659		100,185		87,065		52,087		47,056		36,152		10,124		16,221		6,392		5,085		4,984		5,160		117,364		108,659		100,185		56,506		52,087		47,056		10,063		10,124		16,221		5,478		5,085		4,984
Total International	154,822		133,247		120,302		89,261		75,552		68,352		23,891		16,170		14,753		8,328		7,927		7,903		179,069		154,822		133,247		108,323		89,261		75,552		28,059		23,891		16,170		8,708		8,328		7,927
Total	$	263,481	$	233,432	$	207,367	$	141,348	$	122,608	$	104,504	$	34,015	$	32,391	$	21,145	$	13,413	$	12,911	$	13,063	$	296,433	$	263,481	$	233,432	$	164,829	$	141,348	$	122,608	$	38,122	$	34,015	$	32,391	$	14,186	$	13,413	$	12,911

Other than the United States, ~~Nigeria~~Australia and ~~Australia,~~Nigeria, no other country accounted for 10 percent or more of the company’s net properties, plant and equipment (PP&E) in 2013. Australia had $31,464, $21,770 and $12,423 in 2013, 2012., and 2011, respectively. Nigeria had PP&E of $~~17,485~~18,429, $~~15,601~~17,485 and $~~13,896~~15,601 for ~~2012~~2013,~~2011~~ ~~and~~ ~~2010, respectively. Australia had~~ ~~$21,770~~ ~~and~~ ~~$12,423~~ in 2012 and 2011, respectively.


²	Net of dry hole expense related to prior years’ expenditures of $8089, $4580 and $8245 in ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011, respectively.


³	Includes properties acquired with the acquisition of Atlas Energy, Inc., in 2011.


⁴	Depreciation expense includes accretion expense of $~~629~~627, $~~628~~629 and $~~513~~628 in ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011, respectively.


⁵	Primarily mining operations, power ~~generation businesses,~~and energy services, real estate assets and management information systems.

Note 1314

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 ~~six~~ten 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 Chevron is a defendant in a civil lawsuit ~~before~~initiated in the Superior Court of Nueva Loja in Lago Agrio, Ecuador, ~~brought~~ in May 2003 by plaintiffs who claim to be ~~represen-~~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

~~FS-40~~FS-39



Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Note 1314 Litigation - Continued

tatives 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.

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

Chevron subsequently petitioned for recusal of the judge, claiming that he had disregarded evidence of fraud and misconduct and that he had failed to rule on a number of motions within the statutory time requirement.

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

On February 14, 2011, the provincial court in Lago Agrio rendered an adverse judgment in the case. The court rejectedChevron’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

~~FS-41~~



~~Notes to the Consolidated Financial Statements~~ ~~Millions of dollars, except per-share amounts~~ ~~Note 13~~ ~~Litigation - Continued~~

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~~Chevron��s request for a 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 the next page. 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.

FS-40



Note 14 Litigation - Continued

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 appealed the tribunal's award. A Federal District Court for the District of Columbia confirmed the tribunal's award, and the Government of Ecuador has appealed the District Court's decision.

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. 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 has appealed the decision concerning jurisdiction to the Supreme Court of Canada and, on January 16, 2014, the Court of Appeals for Ontario granted Chevron’s motion to stay the recognition and enforcement proceeding pending a decision on the admissibility of the Supreme Court appeal.

On June 27, 2012, the Lago Agrio plaintiffs filed an action against Chevron Corporation in the Superior Court of Justice in Brasilia, Brazil, seeking to recognize and enforce the Ecuadorian judgment. 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 Nortberto Priu, requiring shares of both companies to be "embargoed," requiring third parties to withhold ~~40%~~40 percent of any payments due to Chevron Argentina S.R.L. and ordering banks to withhold ~~40%~~40 percent of the funds in Chevron Argentina S.R.L. bank accounts. On December 14th, 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.~~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 intends to vigorously defend against the proceeding. 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.

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,

FS-41



Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Note 14 Litigation - Continued

2012, the Tribunal issued a Second Interim Awardmandating 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

~~FS-42~~



~~Note 13~~ ~~Litigation - Continued~~

jurisdiction to hear Chevron's arbitration claims. On April 9, 2012, the Tribunal issued a scheduling order to hear issues relating to the scope of the settlement and release agreements between the Republic of Ecuador and Texpet, and on July 9, 2012, the Tribunal indicated that it wanted to hear the remaining issues in January 2014. 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.” ~~A schedule~~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. Chevron expects that the ~~Tribunal’s order to show cause hearing~~application of this ruling will be ~~issued separately.~~considered by the Tribunal in Phase Two, including a determination whether the claims of the Lago Agrio plaintiffs are individual or collective/diffuse. The Tribunal had set Phase Two to begin on January 20, 2014 to hear Chevron's denial of justice claims, but on January 2, 2014, the Tribunal postponed Phase Two and held a procedural hearing on January 20-21, 2014. The Tribunal set a hearing on April 28-30, 2014 to address remaining issues relating to Phase One. It also set a hearing on April 20 to May 6, 2015 to address Phase Two issues. The Tribunal has not set a date for Phase Three, which will be the damages phase of the arbitration.

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 ~~an award of damages and~~ a declaration that any judgment against Chevron in the Lago Agrio litigation is the result of fraud and other unlawful conduct and is therefore unenforceable. On March 7, 2011, the Federal District Court issued a preliminary injunction prohibiting the Lago Agrio plaintiffs and persons acting in concert with them from taking any action in furtherance of recognition or enforcement of any judgment against Chevron in the Lago Agrio case pending resolution of Chevron’s civil lawsuit by the Federal District Court. On May 31, 2011, the Federal District Court severed claims one

through eight of Chevron’s complaint from the ninth claim for declaratory relief and imposed a discovery stay on claims one through eight pending a trial on the ninth claim for declaratory relief. On September 19, 2011, the U.S. Court of Appeals for the Second Circuit vacated the preliminary injunction, stayed the trial on Chevron’s ninth claim, a claim for declaratory relief, that had been set for November 14, 2011, and denied the defendants’ mandamus petition to recuse the judge hearing the lawsuit. The Second Circuit issued its opinion on January 26, 2012 ordering the dismissal of Chevron’s ninth claim for declaratory relief. On February 16, 2012, the Federal District Court lifted the stay on claims one through eight, 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. Post-trial briefing has concluded, but no decision has been rendered by the Federal District Court as of the date of this report.

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 14~~

~~Taxes~~

~~Income Taxes~~

Year ended December 31
2012
2011
2010
Taxes on income
U.S. federal
Current $ 1,703
$ 1,893
$ 1,501
Deferred 673
877
162
State and local
Current 652
596
376
Deferred (145 ) 41
20
Total United States 2,883
3,407
2,059
International
Current 15,626
16,548
10,483
Deferred 1,487
671
377
Total International 17,113
17,219
10,860
Total taxes on income $ 19,996
$ 20,626
$ 12,919

In ~~2012, before-tax income for U.S. operations, including related corporate and other charges, was~~ ~~$8,456, compared with before-tax income of~~ ~~$10,222~~ ~~and~~ ~~$6,528~~ in ~~2011~~ ~~and~~ ~~2010, respectively. For international operations, before-tax income was~~ ~~$37,876~~, ~~$37,412~~ ~~and~~ ~~$25,527~~ in ~~2012~~, ~~2011~~ ~~and~~ ~~2010, respectively. U.S. federal income tax expense was reduced by~~ ~~$165~~, ~~$191~~ ~~and~~ ~~$162~~ in ~~2012~~, ~~2011~~ ~~and~~ ~~2010, 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
2012
2011
2010

U.S. statutory federal income tax rate 35.0
% 35.0
% 35.0
%
Effect of income taxes from international operations at rates different from the U.S. statutory rate 7.8
7.5
5.2

State and local taxes on income, net of U.S. federal income tax benefit 0.6
0.9
0.8

Prior-year tax adjustments (0.2 ) (0.1 ) (0.6 )
Tax credits (0.4 ) (0.4 ) (0.5 )
Effects of changes in tax rates 0.3
0.5
—

Other 0.1
(0.1 ) 0.4

Effective tax rate 43.2
% 43.3
% 40.3
%

~~FS-43~~FS-42



Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Note 1415 Taxes - Continued

Note 15

Taxes

Income Taxes



	Year ended December 31
	2013		2012			2011
Taxes on income
U.S. federal
Current	$	15	$	1,703		$	1,893
Deferred	1,128		673			877
State and local
Current	120		652			596
Deferred	74		(145		)	41
Total United States	1,337		2,883			3,407
International
Current	12,296		15,626			16,548
Deferred	675		1,487			671
Total International	12,971		17,113			17,219
Total taxes on income	$	14,308	$	19,996		$	20,626

In 2013, before-tax income for U.S. operations, including related corporate and other charges, was $4,672, compared with before-tax income of $8,456 and $10,222 in 2012 and 2011, respectively. For international operations, before-tax income was $31,233, $37,876 and $37,412 in 2013, 2012 and 2011, respectively. U.S. federal income tax expense was reduced by $175, $165 and $191 in 2013, 2012 and 2011, 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
	2013			2012			2011
U.S. statutory federal income tax rate	35.0		%	35.0		%	35.0		%
Effect of income taxes from international operations at rates different from the U.S. statutory rate	5.1			7.8			7.5
State and local taxes on income, net of U.S. federal income tax benefit	0.6			0.6			0.9
Prior-year tax adjustments	(0.8	)		(0.2	)		(0.1	)
Tax credits	(0.5	)		(0.4	)		(0.4	)
Effects of changes in tax rates	—			0.3			0.5
Other	0.5			0.1			(0.1	)
Effective tax rate	39.9		%	43.2		%	43.3		%

The company’s effective tax rate decreased ~~slightly~~ from~~43.3 percent~~ in ~~2011~~ to 43.2 percent in 2012 to 39.9 percent in 2013. The ~~impact of~~decrease was primarily due to a lower effective tax ~~rates~~rate in international upstream ~~operations~~operations. The lower international upstream effective tax rate was ~~essentially offset~~driven by a greater portion of equity income in 2013 than in 2012 (equity income is included as part of before-tax income and is generally

recorded net of income taxes) and foreign currency remeasurement impacts between periods. For international upstream, the lower effective tax rates in the current period were driven primarily by the effects of asset sales, one-time tax benefits and reduced withholding taxes, which were partially offset by a lower utilization of tax credits during the current year. impacts.

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						At December 31
	2012			2011			2013			2012
Deferred tax liabilities
Properties, plant and equipment	$	24,295		$	23,597		$	25,936		$	24,295
Investments and other	2,276			2,271			2,272			2,276
Total deferred tax liabilities	26,571			25,868			28,208			26,571
Deferred tax assets
Foreign tax credits	(10,817		)	(8,476		)	(11,572		)	(10,817		)
Abandonment/environmental reserves	(5,728		)	(5,387		)	(6,279		)	(5,728		)
Employee benefits	(5,100		)	(4,773		)	(3,825		)	(5,100		)
Deferred credits	(2,891		)	(1,548		)	(2,768		)	(2,891		)
Tax loss carryforwards	(738		)	(828		)	(1,016		)	(738		)
Other accrued liabilities	(381		)	(531		)	(533		)	(381		)
Inventory	(281		)	(360		)	(358		)	(281		)
Miscellaneous	(1,835		)	(1,595		)	(1,439		)	(1,835		)
Total deferred tax assets	(27,771		)	(23,498		)	(27,790		)	(27,771		)
Deferred tax assets valuation allowance	15,443			11,096			17,171			15,443
Total deferred taxes, net	$	14,243		$	13,466		$	17,589		$	14,243

Deferred tax liabilities at the end of ~~2012~~2013 increased by approximately $~~700~~1,600 from year-end ~~2011~~2012. The increase was related to increased temporary differences for property, plant and equipment.

Deferred tax assets ~~increased by approximately~~ ~~$4,300~~ in ~~2012. Increases primarily related to additional U.S. foreign tax credits arising from earnings in high-tax-rate international jurisdictions (which~~ were ~~substantially offset by a valuation allowance) and to future international tax benefits earned.~~essentially unchanged between periods.

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 ~~2012~~2013, the company had tax loss carryforwards of approximately $~~2,009~~3,064 and tax credit carryforwards of approximately $~~1,146~~1,301 primarily related to various international tax jurisdictions. Whereas some of these tax loss carryforwards do not have an ~~expira-~~

~~tion~~expiration date, others expire at various times from ~~2013~~2014 through 2029. U.S. foreign tax credit carryforwards of $~~10,817~~11,572 will expire between ~~2013~~2014 and ~~2022~~2023.

FS-43



Note 15 Taxes

At December 31, ~~2012~~2013 and ~~2011~~2012, deferred taxes were classified on the Consolidated Balance Sheet as follows:


	At December 31						At December 31
	2012			2011			2013			2012
Prepaid expenses and other current assets	$	(1,365	)	$	(1,149	)	$	(1,341	)	$	(1,365	)
Deferred charges and other assets	(2,662		)	(1,224		)	(2,954		)	(2,662		)
Federal and other taxes on income	598			295			583			598
Noncurrent deferred income taxes	17,672			15,544			21,301			17,672
Total deferred income taxes, net	$	14,243		$	13,466		$	17,589		$	14,243

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 $~~26,527~~31,300 at December 31, ~~2012~~2013. 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 ~~2012~~2013, deferred income taxes were recorded for the undistributed earnings of certain international operations where indefinite reinvestment of the earnings is not planned. The company does not anticipate incurring significant additional taxes on remittances of earnings that are not indefinitely reinvested.

Uncertain Income Tax Positions ~~Under accounting standards for uncertainty in income taxes (ASC 740-10), a~~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, ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011. 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.

~~FS-44~~



~~Note 14~~ ~~Taxes - Continued~~


	2012			2011			2010			2013			2012			2011
Balance at January 1	$	3,481		$	3,507		$	3,195		$	3,071		$	3,481		$	3,507
Foreign currency effects	4			(2		)	17			(58		)	4			(2		)
Additions based on tax positions taken in current year	543			469			334			276			543			469
Additions/reductions resulting from current-year asset acquisitions/sales	—			(41		)	—			—			—			(41		)
Additions for tax positions taken in prior years	152			236			270			1,164			152			236
Reductions for tax positions taken in prior years	(899		)	(366		)	(165		)	(176		)	(899		)	(366		)
Settlements with taxing authorities in current year	(138		)	(318		)	(136		)	(320		)	(138		)	(318		)
Reductions as a result of a lapse of the applicable statute of limitations	(72		)	(4		)	(8		)	(109		)	(72		)	(4		)
Balance at December 31	$	3,071		$	3,481		$	3,507		$	3,848		$	3,071		$	3,481

The ~~decrease~~increase in unrecognized tax benefits between December 31, ~~2011,~~2012, and December 31, ~~2012~~2013 was primarily due to ~~new information received during the fourth quarter 2012 regarding the sustainability of certain U.S. foreign tax credits. The reduction in unrecognized tax benefitsrelated~~additions for refund claims to ~~these foreign tax credits had no impact on the effective tax rate since the deferred tax asset recognized for these foreign tax credits has been offset~~be filed with ~~a full valuation allowance.~~respect to prior years.

Approximately 6771 percent of the $~~3,071~~3,848 of unrecognized tax benefits at December 31, ~~2012~~2013, 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, ~~2012~~2013. For these jurisdictions, the latest years for which income tax examinations had been finalized were as follows: United States – ~~2007~~2008, Nigeria – 2000, Angola – 2001, Saudi Arabia – ~~2003~~2009 and Kazakhstan – ~~2006~~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-44



Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Note 15 Taxes - Continued

The company ~~is currently assessing~~completed its assessment of the potential impact of anthe August 2012 decision by the U.S. Court of Appeals for the Third Circuit that ~~disallows~~disallowed the Historic Rehabilitation Tax Credits ~~(HRTCs)~~ claimed by an unrelated taxpayer. The ~~company has claimed a significant amount~~findings of ~~HRTCs on its U.S. federal income tax returns in open years, and it is reasonably possible that the specific findings from management's ongoing~~this assessment ~~and evaluation could~~did not result in a ~~significant increase in~~material impact on the company's ~~unrecognized tax benefit within the next 12 months. Any such increase would impact the effective tax rate.~~financial position, results of operations or cash flows.

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, ~~2012~~2013, accruals of $~~293~~215 for anticipated interest and penalty obligations were included on the Consolidated Balance Sheet, compared with accruals of $~~118~~293 as of year-end ~~2011~~2012. Income tax expense (benefit) associated with interest and penalties was $~~145~~(42), $~~(64)~~145 and $40(64) in ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011, respectively.

