CHEVRON CORP - Annual Report: 2018 (Form 10-K)

Large accelerated filer þ

Accelerated filer

Non-accelerated filer o

Smaller reporting company

Emerging growth company

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, 2018

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 every Interactive Data File required to be submitted 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 such files).

Yes þ No o

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

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 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

The 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 — $242.2 billion (As of June 29, 2018)

Number of Shares of Common Stock outstanding as of February 11, 2019 — 1,900,062,760

DOCUMENTS INCORPORATED BY REFERENCE

(To The Extent Indicated Herein)

Notice of the 2019 Annual Meeting and 2019 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, in connection with the company’s 2019 Annual Meeting of Stockholders (in Part III)

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TABLE OF CONTENTS



ITEM		PAGE
PART I
1.	Business	3
	General Development of Business	3
	Description of Business and Properties	4
	Upstream	4
	Downstream	15
	Other Businesses	17
1A.	Risk Factors	18
1B.	Unresolved Staff Comments	21
2.	Properties	21
3.	Legal Proceedings	21
4.	Mine Safety Disclosures	22
	Executive Officers of the Registrant	22
PART II
5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	22
6.	Selected Financial Data	22
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
7A.	Quantitative and Qualitative Disclosures About Market Risk	23
8.	Financial Statements and Supplementary Data	23
9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	23
9A.	Controls and Procedures	23
9B.	Other Information	23
PART III
10.	Directors, Executive Officers and Corporate Governance	24
11.	Executive Compensation	25
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	25
13.	Certain Relationships and Related Transactions, and Director Independence	25
14.	Principal Accounting Fees and Services	25
PART IV
15.	Exhibits, Financial Statement Schedules	102
	Schedule II — Valuation and Qualifying Accounts	102
16.	Form 10-K Summary	102
	Signatures	105

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

This Annual Report on Form 10-K of Chevron Corporation contains forward-looking statements relating to Chevron’s operations that are based on management’s current expectations, estimates and projections about the petroleum, chemicals and other energy-related industries. Words or phrases such as “anticipates,” “expects,” “intends,” “plans,” “targets,” “forecasts,” “projects,” “believes,” “seeks,” “schedules,” “estimates,” “positions,” “pursues,” “may,” “could,” “should,” “will,” “budgets,” “outlook,” “trends,” “guidance,” “focus,” “on schedule,” “on track,” “is slated,” “goals,” “objectives,” “strategies,” “opportunities” and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, many of which are beyond the company’s control and are difficult to predict. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements. The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this report. Unless legally required, Chevron undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.

Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are: changing crude oil and natural gas prices; changing refining, marketing and chemicals margins; the company's ability to realize anticipated cost savings and expenditure reductions; actions of competitors or regulators; timing of exploration expenses; timing of crude oil liftings; the competitiveness of alternate-energy sources or product substitutes; technological developments; the results of operations and financial condition of the company's suppliers, vendors, partners and equity affiliates, particularly during extended periods of low prices for crude oil and natural gas; the inability or failure of the company’s joint-venture partners to fund their share of operations and development activities; the potential failure to achieve expected net production from existing and future crude oil and natural gas development projects; potential delays in the development, construction or start-up of planned projects; the potential disruption or interruption of the company’s operations due to war, accidents, political events, civil unrest, severe weather, cyber threats and terrorist acts, crude oil production quotas or other actions that might be imposed by the Organization of Petroleum Exporting Countries, or other natural or human causes beyond the company's control; changing economic, regulatory and political environments in the various countries in which the company operates; general domestic and international economic and political conditions; the potential liability for remedial actions or assessments under existing or future environmental regulations and litigation; significant operational, investment or product changes required by existing or future environmental statutes and regulations, including international agreements and national or regional legislation and regulatory measures to limit or reduce greenhouse gas emissions; the potential liability resulting from other pending or future litigation; the company’s future acquisition or disposition of assets or shares or the delay or failure of such transactions to close based on required closing conditions; the potential for gains and losses from asset dispositions or impairments; government-mandated sales, divestitures, recapitalizations, industry-specific taxes, tariffs, sanctions, changes in fiscal terms or restrictions on scope of company operations; foreign currency movements compared with the U.S. dollar; material reductions in corporate liquidity and access to debt markets; the effects of changed accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; the company's ability to identify and mitigate the risks and hazards inherent in operating in the global energy industry; and the factors set forth under the heading “Risk Factors” on pages 18 through 21 in this report. Other unpredictable or unknown factors not discussed in this report could also have material adverse effects on forward-looking statements.