Taxes Other Than on Income


	Year ended December 31						Year ended December 31
	2012		2011		2010		2013		2012		2011
United States
Excise and similar taxes on products and merchandise	$	4,665	$	4,199	$	4,484	$	4,792	$	4,665	$	4,199
Import duties and other levies	1		4		—		4		1		4
Property and other miscellaneous taxes	782		726		567		1,036		782		726
Payroll taxes	240		236		219		255		240		236
Taxes on production	328		308		271		333		328		308
Total United States	6,016		5,473		5,541		6,420		6,016		5,473
International
Excise and similar taxes on products and merchandise	3,345		3,886		4,107		3,700		3,345		3,886
Import duties and other levies	106		3,511		6,183		41		106		3,511
Property and other miscellaneous taxes	2,501		2,354		2,000		2,486		2,501		2,354
Payroll taxes	160		148		133		168		160		148
Taxes on production	248		256		227		248		248		256
Total International	6,360		10,155		12,650		6,643		6,360		10,155
Total taxes other than on income	$	12,376	$	15,628	$	18,191	$	13,063	$	12,376	$	15,628

~~FS-45~~



~~Notes to the Consolidated Financial Statements~~ ~~Millions of dollars, except per-share amounts~~

Note 1516

Short-Term Debt


	At December 31						At December 31
	2012			2011			2013			2012
Commercial paper*	$	2,783		$	2,498		$	5,130		$	2,783
Notes payable to banks and others with originating terms of one year or less	23			40			49			23
Current maturities of long-term debt	20			17			—			20
Current maturities of long-term capital leases	38			54			34			38
Redeemable long-term obligations
Long-term debt	3,151			3,317			3,152			3,151
Capital leases	12			14			9			12
Subtotal	6,027			5,940			8,374			6,027
Reclassified to long-term debt	(5,900		)	(5,600		)	(8,000		)	(5,900		)
Total short-term debt	$	127		$	340		$	374		$	127


*	Weighted-average interest rates at December 31, ~~2012~~2013 and ~~2011~~2012, were ~~0.13~~0.09 percent and ~~0.04~~0.13 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, ~~2012~~2013, the company had no interest rate swaps on short-term debt.

At December 31, ~~2012~~2013, the company had $~~6,000~~8,000 in committed credit facilities with various major banks, expiring in December 2016, that enable the refinancing of short-term obligations on a long-term basis. These facilities support commercial paper borrowing and can also be used for general corporate purposes. The company’s practice has been to continually replace expiring commitments with new commitments on substantially the same terms, maintaining levels management believes appropriate. Any borrowings under the facilities would be unsecured indebtedness at interest rates based on the London Interbank Offered Rate or an average of base lending rates published by specified banks and on terms reflecting the company’s strong credit rating. No borrowings were outstandingunder these facilities at December 31, ~~2012~~2013.

At December 31, ~~2012~~2013 and ~~2011~~2012, the company classified $~~5,900~~8,000 and $~~5,600~~5,900, respectively, of short-term debt as long-term. Settlement of these obligations is not expected to require the use of working capital within one year, as the company has both the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis.

FS-45

Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts

Note 17 Long-Term Debt

Note 1617

Long-Term Debt

Total long-term debt, excluding capital leases, at December 31, ~~2012,~~2013, was $~~11,966~~19,960. The company’s long-term debt outstanding at year-end ~~2012~~2013 and ~~2011~~2012 was as follows:


	At December 31						At December 31
	2012			2011			2013		2012
3.95% notes due 2014	$	—		$	1,998
3.191% notes due 2023							$	2,250	$	—
1.104% notes due 2017	2,000			—			2,000		2,000
1.718% notes due 2018							2,000		—
2.355% notes due 2022	2,000			—			2,000		2,000
4.95% notes due 2019	1,500			1,500			1,500		1,500
2.427% notes due 2020							1,000		—
0.889% notes due 2016							750		—
8.625% debentures due 2032	147			147			147		147
8.625% debentures due 2031	107			107			107		107
7.5% debentures due 2043	83			83
8% debentures due 2032	74			74			74		74
9.75% debentures due 2020	54			54			54		54
7.327% amortizing notes due 2014¹	43			59
8.875% debentures due 2021	40			40			40		40
Medium-term notes, maturing from 2021 to 2038 (5.92%)²	38			38
Other long-term debt (8.07%)²	—			1
Medium-term notes, maturing from 2021 to 2038 (5.96%)¹							38		38
7.5% debentures due 2043							—		83
7.327% amortizing notes due 2014²							—		23
7.327% amortizing notes due 2013²							—		20
Total including debt due within one year	6,086			4,101			11,960		6,086
Debt due within one year	(20		)	(17		)	—		(20		)
Reclassified from short-term debt	5,900			5,600			8,000		5,900
Total long-term debt	$	11,966		$	9,684		$	19,960	$	11,966


¹	~~Guarantee of ESOP debt.~~ Weighted-average interest rate at December 31, 2013.


²	~~Weighted-average interest rate at December 31,~~ ~~2012~~ ~~and~~ ~~2011~~. Guarantee of ESOP debt.

~~In November 2012, the company filed with the SEC~~Chevron has an automatic ~~registration~~ statement that expires in 2015. This registration statement is for an unspecified amount of nonconvertible debt securities issued or guaranteed by the company.

Long-term debt of $~~6,086~~11,960 matures as follows: ~~2013~~ – ~~$20~~; 2014 – $230; 2015 – $0; 2016 – $0750; 2017 – $2,000; ~~and after~~ ~~2017~~2018 – $~~4,043~~2,000; and after 2018 – $7,210.

In ~~December 2012,~~June 2013, $~~4,000~~6,000 of Chevron Corporation bonds were issued, and ~~$2,000~~$83 of Texaco Capital, Inc. 7.5% bonds due 2043 and $23 of Chevron Corporation ~~3.95%~~7.327% bonds due 2014 were redeemed early. In January 2013, $20 of Chevron Corporation 7.327% bonds matured.

See Note 8,9, beginning on page ~~FS-33,~~FS-32, for information concerning the fair value of the company’s long-term debt.

~~FS-46~~

Note 1718

New Accounting Standards

~~Balance Sheet~~Income Taxes (Topic ~~210)~~740), ~~Disclosures about Offsetting Assets and Liabilities~~Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (ASU ~~2011-11)~~2013-11) In ~~December 2011,~~July 2013, the FASB issued ASU ~~2011-11,~~2013-11, which became effective for the company on January 1, ~~2013.~~2014. The standard ~~amends and expands disclosure requirements about offsetting and~~provides that a liability related ~~arrangements. The company does not anticipate any impacts~~ to ~~its results of operations, financial~~an unrecognized tax benefit should be offset against a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward if such settlement is required or expected in the event the uncertain tax position ~~or liquidity when the guidance becomes effective.~~

~~Comprehensive Income (Topic 220) Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (ASU 2013-02)~~ The FASB issued ASU 2013-02 in February 2013. This standard became effective for the company on January 1, 2013. ASU 2013-02 changes the presentation requirements of significant reclassifications out of accumulated other comprehensive income in their entirety and their corresponding effect on net income. For other significant amounts that are not required to be reclassified in their entirety, the standard requires the company to cross-reference to related footnote disclosures.is disallowed. Adoption of the standard is not expected to have a significant ~~impact~~effect on the company's results of operations, financial ~~statement presentation.~~position or liquidity.

Note 1819

Accounting for Suspended Exploratory Wells

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

The following table indicates the changes to the company’s suspended exploratory well costs for the three years ended December 31, ~~2012~~2013:

2012
2011
2010
Beginning balance at January 1 $ 2,434
$ 2,718
$ 2,435
Additions to capitalized exploratory well costs pending the determination of proved reserves 595
652
482
Reclassifications to wells, facilities
and equipment based on the
determination of proved reserves (244 ) (828 ) (129 )
Capitalized exploratory well costs
charged to expense (49 ) (45 ) (70 )
Other reductions* (55 ) (63 ) —
Ending balance at December 31 $ 2,681
$ 2,434
$ 2,718



	2013			2012			2011
Beginning balance at January 1	$	2,681		$	2,434		$	2,718
Additions to capitalized exploratory well costs pending the determination of proved reserves	885			595			652
Reclassifications to wells, facilities and equipment based on the determination of proved reserves	(290		)	(244		)	(828		)
Capitalized exploratory well costs charged to expense	(31		)	(49		)	(45		)
Other reductions*	—			(55		)	(63		)
Ending balance at December 31	$	3,245		$	2,681		$	2,434


*	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
2012
2011
2010
Exploratory well costs capitalized
for a period of one year or less $ 501
$ 557
$ 419
Exploratory well costs capitalized
for a period greater than one year 2,180
1,877
2,299
Balance at December 31 $ 2,681
$ 2,434
$ 2,718
Number of projects with exploratory well costs that have been capitalized for a period greater than one year* 46
47
53


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

~~Of the~~ ~~$2,180~~ ~~of exploratory well costs capitalized for more than one year at December 31, 2012,~~ ~~$1,359~~ (23 ~~projects) is related to projects that had drilling activities under way or firmly planned for the near future. The~~ ~~$821~~ ~~balance is related to~~ 23 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.

~~FS-47~~FS-46



~~Notes to the Consolidated Financial Statements~~ ~~Millions of dollars, except per-share amounts~~ Note 1819 Accounting for Suspended Exploratory Wells - Continued



	At December 31
	2013		2012		2011
Exploratory well costs capitalized for a period of one year or less	$	641	$	501	$	557
Exploratory well costs capitalized for a period greater than one year	2,604		2,180		1,877
Balance at December 31	$	3,245	$	2,681	$	2,434
Number of projects with exploratory well costs that have been capitalized for a period greater than one year*	51		46		47


*	Certain projects have multiple wells or fields or both.

Of the $2,604 of exploratory well costs capitalized for more than one year at December 31, 2013, $1,733 (22 projects) is related to projects that had drilling activities under way or firmly planned for the near future. The $871 balance is related to 29 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 $~~821~~871 referenced above had the following activities associated with assessing the reserves and the projects’ economic viability: (a) $~~359~~382 (six projects) – undergoing front-end engineering and design with final investment decision expected within three years; (b) $~~218~~47 (~~four~~two projects) – development concept under review by government; (c) $~~202~~384 (~~five~~nine projects) – development alternatives under review; (d) $4258 (~~eight~~twelve projects) – miscellaneous activities for projects with smaller amounts suspended. While progress was being made on all 4651 projects, the decision on the recognition of proved reserves under SEC rules in some cases may not occur for several years because of the complexity, scale and negotiations connected with the projects. ~~However, the majority~~Approximately half of these decisions are expected to occur in the next three years.

The $~~2,180~~2,604 of suspended well costs capitalized for a period greater than one year as of December 31, ~~2012~~2013, represents ~~166~~191 exploratory wells in 4651 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
1997–2002	$	120	28
2003–2007	531		46
2008–2012	1,953		117
Total	$	2,604	191

Aging based on drilling completion date of last suspended well in project:	Amount		Number of projects
1999	$	8	1
2003–2008	347		10
2009–2013	2,249		40
Total	$	2,604	51

Aging based on drilling completion date of individual wells: Amount

Number
of wells

1997–2001 $ 65
23
2002–2006 416
41
2007–2011 1,699
102
Total $ 2,180
166

Aging based on drilling completion date of last suspended well in project: Amount

Number
of projects

1999 $ 8
1
2003–2007 322
8
2008–2012 1,850
37
Total $ 2,180
46

Note 1920

Stock Options and Other Share-Based Compensation

Compensation expense for stock options for ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011 was$292 ($190 after tax), $283 ($184 after tax), and $265 ($172 ~~after tax) and~~ ~~$229~~ (~~$149~~ after tax), respectively. In addition, compensation expense for stock appreciation rights, restricted stock, performance units and restricted stock units was $223 ($145 after tax), $177 ($115 after tax), and $214 ($139 after tax) ~~and~~ ~~$194~~ (~~$126~~ ~~after tax)~~ for ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011, respectively. No significant stock-based compensation cost was capitalized at December 31, ~~2012~~2013, or December 31, ~~2011~~2012.

Cash received in payment for option exercises under all share-based payment arrangements for ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011 was $~~753~~553, $~~948~~753 and $~~385~~948, respectively. Actual tax benefits realized for the tax deductions from option exercises were $~~101~~73, $~~121~~101 and $66121 for ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011, respectively.

Cash paid to settle performance units and stock appreciation rights was $~~123~~186, $~~151~~123 and $~~140~~151 for ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011, respectively.

Chevron Long-Term Incentive Plan (LTIP) Awards under the LTIP may take the form of, but are not limited to, stock options, restricted stock, restricted stock units, stock appreciation rights, performance units and nonstock grants. From April 2004 through ~~January 2014,~~May 2023, no more than ~~160~~260 million shares may be issued under the ~~LTIP, and~~LTIP. For awards issued on or after May 29, 2013, no more than 6450 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, ~~2012~~2013, the contractual terms vary between three years for the performance units and 10 years for the stock options and stock appreciation rights.

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

~~FS-48~~FS-47



Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Note 1920 Stock Options and Other Share-Based Compensation - Continued

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

The fair market values of stock options and stock appreciation rights granted in ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011 were measured on the date of grant using the Black-Scholes option-pricing model, with the following weighted-average assumptions:


	Year ended December 31									Year ended December 31
	2012			2011			2010			2013			2012			2011
Stock Options
Expected term in years¹	6.0			6.2			6.1			6.0			6.0			6.2
Volatility²	31.7		%	31.0		%	30.8		%	31.3		%	31.7		%	31.0		%
Risk-free interest rate based on zero coupon U.S. treasury note	1.1		%	2.6		%	2.9		%	1.2		%	1.1		%	2.6		%
Dividend yield	3.2		%	3.6		%	3.9		%	3.3		%	3.2		%	3.6		%
Weighted-average fair value per option granted	$	23.35		$	21.24		$	16.28		$	24.48		$	23.35		$	21.24


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


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

A summary of option activity during ~~2012~~2013 is presented below:



			Weighted-		Average					Weighted-		Average
			Average		Remaining	Aggregate				Average		Remaining	Aggregate
	Shares		Exercise		Contractual	Intrinsic		Shares		Exercise		Contractual	Intrinsic
	(Thousands)		Price		Term (Years)	Value		(Thousands)		Price		Term (Years)	Value
Outstanding at January 1, 2012	72,348		$	73.71
Outstanding at January 1, 2013								71,895		$	81.26
Granted	12,455		$	107.73				13,194		$	116.45
Exercised	(12,024	)	$	62.13				(8,377	)	$	68.20
Forfeited	(884	)	$	96.78				(1,086	)	$	93.98
Outstanding at December 31, 2012	71,895		$	81.26	6.3	$	1,933
Exercisable at December 31, 2012	47,060		$	72.82	5.2	$	1,662
Outstanding at December 31, 2013								75,626		$	88.44	6.12	$	2,758
Exercisable at December 31, 2013								51,797		$	78.52	5.05	$	2,403

The total intrinsic value (i.e., the difference between the exercise price and the market price) of options exercised during ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011 was $~~580~~445, $~~668~~580 and $~~259~~668, respectively. During this period, the company continued its practice of issuing treasury shares upon exercise of these awards.

As of December 31, ~~2012~~2013, there was $~~255~~259 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, ~~2012~~2013, the number of LTIP performance units outstanding was equivalent to ~~2,881,836~~2,827,757 shares. During ~~2012~~2013, ~~888,350~~776,180 units were granted, ~~882,003~~1,007,952 units vested with cash proceeds distributed to recipients and ~~60,426~~64,715 units were forfeited. At December 31, ~~2012~~2013, units outstanding were ~~2,827,757~~2,531,270, and the fair value of the liability recorded for these instruments was $~~320~~312. measured using the Monte Carlo simulation method. In addition, outstanding stock appreciation rights and other awards that were granted under various LTIP and former Unocal programs totaled approximately ~~2.4~~2.9 million equivalent shares as of December 31, ~~2012~~2013. A liability of $71107 was recorded for these awards.

Note 2021

Employee Benefit Plans

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

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

~~Under accounting standards for postretirement benefits (ASC 715), the~~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.

~~FS-49~~FS-48



~~Notes to the Consolidated Financial Statements~~ ~~Millions of dollars, except per-share amounts~~ Note 2021 Employee Benefit Plans - Continued

The funded status of the company’s pension and other postretirement benefit plans for ~~2012~~2013 and ~~2011~~2012 follows:


	Pension Benefits																		Pension Benefits
	2012						2011						Other Benefits						2013						2012						Other Benefits
	U.S.			Int’l.			U.S.			Int’l.			2012			2011			U.S.			Int’l.			U.S.			Int’l.			2013			2012
Change in Benefit Obligation
Benefit obligation at January 1	$	12,165		$	5,519		$	10,271		$	5,070		$	3,765		$	3,605		$	13,654		$	6,287		$	12,165		$	5,519		$	3,787		$	3,765
Service cost	452			181			374			174			61			58			495			197			452			181			66			61
Interest cost	435			320			463			325			153			180			471			314			435			320			149			153
Plan participants’ contributions	—			7			—			6			151			148			—			8			—			7			154			151
Plan amendments	94			37			—			27			11			—			(78		)	18			94			37			—			11
Actuarial loss (gain)	1,322			417			1,920			318			44			149
Actuarial (gain) loss																			(1,398		)	(206		)	1,322			417			(636		)	44
Foreign currency exchange rate changes	—			114			—			(98		)	1			(19		)	—			(187		)	—			114			(23		)	1
Benefits paid	(763		)	(308		)	(863		)	(303		)	(350		)	(346		)	(1,064		)	(336		)	(763		)	(308		)	(359		)	(350		)
Divestitures	(51		)	—			—			—			(49		)	—			—			—			(51		)	—			—			(49		)
Curtailment	—			—			—			—			—			(10		)
Benefit obligation at December 31	13,654			6,287			12,165			5,519			3,787			3,765			12,080			6,095			13,654			6,287			3,138			3,787
Change in Plan Assets
Fair value of plan assets at January 1	8,720			3,577			8,579			3,503			—			—			9,909			4,125			8,720			3,577			—			—
Actual return on plan assets	1,149			375			(143		)	118			—			—			1,546			375			1,149			375			—			—
Foreign currency exchange rate changes	—			90			—			(66		)	—			—			—			(21		)	—			90			—			—
Employer contributions	844			384			1,147			319			199			198			819			392			844			384			205			199
Plan participants’ contributions	—			7			—			6			151			148			—			8			—			7			154			151
Benefits paid	(763		)	(308		)	(863		)	(303		)	(350		)	(346		)	(1,064		)	(336		)	(763		)	(308		)	(359		)	(350		)
Divestitures	(41		)	—			—			—			—			—			—			—			(41		)	—			—			—
Fair value of plan assets at December 31	9,909			4,125			8,720			3,577			—			—			11,210			4,543			9,909			4,125			—			—
Funded Status at December 31	$	(3,745	)	$	(2,162	)	$	(3,445	)	$	(1,942	)	$	(3,787	)	$	(3,765	)	$	(870	)	$	(1,552	)	$	(3,745	)	$	(2,162	)	$	(3,138	)	$	(3,787	)

Amounts recognized on the Consolidated Balance Sheet for the company’s pension and other postretirement benefit plans at December 31, ~~2012~~2013 and ~~2011~~2012, include:


	Pension Benefits																		Pension Benefits
	2012						2011						Other Benefits						2013						2012						Other Benefits
	U.S.			Int’l.			U.S.			Int’l.			2012			2011			U.S.			Int’l.			U.S.			Int’l.			2013			2012
Deferred charges and other assets	$	7		$	55		$	5		$	116		$	—		$	—		$	394		$	128		$	7		$	55		$	—		$	—
Accrued liabilities	(61		)	(76		)	(72		)	(84		)	(225		)	(222		)	(76		)	(81		)	(61		)	(76		)	(215		)	(225		)
Reserves for employee benefit plans	(3,691		)	(2,141		)	(3,378		)	(1,974		)	(3,562		)	(3,543		)
Noncurrent employee benefit plans																			(1,188		)	(1,599		)	(3,691		)	(2,141		)	(2,923		)	(3,562		)
Net amount recognized at December 31	$	(3,745	)	$	(2,162	)	$	(3,445	)	$	(1,942	)	$	(3,787	)	$	(3,765	)	$	(870	)	$	(1,552	)	$	(3,745	)	$	(2,162	)	$	(3,138	)	$	(3,787	)

Amounts recognized on a before-tax basis in “Accumulated other comprehensive loss” for the company’s pension and OPEB plans were $~~9,742~~5,464 and $~~9,279~~9,742 at the end of ~~2012~~2013 and ~~2011~~2012, respectively. These amounts consisted of:


	Pension Benefits														Pension Benefits
	2012				2011					Other Benefits					2013					2012				Other Benefits
	U.S.		Int’l.		U.S.			Int’l.		2012		2011			U.S.			Int’l.		U.S.		Int’l.		2013		2012
Net actuarial loss	$	6,087	$	2,439	$	5,982		$	2,250	$	968	$	1,002		$	3,185		$	1,808	$	6,087	$	2,439	$	256	$	968
Prior service (credit) costs	58		170		(44		)	152		20		(63		)	(22		)	167		58		170		70		20
Total recognized at December 31	$	6,145	$	2,609	$	5,938		$	2,402	$	988	$	939		$	3,163		$	1,975	$	6,145	$	2,609	$	326	$	988

The accumulated benefit obligations for all U.S. and international pension plans were $10,876 and $5,108, respectively, at December 31, 2013, and $12,108 and $5,167, respectively, at December 31, 2012~~, and~~ ~~$11,198~~ ~~and~~ ~~$4,518, respectively, at~~ ~~December 31, 2011~~.

~~FS-50~~FS-49



Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Note 2021 Employee Benefit Plans - Continued

Information for U.S. and international pension plans with an accumulated benefit obligation in excess of plan assets at December 31, ~~2012~~2013 and ~~2011~~2012, was:


	Pension Benefits								Pension Benefits
	2012				2011				2013				2012
	U.S.		Int’l.		U.S.		Int’l.		U.S.		Int’l.		U.S.		Int’l.
Projected benefit obligations	$	13,647	$	4,812	$	12,157	$	4,207	$	1,267	$	1,692	$	13,647	$	4,812
Accumulated benefit obligations	12,101		4,063		11,191		3,586		1,155		1,240		12,101		4,063
Fair value of plan assets	9,895		2,756		8,707		2,357		4		203		9,895		2,756

The components of net periodic benefit cost and amounts recognized in ~~other comprehensive income~~the Consolidated Statement of Comprehensive Income for ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011 are shown in the table below:


	Pension Benefits																											Pension Benefits
	2012						2011						2010						Other Benefits									2013						2012						2011						Other Benefits
	U.S.			Int’l.			U.S.			Int’l.			U.S.			Int’l.			2012			2011			2010			U.S.			Int’l.			U.S.			Int’l.			U.S.			Int’l.			2013			2012			2011
Net Periodic Benefit Cost
Service cost	$	452		$	181		$	374		$	174		$	337		$	153		$	61		$	58		$	39		$	495		$	197		$	452		$	181		$	374		$	174		$	66		$	61		$	58
Interest cost	435			320			463			325			486			307			153			180			175			471			314			435			320			463			325			149			153			180
Expected return on plan assets	(634		)	(269		)	(613		)	(283		)	(538		)	(241		)	—			—			—			(701		)	(274		)	(634		)	(269		)	(613		)	(283		)	—			—			—
Amortization of prior service (credits) costs	(7		)	18			(8		)	19			(8		)	22			(72		)	(72		)	(75		)
Amortization of prior service costs (credits)																												2			21			(7		)	18			(8		)	19			(50		)	(72		)	(72		)
Recognized actuarial losses	470			136			310			101			318			98			56			64			27			485			143			470			136			310			101			53			56			64
Settlement losses	220			5			298			—			186			6			(26		)	—			—			173			12			220			5			298			—			—			(26		)	—
Curtailment losses (gains)	—			—			—			35			—			—			—			(10		)	—			—			—			—			—			—			35			—			—			(10		)
Total net periodic benefit cost	936			391			824			371			781			345			172			220			166			925			413			936			391			824			371			218			172			220
Changes Recognized in Other Comprehensive Income
Net actuarial loss during period	805			330			2,671			448			242			118			45			131			497
Changes Recognized in Comprehensive Income
Net actuarial (gain) loss during period																												(2,244		)	(476		)	805			330			2,671			448			(659		)	45			131
Amortization of actuarial loss	(700		)	(141		)	(608		)	(101		)	(504		)	(104		)	(79		)	(64		)	(27		)	(658		)	(155		)	(700		)	(141		)	(608		)	(101		)	(53		)	(79		)	(64		)
Prior service cost during period	94			37			—			27			—			—			11			—			12
Amortization of prior service credits (costs)	7			(18		)	8			(54		)	8			(22		)	72			72			75
Prior service (credits) costs during period																												(78		)	18			94			37			—			27			—			11			—
Amortization of prior service (costs) credits																												(2		)	(21		)	7			(18		)	8			(54		)	50			72			72
Total changes recognized in other comprehensive income	206			208			2,071			320			(254		)	(8		)	49			139			557			(2,982		)	(634		)	206			208			2,071			320			(662		)	49			139
Recognized in Net Periodic Benefit Cost and Other Comprehensive Income	$	1,142		$	599		$	2,895		$	691		$	527		$	337		$	221		$	359		$	723		$	(2,057	)	$	(221	)	$	1,142		$	599		$	2,895		$	691		$	(444	)	$	221		$	359

Net actuarial losses recorded in “Accumulated other comprehensive loss” at December 31, ~~2012~~2013, for the company’s U.S. pension, international pension and OPEB plans are being amortized on a straight-line basis over approximately 10, 1312 and 10 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 ~~2013~~2014, the company estimates actuarial losses of $~~472~~209, $~~143~~102 and $547 will be amortized from “Accumulated other comprehensive loss” for U.S. pension, international pension and OPEB plans,

~~OPEB plans,~~ respectively. In addition, the company estimates an additional $~~230~~132 will be recognized from “Accumulated other comprehensive loss” during ~~2013~~2014 related to lump-sum settlement costs from U.S. pension plans.

The weighted average amortization period for recognizing prior service costs (credits) recorded in “Accumulated other comprehensive loss” at December 31, ~~2012~~2013, was approximately 10 and 1312 years for U.S. and international pension plans, respectively, and 1110 years for other postretirement benefit plans. During ~~2013~~2014, the company estimates prior service (credits) costs of $1(9), $2221 and $~~(50)~~14 will be amortized from “Accumulated other comprehensive loss” for U.S. pension, international pension and OPEB plans, respectively.

~~FS-51~~FS-50



Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Note 2021 Employee Benefit Plans - Continued

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


	Pension Benefits																		Pension Benefits
	2012				2011				2010						Other Benefits				2013				2012				2011						Other Benefits
	U.S.		Int’l.		U.S.		Int’l.		U.S.		Int’l.		2012		2011		2010		U.S.		Int’l.		U.S.		Int’l.		U.S.		Int’l.		2013		2012		2011
Assumptions used to determine benefit obligations:
Discount rate	3.6	%	5.2	%	3.8	%	5.9	%	4.8	%	6.5	%	4.1	%	4.2	%	5.2	%	4.3	%	5.8	%	3.6	%	5.2	%	3.8	%	5.9	%	4.9	%	4.1	%	4.2	%
Rate of compensation increase	4.5	%	5.5	%	4.5	%	5.7	%	4.5	%	6.7	%	N/A		N/A		N/A		4.5	%	5.5	%	4.5	%	5.5	%	4.5	%	5.7	%	N/A		N/A		N/A
Assumptions used to determine net periodic benefit cost:
Discount rate	3.8	%	5.9	%	4.8	%	6.5	%	5.3	%	6.8	%	4.2	%	5.2	%	5.9	%	3.6	%	5.2	%	3.8	%	5.9	%	4.8	%	6.5	%	4.1	%	4.2	%	5.2	%
Expected return on plan assets	7.5	%	7.5	%	7.8	%	7.8	%	7.8	%	7.8	%	N/A		N/A		N/A		7.5	%	6.8	%	7.5	%	7.5	%	7.8	%	7.8	%	N/A		N/A		N/A
Rate of compensation increase	4.5	%	5.7	%	4.5	%	6.7	%	4.5	%	6.3	%	N/A		N/A		N/A		4.5	%	5.5	%	4.5	%	5.7	%	4.5	%	6.7	%	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 ~~2012~~2013, the company used an expected long-term rate of return of 7.5 percent for U.S. pension plan assets, which account for 7071 percent of the company’s pension plan assets. In ~~2011~~2012 and ~~2010~~2011, the company used a long-term rate of return of 7.5 and 7.8 percent, respectively for this plan.

The market-related value of assets of the major U.S. pension plan used in the determination of pension expense was based on the market values in the three months preceding the year-end measurement date. 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 postretirement benefit plan obligations and expense reflect the rate at which benefits could be effectively settled, and is 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, ~~2012~~2013, the company used a ~~3.6~~4.3 percent discount rate for the U.S. pension plans and ~~3.9~~4.7 percent for the main U.S. OPEB plan. The discount rates at the end of ~~2011~~2012 and ~~2010~~2011 were3.6 and 3.9 percent and 3.8 and 4.0 ~~percent~~ ~~and~~ ~~4.8~~ ~~and~~ ~~5.0~~ percent for the U.S. pension plans and the main U.S. OPEB plans, respectively.

Other Benefit Assumptions For the measurement of accumulated postretirement benefit obligation at December 31, ~~2012~~2013, for the main U.S. postretirement medical plan, the assumed health care cost-trend rates start with ~~7.5~~7.3 percent in ~~2013~~2014 and gradually decline to 4.5 percent for 2025 and beyond. For this measurement at December 31, ~~2011~~2012, the assumed health care cost-trend rates started with 87.5 percent in ~~2012~~2013 and gradually declined to 5 4.5

percent for ~~2023~~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 primary U.S. plan. A 1-percentage-point change in the assumed health care cost-trend rates would have the following ~~effects:~~effects on worldwide plans:


	1 Percent		1 Percent			1 Percent		1 Percent
	Increase		Decrease			Increase		Decrease
Effect on total service and interest cost components	$	16	$	(13	)	$	13	$	(11	)
Effect on postretirement benefit obligation	$	165	$	(141	)	$	137	$	(115	)

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

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

Level 2: Fair values of these assets are measured based on quoted prices for similar assets in active markets; quoted prices for identical or similar assets in inactive markets; inputs other than quoted prices that are observable for the asset; and inputs

~~FS-52~~



~~Note 20~~ ~~Employee Benefit Plans - Continued~~

that are derived principally from or corroborated by observable market data through correlation or other means. If

FS-51



Note 21 Employee Benefit Plans - Continued

the asset has a contractual term, the Level 2 input is observable for substantially the full term of the asset. The fair values for Level 2 assets are generally obtained from third-party broker quotes, independent pricing services and exchanges.

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

The fair value measurements of the company’s pension plans for ~~2012~~2013 and ~~2011~~2012 are below:


	U.S.										Int’l.									U.S.									Int’l.
	Total Fair Value			Level 1			Level 2		Level 3		Total Fair Value		Level 1			Level 2		Level 3		Total Fair Value		Level 1			Level 2		Level 3		Total Fair Value		Level 1			Level 2		Level 3
At December 31, 2011
Equities
U.S.¹	$	1,470		$	1,470		$	—	$	—	$	497	$	497		$	—	$	—
International	1,203			1,203			—		—		693		693			—		—
Collective Trusts/Mutual Funds²	2,633			14			2,619		—		596		28			568		—
Fixed Income
Government	622			146			476		—		635		25			610		—
Corporate	338			—			338		—		319		16			276		27
Mortgage-Backed Securities	107			—			107		—		2		—			—		2
Other Asset Backed	61			—			61		—		5		—			5		—
Collective Trusts/Mutual Funds²	1,046			—			1,046		—		345		61			284		—
Mixed Funds³	10			10			—		—		102		13			89		—
Real Estate⁴	843			—			—		843		155		—			—		155
Cash and Cash Equivalents	404			404			—		—		211		211			—		—
Other⁵	(17		)	(79		)	8		54		17		(2		)	17		2
Total at December 31, 2011	$	8,720		$	3,168		$	4,655	$	897	$	3,577	$	1,542		$	1,849	$	186
At December 31, 2012
Equities
U.S.¹	$	1,709		$	1,709		$	—	$	—	$	334	$	334		$	—	$	—	$	1,709	$	1,709		$	—	$	—	$	334	$	334		$	—	$	—
International	1,263			1,263			—		—		520		520			—		—		1,263		1,263			—		—		520		520			—		—
Collective Trusts/Mutual Funds²	2,979			7			2,972		—		1,233		402			831		—		2,979		7			2,972		—		1,233		402			831		—
Fixed Income
Government	435			396			39		—		578		40			538		—		435		396			39		—		578		40			538		—
Corporate	384			—			384		—		230		25			175		30		384		—			384		—		230		25			175		30
Mortgage-Backed Securities	65			—			65		—		2		—			—		2		65		—			65		—		2		—			—		2
Other Asset Backed	51			—			51		—		4		—			4		—		51		—			51		—		4		—			4		—
Collective Trusts/Mutual Funds²	1,520			—			1,520		—		671		26			645		—		1,520		—			1,520		—		671		26			645		—
Mixed Funds³	—			—			—		—		115		4			111		—		—		—			—		—		115		4			111		—
Real Estate⁴	1,114			—			—		1,114		177		—			—		177		1,114		—			—		1,114		177		—			—		177
Cash and Cash Equivalents	373			373			—		—		222		204			18		—		373		373			—		—		222		204			18		—
Other⁵	16			(44		)	5		55		39		(3		)	40		2		16		(44		)	5		55		39		(3		)	40		2
Total at December 31, 2012	$	9,909		$	3,704		$	5,036	$	1,169	$	4,125	$	1,552		$	2,362	$	211	$	9,909	$	3,704		$	5,036	$	1,169	$	4,125	$	1,552		$	2,362	$	211
At December 31, 2013
Equities
U.S.¹																				$	2,298	$	2,298		$	—	$	—	$	409	$	409		$	—	$	—
International																				1,501		1,501			—		—		533		533			—		—
Collective Trusts/Mutual Funds²																				2,977		26			2,951		—		1,066		211			855		—
Fixed Income
Government																				81		52			29		—		726		46			680		—
Corporate																				1,275		—			1,275		—		545		23			499		23
Mortgage-Backed Securities																				1		—			1		—		4		—			2		2
Other Asset Backed																				—		—			—		—		—		—			—		—
Collective Trusts/Mutual Funds²																				1,357		—			1,357		—		647		27			620		—
Mixed Funds³																				—		—			—		—		120		5			115		—
Real Estate⁴																				1,265		—			—		1,265		294		—			—		294
Cash and Cash Equivalents																				385		385			—		—		173		173			—		—
Other⁵																				70		(2		)	18		54		26		(2		)	25		3
Total at December 31, 2013																				$	11,210	$	4,260		$	5,631	$	1,319	$	4,543	$	1,425		$	2,796	$	322


¹	U.S. equities include investments in the company’s common stock in the amount of $28 at December 31, 2013, and $27 at December 31, 2012~~, and~~ ~~$35~~ at ~~December 31, 2011~~.