PART I

Item 1. Business

General Development of Business

Summary Description of Chevron

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

A list of the company’s major subsidiaries is presented on page E-1. As of December 31, 2018, Chevron had approximately 48,600 employees (including about 3,600 service station employees). Approximately 24,800 employees (including about 3,300 service station employees), or 51 percent, were employed in U.S. operations.

Overview of Petroleum Industry

Petroleum industry operations and profitability are influenced by many factors. Prices for crude oil, natural gas, petroleum products and petrochemicals are generally determined by supply and demand. Production levels from the members of the Organization of Petroleum Exporting Countries (OPEC), Russia and the United States are the major factors 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 invest, 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. In the upstream business, 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, as well as independent refining and marketing, transportation and chemicals entities and national petroleum companies in the refining, manufacturing, sale and marketing of fuels, lubricants, additives and petrochemicals.

Operating Environment

Refer to pages 28 through 34 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 deliver industry-leading results and superior shareholder value in any business environment. In the upstream, the company’s strategy is to deliver industry-leading returns while developing high-value resource opportunities. In the downstream, the company's strategy is to grow earnings across the value chain and make targeted investments to lead the industry in returns.

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

________________________________________________________

^* Incorporated in Delaware in 1926 as Standard Oil Company of California, the company adopted the name Chevron Corporation in 1984 and ChevronTexaco Corporation in 2001. In 2005, ChevronTexaco Corporation changed its name to Chevron Corporation. As used in this report, the term “Chevron” and such terms as “the company,” “the corporation,” “our,” “we,” “us” and "its" 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, 2018, and assets as of the end of 2018 and 2017 — for the United States and the company’s international geographic areas — are in Note 13 to the Consolidated Financial Statements beginning on page 66. Similar comparative data for the company’s investments in and income from equity affiliates and property, plant and equipment are in Note 14 beginning on page 69 and Note 17 on page 77. Refer to pages 39 and 40 of this Form 10-K in Management's Discussion and Analysis of Financial Condition and Results of Operations for a discussion of the company's capital and exploratory expenditures.

Upstream

Reserves

Refer to Table V beginning on page 95 for a tabulation of the company’s proved net liquids (including crude oil, condensate, natural gas liquids and synthetic oil) and natural gas reserves by geographic area, at the beginning of 2016 and each year-end from 2016 through 2018. 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, 2018, are summarized in the discussion for Table V. Discussion is also provided regarding the nature of, status of, and planned future activities associated with the development of proved undeveloped reserves. The company recognizes reserves for projects with various development periods, sometimes exceeding five years. The external factors that impact the duration of a project include scope and complexity, remoteness or adverse operating conditions, infrastructure constraints, and contractual limitations.

At December 31, 2018, 29 percent of the company's net proved oil-equivalent reserves were located in the United States, 20 percent were located in Australia and 18 percent were located in Kazakhstan.

The net proved reserve balances at the end of each of the three years 2016 through 2018 are shown in the following table:



	At December 31
	2018	2017	2016
Liquids — Millions of barrels
Consolidated Companies	4,975	4,530	4,131
Affiliated Companies	1,815	2,012	2,197
Total Liquids	6,790	6,542	6,328
Natural Gas — Billions of cubic feet
Consolidated Companies	28,733	27,514	25,432
Affiliated Companies	2,843	3,222	3,328
Total Natural Gas	31,576	30,736	28,760
Oil-Equivalent — Millions of barrels¹
Consolidated Companies	9,764	9,116	8,369
Affiliated Companies	2,289	2,549	2,752
Total Oil-Equivalent	12,053	11,665	11,121