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-53~~FS-52



Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Note 2021 Employee Benefit Plans - Continued

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


	Fixed Income													Fixed Income
				Mortgage-Backed													Mortgage-Backed
	Corporate			Securities		Real Estate		Other			Total			Corporate			Securities		Real Estate		Other		Total
Total at December 31, 2010	$	28		$	2	$	738	$	55		$	823
Actual Return on Plan Assets:
Assets held at the reporting date	—			—		103		4			107
Assets sold during the period	—			—		1		(2		)	(1		)
Purchases, Sales and Settlements	(1		)	—		156		(1		)	154
Transfers in and/or out of Level 3	—			—		—		—			—
Total at December 31, 2011	$	27		$	2	$	998	$	56		$	1,083		$	27		$	2	$	998	$	56	$	1,083
Actual Return on Plan Assets:
Assets held at the reporting date	—			—		108		1			109			—			—		108		1		109
Assets sold during the period	—			—		2		—			2			—			—		2		—		2
Purchases, Sales and Settlements	4			—		182		—			186			4			—		182		—		186
Transfers in and/or out of Level 3	—			—		—		—			—			—			—		—		—		—
Total at December 31, 2012	$	31		$	2	$	1,290	$	57		$	1,380		$	31		$	2	$	1,290	$	57	$	1,380
Actual Return on Plan Assets:
Assets held at the reporting date														(9		)	—		90		—		81
Assets sold during the period														—			—		3		—		3
Purchases, Sales and Settlements														1			—		176		—		177
Transfers in and/or out of Level 3														—			—		—		—		—
Total at December 31, 2013														$	23		$	2	$	1,559	$	57	$	1,641

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 8788 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 20–6560 percent, Real Estate 0–15 percent, and Other 0–5 percent. For the U.K. pension plan, the U.K. Board of Trustees has established the following asset allocation guidelines, which are reviewed regularly: Equities 50–7040-60 percent, ~~and~~ Fixed Income and Cash 30–25–50 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 ~~2012~~2013, the company contributed $~~844~~819 and $~~384~~375 to its U.S. and international pension plans, respectively. In ~~2013~~2014, the company expects contributions to be approximately $~~650~~

~~and~~ $350 to its U.S. plan and $350 to its international pension ~~plans, respectively.~~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 other postretirement benefits of approximately $~~228~~215 in ~~2013~~2014, compared with $~~199~~205 paid in ~~2012~~2013.

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		Pension Benefits				Other
	U.S.		Int’l.		Benefits		U.S.		Int’l.		Benefits
2013	$	1,188	$	273	$	228
2014	$	1,192	$	338	$	234	$	1,212	$	284	$	215
2015	$	1,179	$	265	$	239	$	1,187	$	290	$	218
2016	$	1,180	$	291	$	245	$	1,170	$	284	$	221
2017	$	1,184	$	386	$	249	$	1,175	$	363	$	224
2018-2022	$	5,650	$	2,353	$	1,292
2018							$	1,168	$	391	$	227
2019-2023							$	5,399	$	2,307	$	1,148

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

Charges to expense for the ESIP represent the company’s contributions to the plan, which are funded either through the purchase of shares of common stock on the open market or through the release of common stock held in the leveraged employee stock ownership plan (LESOP), which is described in the section that follows. Total company matching contributions to employee accounts within the ESIP were $~~286~~303, $~~263~~286 and $~~253~~263 in ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011, respectively. This cost was reduced by the value of shares released from the LESOP totaling $43140, $3843 and $9738 in ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011, respectively. The remaining amounts, totaling $163, $243

~~FS-54~~FS-53



Note 2021 Employee Benefit Plans - Continued

~~respectively. The remaining amounts, totaling~~ ~~$243~~,and $225 ~~and~~ ~~$156~~in ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011, respectively, represent open market purchases.

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

~~As permitted by accounting standards for share-based compensation (ASC 718), the~~ The debt ofassociated with the LESOP ~~is recorded as debt, and shares pledged as collateral are reported as “Deferred compensation and benefit plan trust” on the Consolidated Balance Sheet~~was retired in 2013 and the ~~Consolidated Statement of Equity.~~remaining unallocated shares were distributed to ESIP participants during the year.

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

Total ~~expense~~expenses (credits) for the LESOP were $15, $~~(1)~~1 and $(1) in ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011, respectively. The net ~~credit~~expense (credit) for the respective years ~~was~~were composed of ~~credits to~~ compensation ~~expense~~expenses (credits) of $24, $5(2) and $6(5) and charges to interest expense for LESOP debt of $31, $43 and $54.

Of the dividends paid on the LESOP shares, $1838, $18 and $4618 were used in ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011, respectively, to service LESOP debt. The company also contributed $7 and $2 in 2013 and 2012, respectively, to satisfy LESOP debt service. No company contributions were required in 2011, or ~~2010~~, as dividends received by the LESOP were sufficient to satisfy LESOP debt service. ~~In 2012, the company contributed~~ $2 ~~to the LESOP.~~

Shares held in the LESOP ~~are~~were released and allocated to the accounts of ~~plan~~ESIP participants based on debt service deemed to be paid in the year in proportion to the total of current-year and remaining debt service. LESOP shares as of December 31, ~~2012~~2013 and ~~2011~~2012, were as follows:


Thousands	2012	2011	2013	2012
Allocated shares	18,055	19,047	17,954	18,055
Unallocated shares	1,292	1,864	—	1,292
Total LESOP shares	19,347	20,911	17,954	19,347

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 ~~2012~~2013, 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, ~~2012~~2013 and ~~2011~~2012, trust assets of $4840 and $5148, 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 $~~898~~871, $~~1,217~~898 and $~~766~~1,217 in ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011, 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 ~~19,~~20, beginning on page ~~FS-48.~~FS-47.

Note 2122

Equity

Retained earnings at December 31, ~~2012~~2013 and ~~2011~~2012, included approximately $~~10,119~~11,395 and $~~10,127~~10,119, respectively, for the company’s share of undistributed earnings of equity affiliates.

At December 31, ~~2012~~2013, about 55143 million shares of Chevron’s common stock remained available for issuance from the ~~160~~260 million shares that were reserved for issuance under the Chevron LTIP. In addition, approximately ~~231,000~~204,000 shares remain available for issuance from the 800,000 shares of the company’s common stock that were reserved for awards under the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan.

Note 2223

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 ~~14,~~15, beginning on page FS-43, 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. As discussed on page FS-45, Chevron ~~is currently assessing~~completed its assessment of the potential impact of athe August 2012 decision by the U.S. Court of Appeals for the Third Circuit that ~~disallows~~disallowed the Historic ~~Rehabilita-~~Rehabilitation Tax Credits claimed by an unrelated taxpayer. The findings of this assessment did not result in a

~~FS-55~~FS-54



~~Notes to the Consolidated Financial Statements~~ ~~Millions of dollars, except per-share amounts~~ Note 2223 Other Contingencies and Commitments - Continued

tion Tax Credits claimed by an unrelated taxpayer. It is reasonably possible that the specific findings from this assessment could result in a significant increase in unrecognized tax benefits, which may have a material ~~effect~~impact on the company's financial position, results of operations ~~in any one reporting period. The company does not expect settlement of income tax liabilities associated with uncertain tax positions to have a material effect on its consolidated financial position~~ or ~~liquidity.~~cash flows.

Guarantees The company’s guarantee of $~~562~~524 is associated with certain payments under a terminal use agreement entered into by an equity affiliate. Over the approximate 1514-year remaining term of the guarantee, the maximum guarantee amount will be reduced ~~over time~~ as certain fees are paid by the affiliate. There are numerous cross-indemnity agreements with the affiliate and the other partners to permit recovery of amounts paid under the guarantee. Chevron has recorded no liability for its obligation under this guarantee.

IndemnificationsThe company provided certain indemnities of contingent liabilities of Equilon and Motiva to Shell and Saudi Refining, Inc., in connection with the February 2002 sale of the company’s interests in those investments. Through the end of ~~2012, the company paid~~ ~~$48~~ ~~under these indemnities and continues to be obligated up to~~ ~~$250~~ ~~for possible additional indemnification payments in the future.~~

The company has also provided indemnities relating to contingent environmental liabilities of assets originally contributed by Texaco to the Equilon and Motiva joint ventures and environmental conditions that existed prior to the formation of Equilon and Motiva, or that occurred during the

period of Texaco’s ownership interest in the joint ventures. In general, the environmental conditions or events that are subject to these indemnities must have arisen prior to December 2001. Claims had to be asserted by February 2009 for Equilon indemnities and February 2012 for Motiva indemnities. In February 2012, Motiva Enterprises LLC delivered a letter to the company purporting to preserve unmatured claims for certain Motiva indemnities. The company had previously provided a negative response to similar claims. The letter itself provides no estimate of the ultimate claim amount. Management does not believe this letter or any other information provides a basis to estimate the amount, if any, of a range of loss or potential range of loss with respect to either the Equilon or the Motiva indemnities. The company posts no assets as collateral and has made no payments under the indemnities.

Through December 31, 2012, the company has not received further correspondence from Equilon and Motiva Enterprises LLC and the company does not expect further action to occur related to the indemnities described in the preceding paragraphs.

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

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

Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements The company and its subsidiaries have certain other contingent liabilities with respect to long-term unconditional purchase obligations and commitments, including throughput and take-or-pay agreements, some of which relate to suppliers’ financing arrangements. The agreements typically provide goods and services, such as pipeline and storage capacity, drilling rigs, utilities, and petroleum products, to be used or sold in the ordinary course of the company’s business. The aggregate approximate amounts of required payments under these various commitments are: ~~2013~~ – ~~$3,700~~; 2014 – $~~3,900~~4,200; 2015 – $~~4,100~~4,500; 2016 – $~~2,400~~3,200; 2017 – $~~1,800~~2,600; 2018 – $2,200; 2019 and after – $~~6,500~~6,900. A portion of these commitments may ultimately be shared with project partners. Total payments under the agreements were approximately $3,600 in 2013, $3,600 in 2012, and $6,600 in 2011 ~~and~~ ~~$6,500~~ in ~~2010~~.

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

divested. These future costs are not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required,

~~FS-56~~



~~Note 22~~ ~~Other Contingencies and Commitments - Continued~~

the determination of the company’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties.

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

Chevron’s environmental reserve as of December 31, ~~2012~~2013, was $~~1,403~~1,456. Included in this balance were remediation activities at approximately ~~175~~174 sites for which the company had been identified as a potentially responsible party or otherwise involved in the remediation by the U.S. Environmental Protection Agency (EPA) or other regulatory agencies under the provisions of the federal Superfund law or analogous state laws. The company’s remediation reserve for these sites at year-end ~~2012~~2013 was $~~157~~179. The federal Superfund law and analogous state laws provide for joint and several liability for all responsible parties. Any future actions by the EPA or other regulatory agencies to require Chevron to assume other potentially responsible parties’ costs at designated hazardous waste sites are not expected to have a material effect on the company’s results of operations, consolidated financial position or liquidity.

Of the remaining year-end ~~2012~~2013 environmental reserves balance of $~~1,246~~1,277, $~~782~~834 related to the company’s U.S. downstream operations, including refineries and other plants, marketing locations (i.e., service stations and terminals), chemical facilities, and pipelines. The remaining $~~464~~443 was associated with various sites in international downstream $9379, upstream $~~309~~313 and other businesses $6251. Liabilities at all sites, whether operating, closed or divested, were primarily associated with the company’s plans and activities to

FS-55



Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts Note 23 Other Contingencies and Commitments - Continued

remediate soil or groundwater contamination or both. These and other activities include one or more of the following: site assessment; soil excavation; offsite disposal of contaminants; onsite containment, remediation and/or extraction of petroleum hydrocarbon liquid and vapor from soil; groundwater extraction and treatment; and monitoring of the natural attenuation of the contaminants.

The company manages environmental liabilities under specific sets of regulatory requirements, which in the United States include the Resource Conservation and Recovery Act and various state and local regulations. No single remediation site at year-end ~~2012~~2013 had a recorded liability that was ~~mate-~~

~~rial~~material to the company’s results of operations, consolidated financial position or liquidity.

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

Refer to Note ~~23 on page FS-58~~24 for a discussion of the company’s asset retirement obligations.

Other Contingencies On April 26, 2010, a California appeals court issued a ruling related to the adequacy of an Environmental Impact Report (EIR) supporting the issuance of certain permits by the city of Richmond, California, to replace and upgrade certain facilities at Chevron’s refinery in Richmond. Settlement discussions with plaintiffs in the case ended late fourth quarter 2010, and on March 3, 2011, the trial court entered a final judgment and peremptory writ ordering the City to set aside the project EIR and conditional use permits and enjoining Chevron from any further work. On May 23, 2011, the company filed an application with the City Planning Department for a conditional use permit for a revised project to complete construction of the hydrogen plant, certain sulfur removal facilities and related infrastructure. On June 10, 2011, the City published its Notice of Preparation of the revised EIR for the project. The revised and recirculated EIR is intended to comply with the appeals court decision. Management believes the outcomes associated with the project are uncertain. Due to the uncertainty of the company’s future course of action, or potential outcomes of any action or combination of actions, management does not believe an estimate of the financial effects, if any, can be made at this time.

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

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

~~FS-57~~



~~Notes to the Consolidated Financial Statements~~ ~~Millions of dollars, except per-share amounts~~

Note 2324

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 ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011:


	2012			2011			2010			2013			2012			2011
Balance at January 1	$	12,767		$	12,488		$	10,175		$	13,271		$	12,767		$	12,488
Liabilities incurred	133			62			129			59			133			62
Liabilities settled	(966		)	(1,316		)	(755		)	(907		)	(966		)	(1,316		)
Accretion expense	629			628			513			627			629			628
Revisions in estimated cash flows	708			905			2,426			1,248			708			905
Balance at December 31	$	13,271		$	12,767		$	12,488		$	14,298		$	13,271		$	12,767

In the table above, the amounts associated with "Revisions in estimated cash flows" reflect increasing cost estimates to abandon wells, equipment and facilities.

The long-term portion of the $~~13,271~~14,298 balance at the end of ~~2012~~2013 was $~~12,375~~13,476.

FS-56

Note 25 Other Financial Information

Note 2425

Other Financial Information

Earnings in 2013 included after-tax gains of approximately $500 relating to the sale of nonstrategic properties. Of this amount, approximately $300 and $200 related to downstream and upstream assets, respectively. Earnings in 2012 included after-tax gains of approximately $2,800 relating to the sale of nonstrategic properties. Of this amount, approximately $2,200 and ~~$600~~$600 related to upstream and downstream ~~assets, respectively. Earnings in~~ ~~2011~~ ~~included gains of approximately~~ ~~$1,300~~ ~~relating to the sale of nonstrategic properties. Of this amount, approximately~~ ~~$800~~ ~~and~~ ~~$500~~ ~~related to downstream and upstream~~ assets, respectively.

Other financial information is as follows:


	Year ended December 31								Year ended December 31
	2012			2011		2010			2013		2012			2011
Total financing interest and debt costs	$	242		$	288	$	317		$	284	$	242		$	288
Less: Capitalized interest	242			288		267			284		242			288
Interest and debt expense	$	—		$	—	$	50		$	—	$	—		$	—
Research and development expenses	$	648		$	627	$	526		$	750	$	648		$	627
Foreign currency effects*	$	(454	)	$	121	$	(423	)	$	474	$	(454	)	$	121


^*	Includes $~~(202)~~244, $~~(27)~~(202) and $~~(71)~~(27) in ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011, respectively, for the company’s share of equity affiliates’ foreign currency effects.

The excess of replacement cost over the carrying value of inventories for which the last-in, first-out (LIFO) method is used was $~~9,292~~9,150 and $~~9,025~~9,292 at December 31, ~~2012~~2013 and ~~2011~~2012, respectively. Replacement cost is generally based on average acquisition costs for the year. LIFO profits (charges) of $~~121~~14, $~~193~~121 and $21193 were included in earnings for the years ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011, respectively.

The company has $~~4,640~~4,639 in goodwill on the Consolidated Balance Sheet related to the 2005 acquisition of Unocal and to the 2011 acquisition of Atlas Energy, Inc. ~~Under the accounting standard for goodwill (ASC 350), the~~The company tested this goodwill for impairment during ~~2012~~2013 and concluded no impairment was necessary.

Note 26

Assets Held For Sale

At December 31, 2013, the company classified $580 of net properties, plant and equipment as “Assets held for sale” on the Consolidated Balance Sheet. These assets are associated with upstream operations that are anticipated to be sold in 2014. The revenues and earnings contributions of these assets in 2013 were not material.

~~FS-58~~

Note 2527

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 ~~19,~~20, “Stock Options and Other Share-Based Compensation,” beginning on page ~~FS-48)~~FS-47). The table below sets forth the computation of basic and diluted EPS:


	Year ended December 31						Year ended December 31
	2012		2011		2010		2013		2012		2011
Basic EPS Calculation
Earnings available to common stockholders - Basic*	$	26,179	$	26,895	$	19,024	$	21,423	$	26,179	$	26,895
Weighted-average number of common shares outstanding	1,950		1,986		1,996		1,916		1,950		1,986
Add: Deferred awards held as stock units	—		—		1		1		—		—
Total weighted-average number of common shares outstanding	1,950		1,986		1,997		1,917		1,950		1,986
Earnings per share of common stock - Basic	$	13.42	$	13.54	$	9.53	$	11.18	$	13.42	$	13.54
Diluted EPS Calculation
Earnings available to common stockholders - Diluted*	$	26,179	$	26,895	$	19,024	$	21,423	$	26,179	$	26,895
Weighted-average number of common shares outstanding	1,950		1,986		1,996		1,916		1,950		1,986
Add: Deferred awards held as stock units	—		—		1		1		—		—
Add: Dilutive effect of employee stock-based awards	15		15		10		15		15		15
Total weighted-average number of common shares outstanding	1,965		2,001		2,007		1,932		1,965		2,001
Earnings per share of common stock - Diluted	$	13.32	$	13.44	$	9.48	$	11.09	$	13.32	$	13.44

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

~~FS-59~~



~~Notes to the Consolidated Financial Statements~~ ~~Millions of dollars, except per-share amounts~~

~~Note 26~~

~~Acquisition of Atlas Energy, Inc.~~

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

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

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

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

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

Properties were measured primarily using an income approach. The fair values of the acquired oil and gas properties were based on significant inputs not observable in the market and thus represent Level 3 measurements. Refer to Note 8, beginning on page FS-33 for a definition of fair value hierarchy levels. Significant inputs included estimated resource volumes, assumed future production profiles, estimated future commodity prices, a discount rate of ~~8 percent, and assumptions on the timing and amount of future operating and development costs. All the properties are in the United States and are included in the Upstream segment.~~

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

~~FS-60~~FS-57

Five-Year Financial Summary

Unaudited


Millions of dollars, except per-share amounts	2012		2011		2010		2009		2008		2013		2012		2011		2010		2009
Statement of Income Data
Revenues and Other Income
Total sales and other operating revenues*	$	230,590	$	244,371	$	198,198	$	167,402	$	264,958	$	220,156	$	230,590	$	244,371	$	198,198	$	167,402
Income from equity affiliates and other income	11,319		9,335		6,730		4,234		8,047		8,692		11,319		9,335		6,730		4,234
Total Revenues and Other Income	241,909		253,706		204,928		171,636		273,005		228,848		241,909		253,706		204,928		171,636
Total Costs and Other Deductions	195,577		206,072		172,873		153,108		229,948		192,943		195,577		206,072		172,873		153,108
Income Before Income Tax Expense	46,332		47,634		32,055		18,528		43,057		35,905		46,332		47,634		32,055		18,528
Income Tax Expense	19,996		20,626		12,919		7,965		19,026		14,308		19,996		20,626		12,919		7,965
Net Income	26,336		27,008		19,136		10,563		24,031		21,597		26,336		27,008		19,136		10,563
Less: Net income attributable to noncontrolling interests	157		113		112		80		100		174		157		113		112		80
Net Income Attributable to Chevron Corporation	$	26,179	$	26,895	$	19,024	$	10,483	$	23,931	$	21,423	$	26,179	$	26,895	$	19,024	$	10,483
Per Share of Common Stock
Net Income Attributable to Chevron
– Basic	$	13.42	$	13.54	$	9.53	$	5.26	$	11.74	$	11.18	$	13.42	$	13.54	$	9.53	$	5.26
– Diluted	$	13.32	$	13.44	$	9.48	$	5.24	$	11.67	$	11.09	$	13.32	$	13.44	$	9.48	$	5.24
Cash Dividends Per Share	$	3.51	$	3.09	$	2.84	$	2.66	$	2.53	$	3.90	$	3.51	$	3.09	$	2.84	$	2.66
Balance Sheet Data (at December 31)
Current assets	$	55,720	$	53,234	$	48,841	$	37,216	$	36,470	$	50,250	$	55,720	$	53,234	$	48,841	$	37,216
Noncurrent assets	177,262		156,240		135,928		127,405		124,695		203,503		177,262		156,240		135,928		127,405
Total Assets	232,982		209,474		184,769		164,621		161,165		253,753		232,982		209,474		184,769		164,621
Short-term debt	127		340		187		384		2,818		374		127		340		187		384
Other current liabilities	34,085		33,260		28,825		25,827		29,205		32,644		34,085		33,260		28,825		25,827
Long-term debt and capital lease obligations	12,065		9,812		11,289		10,130		6,083		20,057		12,065		9,812		11,289		10,130
Other noncurrent liabilities	48,873		43,881		38,657		35,719		35,942		50,251		48,873		43,881		38,657		35,719
Total Liabilities	95,150		87,293		78,958		72,060		74,048		103,326		95,150		87,293		78,958		72,060
Total Chevron Corporation Stockholders' Equity	$	136,524	$	121,382	$	105,081	$	91,914	$	86,648	$	149,113	$	136,524	$	121,382	$	105,081	$	91,914
Noncontrolling interests	1,308		799		730		647		469		1,314		1,308		799		730		647
Total Equity	$	137,832	$	122,181	$	105,811	$	92,561	$	87,117	$	150,427	$	137,832	$	122,181	$	105,811	$	92,561

* Includes excise, value-added and similar taxes:	$	8,010	$	8,085	$	8,591	$	8,109	$	9,846	$	8,492	$	8,010	$	8,085	$	8,591	$	8,109

~~FS-61~~FS-58



	Supplemental Information on Oil and Gas Producing Activities Unaudited

In accordance with FASB and SEC disclosure and reporting 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

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


	Consolidated Companies														Affiliated Companies				Consolidated Companies														Affiliated Companies
			Other																		Other
Millions of dollars	U.S.		Americas		Africa		Asia		Australia		Europe		Total		TCO		Other		U.S.		Americas		Africa		Asia		Australia		Europe		Total		TCO		Other
Year Ended December 31, 2012
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
Year Ended December 31, 2012⁵
Exploration
Wells	$	251	$	202	$	121	$	271	$	302	$	88	$	1,235	$	—	$	—	$	251	$	202	$	121	$	271	$	302	$	88	$	1,235	$	—	$	—
Geological and geophysical	99		105		107		86		47		58		502		—		—		99		105		107		86		47		58		502		—		—
Rentals and other	161		55		93		201		85		107		702		—		—		161		55		93		201		85		107		702		—		—
Total exploration	511		362		321		558		434		253		2,439		—		—		511		362		321		558		434		253		2,439		—		—
Property acquisitions²
Proved	248		—		8		39		—		—		295		—		—		248		—		8		39		—		—		295		—		—
Unproved	1,150		29		5		342		28		—		1,554		—		28		1,150		29		5		342		28		—		1,554		—		28
Total property acquisitions	1,398		29		13		381		28		—		1,849		—		28		1,398		29		13		381		28		—		1,849		—		28
Development³	6,597		1,211		3,118		3,797		4,555		753		20,031		660		293		6,597		1,211		3,118		3,797		5,379		753		20,855		660		293
Total Costs Incurred⁴	$	8,506	$	1,602	$	3,452	$	4,736	$	5,017	$	1,006	$	24,319	$	660	$	321	$	8,506	$	1,602	$	3,452	$	4,736	$	5,841	$	1,006	$	25,143	$	660	$	321
Year Ended December 31, 2011
Exploration
Wells	$	321	$	71	$	104	$	146	$	242	$	188	$	1,072	$	—	$	—	$	321	$	71	$	104	$	146	$	242	$	188	$	1,072	$	—	$	—
Geological and geophysical	76		59		65		121		23		43		387		—		—		76		59		65		121		23		43		387		—		—
Rentals and other	109		45		83		67		71		78		453		—		—		109		45		83		67		71		78		453		—		—
Total exploration	506		175		252		334		336		309		1,912		—		—		506		175		252		334		336		309		1,912		—		—
Property acquisitions²
Proved	1,174		16		—		1		—		—		1,191		—		—		1,174		16		—		1		—		—		1,191		—		—
Unproved	7,404		228		—		—		—		25		7,657		—		—		7,404		228		—		—		—		25		7,657		—		—
Total property acquisitions	8,578		244		—		1		—		25		8,848		—		—		8,578		244		—		1		—		25		8,848		—		—
Development³	5,517		1,537		2,698		2,867		2,638		633		15,890		379		368		5,517		1,537		2,698		2,867		2,638		633		15,890		379		368
Total Costs Incurred⁴	$	14,601	$	1,956	$	2,950	$	3,202	$	2,974	$	967	$	26,650	$	379	$	368
Year Ended December 31, 2010
Exploration
Wells	$	99	$	118	$	94	$	244	$	293	$	61	$	909	$	—	$	—
Geological and geophysical	67		46		87		29		8		18		255		—		—
Rentals and other	121		39		55		47		95		57		414		—		—
Total exploration	287		203		236		320		396		136		1,578		—		—
Property acquisitions²
Proved	24		—		—		129		—		—		153		—		—
Unproved	359		429		160		187		—		10		1,145		—		—
Total property acquisitions	383		429		160		316		—		10		1,298		—		—
Development³	4,446		1,611		2,985		3,325		2,623		411		15,401		230		343
Total Costs Incurred	$	5,116	$	2,243	$	3,381	$	3,961	$	3,019	$	557	$	18,277	$	230	$	343	$	14,601	$	1,956	$	2,950	$	3,202	$	2,974	$	967	$	26,650	$	379	$	368


¹	Includes costs incurred whether capitalized or expensed. Excludes general support equipment expenditures. Includes capitalized amounts related to asset retirement obligations. See Note 23, “Asset Retirement Obligations,” on page FS-58.					Includes costs incurred whether capitalized or expensed. Excludes general support equipment expenditures. Includes capitalized amounts related to asset retirement obligations. See Note 24, “Asset Retirement Obligations,” on page FS-56.
²	Includes wells, equipment and facilities associated with proved reserves. Does not include properties acquired in nonmonetary transactions, such as $1,850 million related to the 2012 acquisition of Clio and Acme fields in Australia.					Does not include properties acquired in nonmonetary transactions.
³	Includes $963, $1,035 and $745 costs incurred prior to assignment of proved reserves for consolidated companies in 2012, 2011 and 2010, respectively.					Includes $661, $963 and $1,035 costs incurred prior to assignment of proved reserves for consolidated companies in 2013, 2012 and 2011, respectively.
⁴	Reconciliation of consolidated and affiliated companies total cost incurred to Upstream capital and exploratory (C&E) expenditures - $ billions.					Reconciliation of consolidated and affiliated companies total cost incurred to Upstream capital and exploratory (C&E) expenditures - $ billions.
	Total cost incurred for 2012	$	25.3				2013			2012 ⁵
	Non oil and gas activities	5.8			(Includes LNG and gas-to-liquids $4.6, transportation $0.6, affiliate $0.4, other $0.2)	Total cost incurred	$	33.5		$	26.1
	ARO	(0.7		)		Non-oil and gas activities	5.8			5.0			(Primarily includes LNG, gas-to-liquids and transportation activities)
	Upstream C&E	$	30.4		Reference Page FS-12 upstream total	ARO	(1.4		)	(0.7		)
						Upstream C&E	$	37.9		$	30.4		Reference Page FS-12 Upstream total
⁵						2012 Non-oil and gas allocation revised.

~~FS-62~~FS-59



	Table I Costs Incurred in Exploration, Property Acquisitions and Development - Continued

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

Denmark, the Netherlands, Norway and the United Kingdom. The Other Americas geographic region includes activities primarily in Argentina, Brazil, Canada, Colombia, and Trinidad and Tobago. Amounts for TCO represent Chevron’s 50 percent equity share of Tengizchevroil, an exploration and production partnership in the Republic of Kazakhstan. The affiliated companies Other amounts are composed of the company’s equity interests principally in Venezuela and Angola. Refer to Note ~~11,~~12, beginning on page ~~FS-38,~~FS-37, 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				Consolidated Companies														Affiliated Companies
			Other																		Other
Millions of dollars	U.S.		Americas		Africa		Asia		Australia		Europe		Total		TCO		Other		U.S.		Americas		Africa		Asia		Australia		Europe		Total		TCO		Other
At December 31, 2012
At December 31, 2013
Unproved properties	$	10,478	$	1,415	$	271	$	2,039	$	1,884	$	34	$	16,121	$	109	$	28	$	10,228	$	3,697	$	267	$	2,064	$	1,990	$	36	$	18,282	$	109	$	29
Proved properties and related producing assets	62,274		11,237		30,106		39,889		2,420		9,994		155,920		6,832		1,852		67,837		12,868		32,936		42,780		3,274		9,592		169,287		6,977		3,408
Support equipment	1,179		330		1,195		1,554		1,191		172		5,621		1,089		—		1,314		344		1,180		1,678		1,608		177		6,301		1,166		—
Deferred exploratory wells	412		201		598		326		911		233		2,681		—		—		670		297		536		335		1,134		273		3,245		—		—
Other uncompleted projects	7,203		3,211		3,466		4,123		9,754		768		28,525		906		1,594		9,149		4,175		4,424		5,998		16,000		1,390		41,136		1,638		404
Gross Capitalized Costs	81,546		16,394		35,636		47,931		16,160		11,201		208,868		8,936		3,474		89,198		21,381		39,343		52,855		24,006		11,468		238,251		9,890		3,841
Unproved properties valuation	1,121		634		201		253		2		28		2,239		41		—		1,243		707		203		389		6		31		2,579		45		10
Proved producing properties – Depreciation and depletion	42,224		5,288		15,566		24,432		1,832		8,255		97,597		2,274		551		45,756		5,695		18,051		27,356		2,083		7,825		106,766		2,672		696
Support equipment depreciation	589		178		613		1,101		305		137		2,923		480		—		656		189		647		1,177		384		149		3,202		538		—
Accumulated provisions	43,934		6,100		16,380		25,786		2,139		8,420		102,759		2,795		551		47,655		6,591		18,901		28,922		2,473		8,005		112,547		3,255		706
Net Capitalized Costs	$	37,612	$	10,294	$	19,256	$	22,145	$	14,021	$	2,781	$	106,109	$	6,141	$	2,923	$	41,543	$	14,790	$	20,442	$	23,933	$	21,533	$	3,463	$	125,704	$	6,635	$	3,135
At December 31, 2011
At December 31, 2012 *
Unproved properties	$	9,806	$	1,417	$	368	$	2,408	$	6	$	33	$	14,038	$	109	$	—	$	10,478	$	1,415	$	271	$	2,039	$	1,884	$	34	$	16,121	$	109	$	28
Proved properties and related producing assets	57,674		11,029		25,549		36,740		2,244		9,549		142,785		6,583		1,607		62,274		11,237		30,106		39,889		2,420		9,994		155,920		6,832		1,852
Support equipment	1,071		292		1,362		1,544		533		169		4,971		1,018		—		1,179		330		1,195		1,554		1,191		172		5,621		1,089		—
Deferred exploratory wells	565		63		629		260		709		208		2,434		—		—		412		201		598		326		911		233		2,681		—		—
Other uncompleted projects	4,887		2,408		4,773		3,109		6,076		492		21,745		605		1,466		7,203		3,211		3,466		4,123		10,578		768		29,349		906		1,594
Gross Capitalized Costs	74,003		15,209		32,681		44,061		9,568		10,451		185,973		8,315		3,073		81,546		16,394		35,636		47,931		16,984		11,201		209,692		8,936		3,474
Unproved properties valuation	1,085		498		178		262		2		13		2,038		38		—		1,121		634		201		253		2		28		2,239		41		—
Proved producing properties – Depreciation and depletion	39,210		4,826		13,173		20,991		1,574		7,742		87,516		1,910		436		42,224		5,288		15,566		24,432		1,832		8,255		97,597		2,274		551
Support equipment depreciation	530		175		715		1,192		238		129		2,979		451		—		589		178		613		1,101		305		137		2,923		480		—
Accumulated provisions	40,825		5,499		14,066		22,445		1,814		7,884		92,533		2,399		436		$	43,934	$	6,100	$	16,380	$	25,786	$	2,139	$	8,420	$	102,759	$	2,795	$	551
Net Capitalized Costs	$	33,178	$	9,710	$	18,615	$	21,616	$	7,754	$	2,567	$	93,440	$	5,916	$	2,637	$	37,612	$	10,294	$	19,256	$	22,145	$	14,845	$	2,781	$	106,933	$	6,141	$	2,923
* 2012 Non-oil and gas allocation revised.																			* 2012 Non-oil and gas allocation revised.

~~FS-63~~FS-60



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


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

~~FS-64~~FS-61



	Table IIIResults of Operations for Oil and Gas Producing Activities¹

The company’s results of operations from oil and gas producing activities for the years ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011 are shown in the following table. Net income from exploration and production activities as reported on page ~~FS-37~~FS-36 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-37.~~FS-36.

Table III - Results of Operations for Oil and Gas Producing Activities ¹


	Consolidated Companies																					Affiliated Companies						Consolidated Companies																					Affiliated Companies
				Other																											Other
Millions of dollars	U.S.			Americas			Africa			Asia			Australia			Europe			Total			TCO			Other			U.S.			Americas			Africa			Asia			Australia			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
Year Ended December 31, 2012
Revenues from net production
Sales	$	1,832		$	1,561		$	1,480		$	10,485		$	1,539		$	1,618		$	18,515		$	7,869		$	1,951		$	1,832		$	1,561		$	1,480		$	10,485		$	1,539		$	1,618		$	18,515		$	7,869		$	1,951
Transfers	15,122			1,997			15,033			9,071			1,073			2,148			44,444			—			—			15,122			1,997			15,033			9,071			1,073			2,148			44,444			—			—
Total	16,954			3,558			16,513			19,556			2,612			3,766			62,959			7,869			1,951			16,954			3,558			16,513			19,556			2,612			3,766			62,959			7,869			1,951
Production expenses excluding taxes	(4,009		)	(1,073		)	(1,918		)	(4,545		)	(164		)	(637		)	(12,346		)	(463		)	(442		)	(4,009		)	(1,073		)	(1,918		)	(4,545		)	(164		)	(637		)	(12,346		)	(463		)	(442		)
Taxes other than on income	(654		)	(123		)	(161		)	(191		)	(390		)	(3		)	(1,522		)	(439		)	(767		)	(654		)	(123		)	(161		)	(191		)	(390		)	(3		)	(1,522		)	(439		)	(767		)
Proved producing properties:
Depreciation and depletion	(3,462		)	(508		)	(2,475		)	(3,399		)	(315		)	(541		)	(10,700		)	(427		)	(147		)	(3,462		)	(508		)	(2,475		)	(3,399		)	(315		)	(541		)	(10,700		)	(427		)	(147		)
Accretion expense²	(226		)	(33		)	(66		)	(92		)	(23		)	(46		)	(486		)	(8		)	(6		)	(226		)	(33		)	(66		)	(92		)	(23		)	(46		)	(486		)	(8		)	(6		)
Exploration expenses	(244		)	(145		)	(427		)	(489		)	(133		)	(272		)	(1,710		)	—			—			(244		)	(145		)	(427		)	(489		)	(133		)	(272		)	(1,710		)	—			—
Unproved properties valuation	(127		)	(138		)	(16		)	(133		)	—			(15		)	(429		)	—			—			(127		)	(138		)	(16		)	(133		)	—			(15		)	(429		)	—			—
Other income (expense)³	167			(169		)	(199		)	245			2,495			13			2,552			27			31			167			(169		)	(199		)	245			2,495			13			2,552			27			31
Results before income taxes	8,399			1,369			11,251			10,952			4,082			2,265			38,318			6,559			620			8,399			1,369			11,251			10,952			4,082			2,265			38,318			6,559			620
Income tax expense	(3,043		)	(310		)	(7,558		)	(5,739		)	(1,226		)	(1,511		)	(19,387		)	(1,972		)	(299		)	(3,043		)	(310		)	(7,558		)	(5,739		)	(1,226		)	(1,511		)	(19,387		)	(1,972		)	(299		)
Results of Producing Operations	$	5,356		$	1,059		$	3,693		$	5,213		$	2,856		$	754		$	18,931		$	4,587		$	321		$	5,356		$	1,059		$	3,693		$	5,213		$	2,856		$	754		$	18,931		$	4,587		$	321
Year Ended December 31, 2011 ⁴
Revenues from net production
Sales	$	2,508		$	2,047		$	1,174		$	9,431		$	1,474		$	1,868		$	18,502		$	8,581		$	1,988
Transfers	15,811			2,624			15,726			8,962			1,012			2,672			46,807			—			—
Total	18,319			4,671			16,900			18,393			2,486			4,540			65,309			8,581			1,988
Production expenses excluding taxes	(3,668		)	(1,061		)	(1,526		)	(4,489		)	(117		)	(564		)	(11,425		)	(449		)	(235		)
Taxes other than on income	(597		)	(137		)	(153		)	(242		)	(396		)	(2		)	(1,527		)	(429		)	(815		)
Proved producing properties:
Depreciation and depletion	(3,366		)	(796		)	(2,225		)	(2,923		)	(136		)	(580		)	(10,026		)	(442		)	(140		)
Accretion expense²	(291		)	(27		)	(106		)	(81		)	(18		)	(39		)	(562		)	(8		)	(4		)
Exploration expenses	(207		)	(144		)	(188		)	(271		)	(128		)	(277		)	(1,215		)	—			—
Unproved properties valuation	(134		)	(146		)	(27		)	(60		)	—			(14		)	(381		)	—			—
Other income (expense)³	163			(466		)	(409		)	231			(18		)	(74		)	(573		)	(8		)	(29		)
Results before income taxes	10,219			1,894			12,266			10,558			1,673			2,990			39,600			7,245			765
Income tax expense	(3,728		)	(535		)	(7,802		)	(5,374		)	(507		)	(1,913		)	(19,859		)	(2,176		)	(392		)
Results of Producing Operations	$	6,491		$	1,359		$	4,464		$	5,184		$	1,166		$	1,077		$	19,741		$	5,069		$	373


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 ~~23,~~24, “Asset Retirement Obligations,” on page ~~FS-58.~~FS-56.


³	Includes foreign currency gains and losses, gains and losses on property dispositions ~~(primarily related to Browse and Wheatstone gains in 2012),~~ and other miscellaneous income and expenses.


⁴	~~2011 and 2010 conformed to 2012 presentation.~~

~~FS-65~~FS-62



	Table IIIResults of Operations for Oil and Gas Producing Activities¹ - Continued

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


	Consolidated Companies																					Affiliated Companies						Consolidated Companies																					Affiliated Companies
				Other																											Other
Millions of dollars	U.S.			Americas			Africa			Asia			Australia			Europe			Total			TCO			Other			U.S.			Americas			Africa			Asia			Australia			Europe			Total			TCO			Other
Year Ended December 31, 2010 ⁴
Year Ended December 31, 2011
Revenues from net production
Sales	$	2,540		$	1,881		$	2,278		$	7,221		$	994		$	1,519		$	16,433		$	6,031		$	1,307		$	2,508		$	2,047		$	1,174		$	9,431		$	1,474		$	1,868		$	18,502		$	8,581		$	1,988
Transfers	12,172			1,147			10,306			6,242			985			2,138			32,990			—			—			15,811			2,624			15,726			8,962			1,012			2,672			46,807			—			—
Total	14,712			3,028			12,584			13,463			1,979			3,657			49,423			6,031			1,307			18,319			4,671			16,900			18,393			2,486			4,540			65,309			8,581			1,988
Production expenses excluding taxes	(3,338		)	(805		)	(1,413		)	(2,996		)	(96		)	(534		)	(9,182		)	(347		)	(152		)	(3,668		)	(1,061		)	(1,526		)	(4,489		)	(117		)	(564		)	(11,425		)	(449		)	(235		)
Taxes other than on income	(542		)	(102		)	(130		)	(85		)	(334		)	(2		)	(1,195		)	(360		)	(101		)	(597		)	(137		)	(153		)	(242		)	(396		)	(2		)	(1,527		)	(429		)	(815		)
Proved producing properties:
Depreciation and depletion	(3,639		)	(907		)	(2,204		)	(2,816		)	(151		)	(681		)	(10,398		)	(432		)	(131		)	(3,366		)	(796		)	(2,225		)	(2,923		)	(136		)	(580		)	(10,026		)	(442		)	(140		)
Accretion expense²	(240		)	(23		)	(102		)	(35		)	(15		)	(53		)	(468		)	(8		)	(5		)	(291		)	(27		)	(106		)	(81		)	(18		)	(39		)	(562		)	(8		)	(4		)
Exploration expenses	(193		)	(173		)	(242		)	(289		)	(175		)	(75		)	(1,147		)	(5		)	—			(207		)	(144		)	(188		)	(271		)	(128		)	(277		)	(1,215		)	—			—
Unproved properties valuation	(123		)	(71		)	(25		)	(33		)	—			(2		)	(254		)	—			—			(134		)	(146		)	(27		)	(60		)	—			(14		)	(381		)	—			—
Other income (expense)³	(154		)	(367		)	(103		)	(282		)	109			165			(632		)	(65		)	191			163			(466		)	(409		)	231			(18		)	(74		)	(573		)	(8		)	(29		)
Results before income taxes	6,483			580			8,365			6,927			1,317			2,475			26,147			4,814			1,109			10,219			1,894			12,266			10,558			1,673			2,990			39,600			7,245			765
Income tax expense	(2,273		)	(223		)	(4,535		)	(3,886		)	(325		)	(1,455		)	(12,697		)	(1,445		)	(615		)	(3,728		)	(535		)	(7,802		)	(5,374		)	(507		)	(1,913		)	(19,859		)	(2,176		)	(392		)
Results of Producing Operations	$	4,210		$	357		$	3,830		$	3,041		$	992		$	1,020		$	13,450		$	3,369		$	494		$	6,491		$	1,359		$	4,464		$	5,184		$	1,166		$	1,077		$	19,741		$	5,069		$	373


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 ~~23,~~24, “Asset Retirement Obligations,” on page ~~FS-58.~~FS-56.


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


^{4 Table IV - Results of Operations for Oil and Gas Producing Activities - Unit Prices and Costs ¹}	~~2011 and 2010 conformed to 2012 presentation.~~

~~FS-66~~



	~~Table IV~~ ~~Results of Operations for Oil and~~ ~~Gas Producing Activities - Unit Prices and Costs~~¹


	Consolidated Companies														Affiliated Companies				Consolidated Companies														Affiliated Companies
			Other																		Other
	U.S.		Americas		Africa		Asia		Australia		Europe		Total		TCO		Other		U.S.		Americas		Africa		Asia		Australia		Europe		Total		TCO		Other
Year Ended December 31, 2013
Average sales prices
Liquids, per barrel																			$	93.46	$	88.32	$	107.22	$	98.37	$	103.28	$	105.78	$	99.05	$	88.06	$	78.87
Natural gas, per thousand cubic feet																			3.38		2.68		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
Year Ended December 31, 2012
Average sales prices
Liquids, per barrel	$	95.21	$	87.87	$	109.64	$	102.46	$	103.06	$	108.77	$	101.61	$	89.34	$	83.97	$	95.21	$	87.87	$	109.64	$	102.46	$	103.06	$	108.77	$	101.61	$	89.34	$	83.97
Natural gas, per thousand cubic feet	2.65		3.59		1.22		6.03		10.99		10.10		5.42		1.36		5.39		2.65		3.59		1.22		6.03		10.99		10.10		5.42		1.36		5.39
Average production costs, per barrel²	16.99		18.38		12.14		16.71		4.86		15.72		15.46		4.42		18.73		16.99		18.38		12.14		16.71		4.86		15.72		15.46		4.42		18.73
Year Ended December 31, 2011 ³
Year Ended December 31, 2011
Average sales prices
Liquids, per barrel	$	97.51	$	89.87	$	109.45	$	100.55	$	103.70	$	107.11	$	101.63	$	94.60	$	90.90	$	97.51	$	89.87	$	109.45	$	100.55	$	103.70	$	107.11	$	101.63	$	94.60	$	90.90
Natural gas, per thousand cubic feet	4.02		2.97		0.41		5.28		9.98		9.91		5.29		1.60		6.57		4.02		2.97		0.41		5.28		9.98		9.91		5.29		1.60		6.57
Average production costs, per barrel²	15.08		14.62		9.48		17.47		3.41		11.44		13.98		4.23		10.54		15.08		14.62		9.48		17.47		3.41		11.44		13.98		4.23		10.54
Year Ended December 31, 2010³
Average sales prices
Liquids, per barrel	$	71.59	$	66.22	$	78.00	$	70.96	$	76.43	$	76.10	$	73.24	$	63.94	$	64.92
Natural gas, per thousand cubic feet	4.25		2.52		0.73		4.45		6.76		7.09		4.55		1.41		4.20
Average production costs, per barrel²	13.11		11.86		8.57		11.71		2.55		9.42		10.96		3.14		7.37


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.

FS-63



³Table V Reserve Quantity Information	~~2011 and 2010 conformed to 2012 presentation.~~

Table V Reserve Quantity Information

Summary of Net Oil and Gas Reserves



	2013			2012			2011
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.	976	—	2,632	1,012	—	2,574	990	—	2,486
Other Americas	109	403	943	91	391	1,063	82	403	1,147
Africa	763	—	1,161	782	—	1,163	792	—	1,276
Asia	601	—	4,620	643	—	4,511	703	—	4,300
Australia	44	—	1,251	31	—	682	39	—	813
Europe	94	—	200	103	—	191	116	—	204
Total Consolidated	2,587	403	10,807	2,662	391	10,184	2,722	403	10,226
Affiliated Companies
TCO	884	—	1,188	977	—	1,261	1,019	—	1,400
Other	105	44	330	115	50	377	93	50	75
Total Consolidated and Affiliated Companies	3,576	447	12,325	3,754	441	11,822	3,834	453	11,701
Proved Undeveloped
Consolidated Companies
U.S.	354	—	1,358	347	—	1,148	321	—	1,160
Other Americas	134	134	357	132	122	412	31	120	517
Africa	341	—	1,884	348	—	1,918	363	—	1,920
Asia	191	—	2,125	194	—	2,356	191	—	2,421
Australia	87	—	9,076	103	—	9,570	101	—	8,931
Europe	72	—	63	54	—	66	43	—	54
Total Consolidated	1,179	134	14,863	1,178	122	15,470	1,050	120	15,003
Affiliated Companies
TCO	784	—	1,102	755	—	1,038	740	—	851
Other	49	176	856	49	182	865	64	194	1,128
Total Consolidated and Affiliated Companies	2,012	310	16,821	1,982	304	17,373	1,854	314	16,982
Total Proved Reserves	5,588	757	29,146	5,736	745	29,195	5,688	767	28,683

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.

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 reports directly to the Vice Chairman responsible for the company’s worldwide exploration and production activities. 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

FS-64



Table V Reserve Quantity Information - Continued

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 1510 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 reserves activities are managed by two operating company-level reserves managers. These two reserves managers are not members of the RAC so as to preserve corporate-level independence.

~~FS-67~~



~~Table V~~ ~~Reserve Quantity Information - Continued~~

~~Summary of Net Oil and Gas Reserves~~

2012* 2011* 2010*
Liquids in Millions of Barrels Crude Oil

Crude Oil

Crude Oil

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. 1,012

—

2,574

990

—

2,486

1,045

—

2,113
   Other Americas 91

391

1,063

82

403

1,147

84

352

1,490
   Africa 782

—

1,163

792

—

1,276

830

—

1,304
   Asia 643

—

4,511

703

—

4,300

826

—

4,836
   Australia 31

—

682

39

—

813

39

—

881
   Europe 103

—

191

116

—

204

136

—

235
Total Consolidated 2,662

391

10,184

2,722
403
10,226

2,960

352

10,859
   Affiliated Companies

   TCO 977

—

1,261

1,019

—

1,400

1,128

—

1,484
   Other 115

50

377

93

50

75

95

53

70
Total Consolidated and Affiliated Companies 3,754

441

11,822

3,834
453
11,701

4,183

405

12,413
Proved Undeveloped

   Consolidated Companies

   U.S. 347

—

1,148

321

—

1,160

230

—

359
   Other Americas 132

122

412

31

120

517

24

114

325
   Africa 348

—

1,918

363

—

1,920

338

—

1,640
   Asia 194

—

2,356

191

—

2,421

187

—

2,357
   Australia 103

—

9,570

101

—

8,931

49

—

5,175
   Europe 54

—

66

43

—

54

16

—

40
Total Consolidated 1,178
122
15,470
1,050
120
15,003

844

114

9,896
   Affiliated Companies

   TCO 755

—

1,038

740

—

851

692

—

902
   Other 49

182

865

64

194

1,128

62

203

1,040
Total Consolidated and Affiliated Companies 1,982
304
17,373
1,854
314
16,982

1,598

317

11,838
Total Proved Reserves 5,736

745

29,195

5,688
767
28,683

5,781

722

24,251


*	~~Based on 12-month average price.~~

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 ~~2012~~2013, 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.

~~FS-68~~



~~Table V~~ ~~Reserve Quantity Information - Continued~~

Proved Undeveloped Reserve Quantities At the end of ~~2012~~2013, proved undeveloped reserves totaled ~~5.2~~5.1 billion barrels of oil-equivalent (BOE). Approximately 56 percent of these reserves are attributed to natural gas, of which about 55 percent were located in Australia. Crude oil, condensate and natural gas liquids (NGLs) accounted for about 38 percent of the total proved undeveloped reserves, of which about 38 percent were from TCO, and the remaining large concentrations were in Africa, Asia and the United States. Synthetic oil accounted for the balance of the proved undeveloped reserves.

In ~~2012~~, a ~~total~~decrease of ~~394~~56 million BOE from year-end 2012. The decrease was ~~transferred from proved undeveloped~~due to ~~proved developed. In Asia, 98~~the transfer of 461 million BOE ~~were transferred~~ to proved developed, ~~primarily driven~~partially offset by ~~development drilling performance. In the United States, approximately 95~~increases of 210 BOE in extensions and discoveries, 7 million BOE ~~were transferred, primarily due to ongoing drilling activities~~ in ~~the deepwater Gulf of Mexico and California. Affiliates accounted for 104~~purchases, 42 million BOE ~~transferred to proved developed due to ongoing development activities. Development drilling~~in improved recovery and ~~the start up of several projects~~146 million BOE in ~~Africa, Europe and Other Americas accounted for the remainder.~~revisions.

Investment to Convert Proved Undeveloped to Proved Developed Reserves During ~~2012~~2013, investments totaling approximately ~~$10.7~~$17.4 billion in oil and gas producing activities and about ~~$3.5~~$3.4 billion in non-oil and gas producing activities were expended to advance the development of proved undeveloped reserves. Australia accounted for ~~$7.7~~$9.6 billion of the total, mainly for development and construction activities at the Gorgon and Wheatstone LNG projects. ~~In Africa, another $2.3 billion was expended on various offshore development and natural gas projects in Nigeria and Angola.~~ Expenditures of about ~~$1.8~~$3.5 billion in the United States related primarily to various development activities in the Gulf of Mexico and the ~~mid-continent~~midcontinent region. In Asia, expenditures during the year totaled ~~$1.7~~$3.0 billion, primarily related to development projects in Thailand, Indonesia and ~~Indonesia.~~with the TCO affiliate in Kazakhstan. In Africa, about $2.9 billion was expended on various offshore development and natural gas projects in Nigeria and Angola.

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

FS-65



Table V Reserve Quantity Information - Continued

At year-end ~~2012~~2013, the company held approximately ~~1.7~~1.6 billion BOE of proved undeveloped reserves that have remained undeveloped for five years or more. The reserves are held by consolidated and affiliated companies and the majority of these reserves are in locations where the company has a proven track record of developing major projects.

In Africa, the majority of the approximately 300 million BOE of proved undeveloped reserves that have remained undeveloped for five years or more is related to deepwater and natural gas developments in Nigeria. Major Nigerian deepwater development projects include Agbami, which started production in 2008 and has ongoing development activities to maintain full utilization of infrastructure capacity, and the Usan development, which started production in 2012. Also in Nigeria, various fields and infrastructure associated with the Escravos ~~Gas Projects~~gas projects are currently under development.

In Asia, ~~approximately~~less than 200 million BOE remain classified as proved undeveloped ~~after~~for more than five years. The majority relate to ongoing development activities in the Pattani Field ~~(Thailand)~~in Thailand and the ~~Malampaya Field (Philippines) that are scheduled to maintain production within contractual and infrastructure constraints.~~Azeri-Chirag-Gunashli fields in Azerbaijan.

~~In Australia, approximately 100 million BOE remain classified as proved undeveloped due to a compression project at the North West Shelf Venture, which is scheduled~~Affiliates account for ~~start-up in 2013.~~

~~Affiliated companies have approximately 1.0~~1.1 billion ~~BOE~~barrels of proved undeveloped reserves that have ~~been recorded~~remained undeveloped for five years or ~~more. The~~more, with the majority related to the TCO affiliate in ~~Kazakhstan accounts for most of this amount. Production~~Kazakhstan. At TCO, further field development to convert the remaining proved undeveloped reserves is ~~constrained by plant capacity limitations.~~scheduled to occur in line with reservoir depletion. In Venezuela, development drilling continues at Hamaca to optimize utilization of upgrader capacity.

Annually, the company assesses whether any changes have occurred in facts or circumstances, such as changes to development plans, regulations or government policies, that would warrant a revision to reserve estimates. For ~~2012~~2013, 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 3744 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 At December 31, ~~2012~~2013, proved reserves for the company were ~~11.3~~11.2 billion BOE. ~~(Refer to the term “Reserves” on page E-11 for the definition of oil-equivalentreserves.)~~ Approximately 1718 percent of the total reserves were located in the United States.

Aside from the TCO affiliate's Tengiz Field in Kazakhstan, no single property accounted for more than 5 percent of the company’s total oil-equivalent proved reserves. About 2018 other individual properties in the company’s portfolio of assets each contained between 1 percent and 5 percent of the company’s oil-equivalent proved reserves, which in the aggregate accounted for 4544 percent of the company’s total oil-equivalent proved reserves. These properties were geographically dispersed, located in the United States, Canada, South America, Africa, Asia and Australia.

~~FS-69~~



~~Table V~~ ~~Reserve Quantity Information - Continued~~

In the United States, total proved reserves at year-end ~~2012~~2013 were 2.0 billion BOE. California properties accounted for 3230 percent of the U.S. reserves, with most classified as heavy oil. Because of heavy oil’s high viscosity and the need to employ enhanced recovery methods, most of the company’s ~~heavy-oil~~heavy oil fields in California employ a continuous steamflooding process. The Gulf of Mexico region contains 26 percent of the U.S. reserves and production operations are mostly offshore. Other U.S. areas represent the remaining 4244 percent of U.S. reserves. For production of crude oil, some fields utilize enhanced recovery methods, including ~~waterflood~~waterflooding and CO₂ injection.

For the three years ending December 31, ~~2012~~2013, 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 iscan be affected by, among other things, events and circumstances that are outside the company’s control, such as delays in government permitting, partner approvals of development plans, changes in oil and gas prices, OPEC constraints, geopolitical uncertainties, and civil unrest.

The company’s estimated net proved reserves of crude oil, condensate, natural gas liquids and synthetic oil and changes thereto for the years ~~2010~~2011, ~~2011~~2012 and ~~2012~~2013 are shown in the table ~~below.~~on page FS-67. The company’s estimated net proved reserves of natural gas are shown on page ~~FS-72.~~FS-68.

FS-66



Table V Reserve Quantity Information - Continued

Net Proved Reserves (Developed and Undeveloped) of Crude Oil, Condensate, Natural Gas Liquids and Synthetic Oil


	Consolidated Companies																Affiliated Companies						Total Consolidated		Consolidated Companies																Affiliated Companies						Total Consolidated
			Other										Synthetic						Synthetic				and Affiliated				Other										Synthetic						Synthetic				and Affiliated
Millions of barrels	U.S.		Americas¹		Africa		Asia		Australia		Europe		Oil²		Total		TCO		Oil		Other³		Companies		U.S.		Americas¹		Africa		Asia		Australia		Europe		Oil²		Total		TCO		Oil		Other³		Companies
Reserves at January 1, 2010	1,361		104		1,246		1,171		98		170		460		4,610		1,946		266		151		6,973
Changes attributable to:
Revisions	63		12		17		(26	)	3		19		15		103		(33	)	—		12		82
Improved recovery	11		3		58		2		—		—		—		74		—		—		3		77
Extensions and discoveries	19		19		9		16		—		—		—		63		—		—		—		63
Purchases	—		—		—		11		—		—		—		11		—		—		—		11
Sales	(1	)	—		—		—		—		—		—		(1	)	—		—		—		(1	)
Production	(178	)	(30	)	(162	)	(161	)	(13	)	(37	)	(9	)	(590	)	(93	)	(10	)	(9	)	(702	)
Reserves at December 31, 2010⁴	1,275		108		1,168		1,013		88		152		466		4,270		1,820		256		157		6,503
Reserves at January 1, 2011																									1,275		108		1,168		1,013		88		152		466		4,270		1,820		256		157		6,503
Changes attributable to:
Revisions	63		4		60		25		(2	)	15		32		197		28		—		10		235		63		4		60		25		(2	)	15		32		197		28		—		10		235
Improved recovery	6		4		48		—		—		—		—		58		—		—		—		58		6		4		48		—		—		—		—		58		—		—		—		58
Extensions and discoveries	140		30		34		4		65		26		—		299		—		—		—		299		140		30		34		4		65		26		—		299		—		—		—		299
Purchases	2		—		—		—		—		—		40		42		—		—		—		42		2		—		—		—		—		—		40		42		—		—		—		42
Sales	(5	)	—		—		—		(1	)	—		—		(6	)	—		—		—		(6	)	(5	)	—		—		—		(1	)	—		—		(6	)	—		—		—		(6	)
Production	(170	)	(33	)	(155	)	(148	)	(10	)	(34	)	(15	)	(565	)	(89	)	(12	)	(10	)	(676	)	(170	)	(33	)	(155	)	(148	)	(10	)	(34	)	(15	)	(565	)	(89	)	(12	)	(10	)	(676	)
Reserves at December 31, 2011⁴	1,311		113		1,155		894		140		159		523		4,295		1,759		244		157		6,455		1,311		113		1,155		894		140		159		523		4,295		1,759		244		157		6,455
Changes attributable to:
Revisions	104		20		66		97		4		16		6		313		59		(6	)	24		390		104		20		66		97		4		16		6		313		59		(6	)	24		390
Improved recovery	24		8		30		6		—		9		—		77		—		—		—		77		24		8		30		6		—		9		—		77		—		—		—		77
Extensions and discoveries	77		101		30		2		7		—		—		217		—		—		1		218		77		101		30		2		7		—		—		217		—		—		1		218
Purchases	10		—		—		—		—		—		—		10		—		—		—		10		10		—		—		—		—		—		—		10		—		—		—		10
Sales	(1	)	—		—		(15	)	(7	)	—		—		(23	)	—		—		—		(23	)	(1	)	—		—		(15	)	(7	)	—		—		(23	)	—		—		—		(23	)
Production	(166	)	(19	)	(151	)	(147	)	(10	)	(27	)	(16	)	(536	)	(86	)	(6	)	(18	)	(646	)	(166	)	(19	)	(151	)	(147	)	(10	)	(27	)	(16	)	(536	)	(86	)	(6	)	(18	)	(646	)
Reserves at December 31, 2012⁴	1,359		223		1,130		837		134		157		513		4,353		1,732		232		164		6,481		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


¹	Ending reserve balances in North America were ~~121~~141, 13121 and 1413 and in South America were 102, ~~100~~102 and 94100 in ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011, respectively.


²	Reserves associated with Canada.


³	Ending reserve balances in Africa were 4137, 3841 and 3638 and in South America were ~~123~~117, ~~119~~123 and ~~121~~119 in ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011, respectively.


⁴	Included are year-end reserve quantities related to production-sharing contracts (PSC) (refer to page E-11 for the definition of a PSC). PSC-related reserve quantities are 20 percent, 2220 percent and 2422 percent for consolidated companies for ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011, respectively.

~~FS-70~~



~~Table V~~ ~~Reserve Quantity Information - Continued~~

Noteworthy amounts in the categories of liquids proved reserve changes for ~~2010~~2011 through ~~2012~~2013 are discussed below:

Revisions In 2010, net revisions increased reserves 82 million barrels. For consolidated companies, improved reservoir performance accounted for a majority of the 63 million barrel increase in the United States. Increases in the other regions were partially offset by Asia, which decreased as a result of the effect of higher prices on entitlement volumes in Kazakhstan. For affiliated companies, the price effect on entitlement volumes at TCO decreased reserves by 33 million barrels.

In 2011, net revisions increased reserves 235 million barrels. For consolidated companies, improved reservoir performance accounted for a majority of the 63 million barrel increase in the United States. In Africa, improved field performance drove the 60 million barrel increase. In Asia, increases from improved reservoir performance were partially offset by the effects of higher prices on entitlement volumes. Synthetic oil reserves in Canada increased by 32 million barrels, primarily due to geotechnical revisions. For affiliated companies, improved facility and reservoir performance was partially offset by the price effect on entitlement volumes at TCO.

In 2012, net revisions increased reserves 390 million barrels. Improved field performance and drilling associated with Gulf of Mexico projects accounted for the majority of the 104 million barrel increase in the United States. In Asia, drilling results across numerous assets drove the 97 million barrel increase. Improved field performance from various Nigeria and Angola producing assets was primarily responsible for the 66 million barrel increase

in Africa. Improved plant efficiency for the TCO affiliate was responsible for a large portion of the 59 million barrel increase.

In 2013, net revisions increased reserves 354 million barrels. 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.

Improved Recovery ~~In 2010, improved recovery increased volumes by 77 million barrels. Reserves in Africa increased 58 million barrels due primarily to secondary recovery performance in Nigeria.~~

In 2011, improved recovery increased volumes by 58 million barrels. Reserves in Africa increased 48 million barrels due primarily to secondary recovery performance in Nigeria.

In 2012, improved recovery increased reserves by 77 million barrels, primarily due to secondary recovery performance in Africa and in Gulf of Mexico fields in the United States.

~~Extensions and Discoveries~~

FS-67



Table V Reserve Quantity Information - Continued

In ~~2010, extensions and discoveries~~2013, improved recovery increased reserves ~~63 million barrels. The United States and Other Americas each increased reserves 19~~by 57 million barrels ~~and Asia increased reserves 16 million barrels. No single area~~due to numerous small projects, including expansions of existing projects in the United States, ~~was individually significant. Drilling activity in Argentina~~Europe, Asia, and ~~Brazil accounted for the majority of the increase in Other Americas. In Asia, the increase was primarily related to activity in Azerbaijan.~~Africa.

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

In 2012, extensions and discoveries increased reserves 218 million barrels. In Other Americas, extensions and discoveries

increased reserves 101 million barrels, primarily due to the initial booking of the Hebron project in Canada. In the United States, additions at several Gulf of Mexico projects and drilling activities in the mid-continent region were primarily responsible for the 77 million barrel increase.

In 2013, extensions and discoveries increased reserves 78 million barrels. In the United States, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 55 million barrel increase.

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

~~FS-71~~



~~Table V~~ ~~Reserve Quantity Information - Continued~~

Net Proved Reserves of Natural Gas


	Consolidated Companies														Affiliated Companies				Total Consolidated		Consolidated Companies														Affiliated Companies				Total Consolidated
			Other																and Affiliated				Other																and Affiliated
Billions of cubic feet (BCF)	U.S.		Americas¹		Africa		Asia		Australia		Europe		Total		TCO		Other²		Companies		U.S.		Americas¹		Africa		Asia		Australia		Europe		Total		TCO		Other²		Companies
Reserves at January 1, 2010	2,698		1,985		3,021		7,860		6,245		344		22,153		2,833		1,063		26,049
Changes attributable to:
Revisions	220		4		(20	)	(31	)	(22	)	46		197		(324	)	56		(71	)
Improved recovery	1		1		—		—		—		—		2		—		—		2
Extensions and discoveries	36		4		—		59		—		11		110		—		—		110
Purchases	3		—		—		4		—		—		7		—		—		7
Sales	(7	)	—		—		—		—		—		(7	)	—		—		(7	)
Production³	(479	)	(179	)	(57	)	(699	)	(167	)	(126	)	(1,707	)	(123	)	(9	)	(1,839	)
Reserves at December 31, 2010⁴	2,472		1,815		2,944		7,193		6,056		275		20,755		2,386		1,110		24,251
Reserves at January 1, 2011																					2,472		1,815		2,944		7,193		6,056		275		20,755		2,386		1,110		24,251
Changes attributable to:
Revisions	217		(4	)	39		196		(107	)	74		415		(21	)	103		497		217		(4	)	39		196		(107	)	74		415		(21	)	103		497
Improved recovery	—		1		—		—		—		—		1		—		—		1		—		1		—		—		—		—		1		—		—		1
Extensions and discoveries	287		13		290		46		4,035		9		4,680		—		—		4,680		287		13		290		46		4,035		9		4,680		—		—		4,680
Purchases	1,231		—		—		2		—		—		1,233		—		—		1,233		1,231		—		—		2		—		—		1,233		—		—		1,233
Sales	(95	)	—		—		(2	)	(77	)	—		(174	)	—		—		(174	)	(95	)	—		—		(2	)	(77	)	—		(174	)	—		—		(174	)
Production³	(466	)	(161	)	(77	)	(714	)	(163	)	(100	)	(1,681	)	(114	)	(10	)	(1,805	)	(466	)	(161	)	(77	)	(714	)	(163	)	(100	)	(1,681	)	(114	)	(10	)	(1,805	)
Reserves at December 31, 2011⁴	3,646		1,664		3,196		6,721		9,744		258		25,229		2,251		1,203		28,683		3,646		1,664		3,196		6,721		9,744		258		25,229		2,251		1,203		28,683
Changes attributable to:
Revisions	318		(77	)	(30	)	1,007		358		84		1,660		158		37		1,855		318		(77	)	(30	)	1,007		358		84		1,660		158		37		1,855
Improved recovery	5		—		—		1		—		2		8		—		—		8		5		—		—		1		—		2		8		—		—		8
Extensions and discoveries	166		34		2		50		747		—		999		—		12		1,011		166		34		2		50		747		—		999		—		12		1,011
Purchases	33		—		—		—		—		—		33		—		—		33		33		—		—		—		—		—		33		—		—		33
Sales	(6	)	—		—		(93	)	(439	)	—		(538	)	—		—		(538	)	(6	)	—		—		(93	)	(439	)	—		(538	)	—		—		(538	)
Production³	(440	)	(146	)	(87	)	(819	)	(158	)	(87	)	(1,737	)	(110	)	(10	)	(1,857	)	(440	)	(146	)	(87	)	(819	)	(158	)	(87	)	(1,737	)	(110	)	(10	)	(1,857	)
Reserves at December 31, 2012⁴	3,722		1,475		3,081		6,867		10,252		257		25,654		2,299		1,242		29,195		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, 2013⁴																					3,990		1,300		3,045		6,745		10,327		263		25,670		2,290		1,186		29,146


¹	Ending reserve balances in North America and South America were 54, 49, 19, and 211,246 ~~and~~, 1,426, 1,645, ~~1,794~~ in ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011, respectively.


²	Ending reserve balances in Africa and South America were 1,009, 1,068, 1,016, and ~~953~~177 ~~and~~, 174, 187, ~~157~~ in ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011, respectively.


³	Total “as sold” volumes are ~~1,647~~1,704 BCF, ~~1,591~~1,666 BCF and ~~1,644~~1,615 BCF for ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011, respectively. 2011 and 2012 conformed to 2013 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 2120 percent, 21 percent and 2921 percent for consolidated companies for ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011, respectively.

FS-68



Table V Reserve Quantity Information - Continued

Noteworthy amounts in the categories of natural gas proved-reserve changes for ~~2010~~2011 through ~~2012~~2013 are discussed below:

Revisions In 2010, net revisions decreased reserves by 71 BCF. For consolidated companies, a net increase in the United States of 220 BCF, primarily in the mid-continent area and the Gulf of Mexico, was the result of a number of small upward revisions related to improved reservoir performance and drilling activity, none of which were individually significant. The increase was partially offset by downward revisions due to the impact of higher prices on entitlement volumes in Asia. For equity affiliates, a downward revision of 324 BCF at TCO was due to the price effect on entitlement volumes and a change in the variable-royalty calculation. This decline was partially offset

~~by the recognition of additional reserves related to the Angola LNG project.~~

In 2011, net revisions increased reserves 497 BCF. For consolidated companies, improved reservoir performance accounted for a majority of the 217 BCF increase in the United States. In Asia, a net increase of 196 BCF was driven by development drilling and improved field performance in Thailand, partially offset by the effects of higher prices on entitlement volumes in Kazakhstan. For affiliated companies, ongoing reservoir assessment resulted in the recognition of additional reserves related to the Angola LNG project. At TCO, improved facility and reservoir performance was more than offset by the price effect on entitlement volumes.

~~FS-72~~



~~Table V~~ ~~Reserve Quantity Information - Continued~~

In 2012, net revisions increased reserves 1,855 BCF. A net increase of 1,007 BCF in Asia was primarily due to development drilling and additional compression in Bangladesh, and drilling results and improved field performance in Thailand. In Australia, updated reservoir data interpretation based on additional drilling at the Gorgon Project drove the 358 BCF increase. Drilling results from activities in the Marcellus Shale were responsible for the majority of the 318 BCF increase in the United States.

In 2013, net revisions increased reserves 718 BCF. A net increase of 627 BCF in Asia was 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.

Extensions and Discoveries In 2011, extensions and discoveries increased reserves 4,680 BCF. In Australia, the Wheatstone Project accounted for the 4,035 BCF in additions. In Africa, the start of a new natural gas development project in Nigeria resulted in the 290 BCF increase. In the United States, development drilling accounted for the majority of the 287 BCF increase.

In 2012, extensions and discoveries increased reserves by 1,011 BCF. The increase of 747 BCF in Australia was primarily related to positive drilling results at the Gorgon Project.

In 2013, extensions and discoveries increased reserves by 1,021 BCF, with the majority in the Appalachian region in the U.S.

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

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

In 2012, sales decreased reserves by 538 BCF. Sales of a portion of the company's equity interest in the Wheatstone Project were responsible for the 439 BCF reserves reduction in Australia.

~~FS-73~~FS-69



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

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

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

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


	Consolidated Companies																					Affiliated Companies						Total Consolidated			Consolidated Companies																					Affiliated Companies						Total Consolidated
				Other																								and Affiliated						Other																								and Affiliated
Millions of dollars	U.S.			Americas			Africa			Asia			Australia			Europe			Total			TCO			Other			Companies			U.S.			Americas			Africa			Asia			Australia			Europe			Total			TCO			Other			Companies
At December 31, 2012
At December 31, 2013
Future cash inflows from production¹	$	139,856		$	72,548		$	122,189		$	121,849		$	134,009		$	19,653		$	610,104		$	169,966		$	47,496		$	827,566		$	136,942		$	73,468		$	117,119		$	111,970		$	130,620		$	20,232		$	590,351		$	157,108		$	43,380		$	790,839
Future production costs	(46,173		)	(26,450		)	(24,591		)	(35,713		)	(18,340		)	(8,768		)	(160,035		)	(32,085		)	(19,899		)	(212,019		)	(39,009		)	(29,373		)	(27,800		)	(35,716		)	(19,387		)	(10,099		)	(161,384		)	(32,245		)	(18,027		)	(211,656		)
Future development costs	(11,192		)	(11,925		)	(14,601		)	(17,275		)	(24,923		)	(1,946		)	(81,862		)	(12,355		)	(3,710		)	(97,927		)	(12,058		)	(10,149		)	(10,983		)	(17,290		)	(18,220		)	(2,644		)	(71,344		)	(12,852		)	(3,879		)	(88,075		)
Future income taxes	(31,647		)	(9,902		)	(48,683		)	(30,763		)	(27,224		)	(5,589		)	(153,808		)	(37,658		)	(13,363		)	(204,829		)	(28,458		)	(9,454		)	(53,953		)	(26,162		)	(27,904		)	(4,727		)	(150,658		)	(33,603		)	(9,418		)	(193,679		)
Undiscounted future net cash flows	50,844			24,271			34,314			38,098			63,522			3,350			214,399			87,868			10,524			312,791			57,417			24,492			24,383			32,802			65,109			2,762			206,965			78,408			12,056			297,429
10 percent midyear annual discount for timing of estimated cash flows	(21,416		)	(15,906		)	(12,430		)	(13,033		)	(40,450		)	(860		)	(104,095		)	(47,534		)	(5,644		)	(157,273		)	(23,055		)	(15,217		)	(8,165		)	(10,901		)	(35,110		)	(888		)	(93,336		)	(41,444		)	(6,482		)	(141,262		)
Standardized Measure Net Cash Flows	$	29,428		$	8,365		$	21,884		$	25,065		$	23,072		$	2,490		$	110,304		$	40,334		$	4,880		$	155,518		$	34,362		$	9,275		$	16,218		$	21,901		$	29,999		$	1,874		$	113,629		$	36,964		$	5,574		$	156,167
At December 31, 2011 ²
At December 31, 2012²
Future cash inflows from production¹	$	143,633		$	63,579		$	124,077		$	124,972		$	113,773		$	19,704		$	589,738		$	171,588		$	42,212		$	803,538		$	139,856		$	72,548		$	122,189		$	121,849		$	134,009		$	19,653		$	610,104		$	169,966		$	47,496		$	827,566
Future production costs	(39,523		)	(22,856		)	(22,703		)	(35,579		)	(15,411		)	(7,467		)	(143,539		)	(30,904		)	(19,430		)	(193,873		)	(41,773		)	(27,191		)	(24,592		)	(35,713		)	(18,340		)	(8,768		)	(156,377		)	(32,085		)	(19,899		)	(208,361		)
Future development costs	(11,272		)	(9,345		)	(10,695		)	(15,035		)	(29,489		)	(676		)	(76,512		)	(10,778		)	(2,836		)	(90,126		)	(11,192		)	(14,810		)	(14,601		)	(17,275		)	(24,923		)	(1,946		)	(84,747		)	(12,355		)	(3,710		)	(100,812		)
Future income taxes	(34,050		)	(9,121		)	(53,103		)	(33,884		)	(20,661		)	(7,229		)	(158,048		)	(36,698		)	(10,833		)	(205,579		)	(32,357		)	(9,902		)	(48,683		)	(30,763		)	(27,224		)	(5,589		)	(154,518		)	(37,658		)	(13,363		)	(205,539		)
Undiscounted future net cash flows	58,788			22,257			37,576			40,474			48,212			4,332			211,639			93,208			9,113			313,960			54,534			20,645			34,313			38,098			63,522			3,350			214,462			87,868			10,524			312,854
10 percent midyear annual discount for timing of estimated cash flows	(25,013		)	(15,082		)	(13,801		)	(14,627		)	(35,051		)	(1,117		)	(104,691		)	(51,547		)	(4,883		)	(161,121		)	(23,055		)	(14,331		)	(12,429		)	(13,033		)	(40,450		)	(860		)	(104,158		)	(47,534		)	(5,644		)	(157,336		)
Standardized Measure Net Cash Flows	$	33,775		$	7,175		$	23,775		$	25,847		$	13,161		$	3,215		$	106,948		$	41,661		$	4,230		$	152,839		$	31,479		$	6,314		$	21,884		$	25,065		$	23,072		$	2,490		$	110,304		$	40,334		$	4,880		$	155,518
At December 31, 2010 ²
At December 31, 2011
Future cash inflows from production¹	$	101,281		$	48,068		$	90,402		$	101,553		$	52,635		$	13,618		$	407,557		$	124,970		$	31,188		$	563,715		$	143,633		$	63,579		$	124,077		$	124,972		$	113,773		$	19,704		$	589,738		$	171,588		$	42,212		$	803,538
Future production costs	(36,609		)	(22,118		)	(19,591		)	(30,793		)	(9,191		)	(5,842		)	(124,144		)	(22,304		)	(4,172		)	(150,620		)	(39,523		)	(22,856		)	(22,703		)	(35,579		)	(15,411		)	(7,467		)	(143,539		)	(30,904		)	(19,430		)	(193,873		)
Future development costs	(6,661		)	(6,953		)	(12,239		)	(11,690		)	(13,160		)	(708		)	(51,411		)	(8,777		)	(2,254		)	(62,442		)	(11,272		)	(9,345		)	(10,695		)	(15,035		)	(29,489		)	(676		)	(76,512		)	(10,778		)	(2,836		)	(90,126		)
Future income taxes	(20,307		)	(7,337		)	(34,405		)	(26,355		)	(9,085		)	(4,031		)	(101,520		)	(26,524		)	(12,919		)	(140,963		)	(34,050		)	(9,121		)	(53,103		)	(33,884		)	(20,661		)	(7,229		)	(158,048		)	(36,698		)	(10,833		)	(205,579		)
Undiscounted future net cash flows	37,704			11,660			24,167			32,715			21,199			3,037			130,482			67,365			11,843			209,690			58,788			22,257			37,576			40,474			48,212			4,332			211,639			93,208			9,113			313,960
10 percent midyear annual discount for timing of estimated cash flows	(13,218		)	(6,751		)	(9,221		)	(12,287		)	(15,282		)	(699		)	(57,458		)	(37,015		)	(6,574		)	(101,047		)	(25,013		)	(15,082		)	(13,801		)	(14,627		)	(35,051		)	(1,117		)	(104,691		)	(51,547		)	(4,883		)	(161,121		)
Standardized Measure Net Cash Flows	$	24,486		$	4,909		$	14,946		$	20,428		$	5,917		$	2,338		$	73,024		$	30,350		$	5,269		$	108,643		$	33,775		$	7,175		$	23,775		$	25,847		$	13,161		$	3,215		$	106,948		$	41,661		$	4,230		$	152,839


¹	Based on 12-month average price.


²	~~2011 and 2010~~2012 conformed to ~~2012~~2013 presentation.

~~FS-74~~FS-70



	Table VIIChanges 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

~~production volumes~~ and costs. Changes in the timing of production are included with “Revisions of previous quantity estimates.”

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


							Total									Total
							Consolidated									Consolidated
							and Affiliated									and Affiliated
Millions of dollars	Consolidated Companies			Affiliated Companies			Companies			Consolidated Companies*			Affiliated Companies			Companies
Present Value at January 1, 2010 ^*	$	50,276		$	27,236		$	77,512
Sales and transfers of oil and gas produced net of production costs	(39,047		)	(6,377		)	(45,424		)
Development costs incurred	12,042			572			12,614
Purchases of reserves	513			—			513
Sales of reserves	(47		)	—			(47		)
Extensions, discoveries and improved recovery less related costs	5,194			63			5,257
Revisions of previous quantity estimates	9,704			1,113			10,817
Net changes in prices, development and production costs	43,887			14,429			58,316
Accretion of discount	8,391			3,797			12,188
Net change in income tax	(17,889		)	(5,214		)	(23,103		)
Net change for 2010	22,748			8,383			31,131
Present Value at December 31, 2010 ^*	$	73,024		$	35,619		$	108,643
Present Value at January 1, 2011										$	73,024		$	35,619		$	108,643
Sales and transfers of oil and gas produced net of production costs	(52,338		)	(8,679		)	(61,017		)	(52,338		)	(8,679		)	(61,017		)
Development costs incurred	13,869			729			14,598			13,869			729			14,598
Purchases of reserves	1,212			—			1,212			1,212			—			1,212
Sales of reserves	(803		)	—			(803		)	(803		)	—			(803		)
Extensions, discoveries and improved recovery less related costs	12,288			—			12,288			12,288			—			12,288
Revisions of previous quantity estimates	16,025			923			16,948			16,025			923			16,948
Net changes in prices, development and production costs	61,428			15,979			77,407			61,428			15,979			77,407
Accretion of discount	11,943			5,048			16,991			11,943			5,048			16,991
Net change in income tax	(29,700		)	(3,728		)	(33,428		)	(29,700		)	(3,728		)	(33,428		)
Net change for 2011	33,924			10,272			44,196			33,924			10,272			44,196
Present Value at December 31, 2011	$	106,948		$	45,891		$	152,839		$	106,948		$	45,891		$	152,839
Sales and transfers of oil and gas produced net of production costs	(49,094		)	(7,708		)	(56,802		)	(49,094		)	(7,708		)	(56,802		)
Development costs incurred	18,013			942			18,955			18,013			942			18,955
Purchases of reserves	376			—			376			376			—			376
Sales of reserves	(1,630		)	—			(1,630		)	(1,630		)	—			(1,630		)
Extensions, discoveries and improved recovery less related costs	11,303			106			11,409			9,251			106			9,357
Revisions of previous quantity estimates	23,556			3,759			27,315			26,022			3,759			29,781
Net changes in prices, development and production costs	(19,179		)	(2,266		)	(21,445		)	(19,178		)	(2,266		)	(21,444		)
Accretion of discount	18,026			6,322			24,348			18,026			6,322			24,348
Net change in income tax	1,985			(1,832		)	153			1,570			(1,832		)	(262		)
Net change for 2012	3,356			(677		)	2,679			3,356			(677		)	2,679
Present Value at December 31, 2012	$	110,304		$	45,214		$	155,518		$	110,304		$	45,214		$	155,518
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										25,573			1,306			26,879
Net changes in prices, development and production costs										(25,959		)	(5,925		)	(31,884		)
Accretion of discount										18,463			6,406			24,869
Net change in income tax										2,539			2,818			5,357
Net change for 2013										3,325			(2,676		)	649
Present Value at December 31, 2013										$	113,629		$	42,538		$	156,167

^*~~2011 and 2010~~2012 conformed to ~~2012~~2013 presentation.

~~FS-75~~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 ~~March 28, 2012,~~January 29, 2014, filed as Exhibit 3.1 to Chevron Corporation’s Current Report on Form 8-K filed ~~March 29, 2012,~~January 31, 2014, 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		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.
10.3		Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit ~~10.3~~B to Chevron Corporation’s Notice of the 2013 Annual ~~Report on Form 10-K for the year ended December 31, 2008,~~Meeting and 2013 Proxy Statement filed April 11, 2013, and incorporated herein by reference.
10.4		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.
10.5		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.
10.6		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.
10.7		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.
~~10.8~~		Texaco Inc. Director and Employee Deferral Plan, filed as Exhibit 10.16 to Chevron Corporation’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated herein by reference.
10.910.8		Summary of Chevron Incentive Plan Award Criteria.
~~10.1~~		Chevron Corporation Change in Control Surplus Employee Severance Program for Salary Grades 41 through 43, filed as Exhibit 10.1 to Chevron Corporation’s Current Report on Form 8-K filed December 12, 2006, and incorporated herein by reference.
~~10.11~~		~~Chevron Corporation Benefit Protection Program, filed as Exhibit 10.2 to Chevron Corporation’s Current Report on Form 8-K filed December 12, 2006, and incorporated herein by reference.~~
~~10.12~~10.9*		Form of Terms and Conditions for Awards under the Long-Term Incentive Plan of Chevron ~~Corporation, filed as Exhibit 10.1 to Chevron Corporation’s Current Report on Form 8-K filed February 1, 2011, and incorporated herein by reference.~~Corporation.
10.13*10.10		Form of Restricted Stock Unit Grant Agreement under the Long-Term Incentive Plan of Chevron ~~Corporation.~~Corporation, filed as Exhibit 10.13 to Chevron Corporation's Annual Report on Form 10-K for the year ended December 31, 2012, and incorporated herein by reference.
~~10.14~~10.11		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.
~~10.15~~10.12		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.
~~10.16~~10.13		Agreement between Chevron Corporation and R. Hewitt Pate, filed as Exhibit 10.16 to Chevron'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 ~~(pages E-4 through E-5)~~(page E-4).

E-1



Exhibit No.		Description

23.1*		Consent of PricewaterhouseCoopers LLP (page ~~E-6)~~E-5).
24.1 to 24.924.10		Powers of Attorney for directors and certain officers 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 of the company’s Chief Executive Officer (page ~~E-7)~~E-6).
31.2*		Rule 13a-14(a)/15d-14(a) Certification of the company’s Chief Financial Officer (page ~~E-8)~~E-7).
32.1*		Section 1350 Certification of the company’s Chief Executive Officer (page ~~E-9)~~E-8).
32.2*		Section 1350 Certification of the company’s Chief Financial Officer (page ~~E-10)~~E-9).
95*		Mine Safety Disclosure.
99.1*		Definitions of Selected Energy and Financial Terms (pages ~~E-11~~E-10 through ~~E-12)~~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 ~~the~~ 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




	Wells Drilling		Net Wells Completed
	at 12/31/12		2012		2011		2010
	Gross	Net	Prod.	Dry	Prod.	Dry	Prod.	Dry
United States	78	45	941	6	909	9	634	7
Other Americas	13	6	50	—	37	—	32	—
Africa	10	4	23	—	29	—	33	—
Asia	75	35	566	15	549	15	445	15
Australia	8	4	—	—	—	—	—	—
Europe	5	—	9	—	6	—	4	—
Total Consolidated Companies	189	94	1,589	21	1,530	24	1,148	22
Equity Affiliates	6	3	26	—	25	—	8	—
Total Including Affiliates	195	97	1,615	21	1,555	24	1,156	22



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



	2012*			2011*			2010*
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.	1,012	—	2,574	990	—	2,486	1,045	—	2,113
Other Americas	91	391	1,063	82	403	1,147	84	352	1,490
Africa	782	—	1,163	792	—	1,276	830	—	1,304
Asia	643	—	4,511	703	—	4,300	826	—	4,836
Australia	31	—	682	39	—	813	39	—	881
Europe	103	—	191	116	—	204	136	—	235
Total Consolidated	2,662	391	10,184	2,722	403	10,226	2,960	352	10,859
Affiliated Companies
TCO	977	—	1,261	1,019	—	1,400	1,128	—	1,484
Other	115	50	377	93	50	75	95	53	70
Total Consolidated and Affiliated Companies	3,754	441	11,822	3,834	453	11,701	4,183	405	12,413
Proved Undeveloped
Consolidated Companies
U.S.	347	—	1,148	321	—	1,160	230	—	359
Other Americas	132	122	412	31	120	517	24	114	325
Africa	348	—	1,918	363	—	1,920	338	—	1,640
Asia	194	—	2,356	191	—	2,421	187	—	2,357
Australia	103	—	9,570	101	—	8,931	49	—	5,175
Europe	54	—	66	43	—	54	16	—	40
Total Consolidated	1,178	122	15,470	1,050	120	15,003	844	114	9,896
Affiliated Companies
TCO	755	—	1,038	740	—	851	692	—	902
Other	49	182	865	64	194	1,128	62	203	1,040
Total Consolidated and Affiliated Companies	1,982	304	17,373	1,854	314	16,982	1,598	317	11,838
Total Proved Reserves	5,736	745	29,195	5,688	767	28,683	5,781	722	24,251