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

________________________________________________________

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

Net Production of Liquids and Natural Gas

The following table summarizes the net production of liquids and natural gas for 2018 and 2017 by the company and its affiliates. Worldwide oil-equivalent production of 2.930 million barrels per day in 2018 was up 7 percent from 2017. Production increases from major capital projects, shale and tight properties, and base business were partially offset by normal field declines, the impact of asset sales, and production entitlement effects in several locations. Refer to the “Results of Operations” section beginning on page 32 for a detailed discussion of the factors explaining the 2016 through 2018 changes in production for crude oil and natural gas liquids, and natural gas, and refer to Table V on pages 98 and 99 for information on annual production by geographical region.



			Components of Oil-Equivalent
	Oil-Equivalent		Liquids		Natural Gas
Thousands of barrels per day (MBPD)	(MBPD)¹		(MBPD)		(MMCFPD)
Millions of cubic feet per day (MMCFPD)	2018	2017	2018	2017	2018	2017
United States	791	681	618	519	1,034	970
Other Americas
Argentina	24	23	20	19	24	27
Brazil	11	13	10	12	4	4
Canada²	116	98	103	87	79	65
Colombia	14	16	—	—	82	96
Trinidad and Tobago³	—	5	—	—	—	29
Total Other Americas	165	155	133	118	189	221
Africa
Angola	108	112	98	103	59	57
Democratic Republic of the Congo³	1	2	1	2	—	1
Nigeria	239	250	200	213	233	223
Republic of Congo	52	38	49	36	14	14
Total Africa	400	402	348	354	306	295
Asia
Azerbaijan	20	25	18	23	10	11
Bangladesh	112	111	4	4	648	642
China	29	30	16	17	84	81
Indonesia	132	164	113	137	113	163
Kazakhstan	46	55	27	33	120	132
Myanmar	16	19	—	—	98	116
Partitioned Zone⁴	—	—	—	—	—	—
Philippines	26	25	3	3	138	129
Thailand	236	241	66	69	1,022	1,031
Total Asia	617	670	247	286	2,233	2,305
Australia/Oceania
Australia	426	256	42	27	2,304	1,372
Total Australia/Oceania	426	256	42	27	2,304	1,372
Europe
Denmark	19	23	12	14	45	53
United Kingdom	65	75	43	50	133	155
Total Europe	84	98	55	64	178	208
Total Consolidated Companies	2,483	2,262	1,443	1,368	6,244	5,371
Affiliates^2,5	447	466	339	355	645	661
Total Including Affiliates⁶	2,930	2,728	1,782	1,723	6,889	6,032

¹Oil-equivalent conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of crude oil.
² Includes synthetic oil: Canada, net	53	51	53	51	—	—
Venezuelan affiliate, net	24	28	24	28	—	—
³ Producing fields in Trinidad and Tobago were sold in August 2017. Chevron sold its interest in a concession in the Democratic Republic of Congo in April 2018.
⁴ Located between Saudi Arabia and Kuwait. Production has been shut-in since May 2015.
⁵Volumes represent Chevron’s share of production by affiliates, including Tengizchevroil in Kazakhstan; Petroboscan and Petropiar in Venezuela; and Angola LNG in Angola.
⁶ Volumes include natural gas consumed in operations of 619 million and 565million cubic feet per day in 2018 and 2017, respectively. Total “as sold” natural gas volumes were 6,270 million and 5,467 million cubic feet per day for 2018 and 2017, respectively.

Production Outlook

The company estimates its average worldwide oil-equivalent production in 2019 will grow 4 to 7 percent compared to 2018, assuming a Brent crude oil price of $60 per barrel and excluding the impact of anticipated 2019 asset sales. This estimate is subject to many factors and uncertainties, as described beginning on page 29. Refer to the “Review of Ongoing Exploration and Production Activities in Key Areas,” beginning on page 8, for a discussion of the company’s major crude oil and natural gas development projects.

Average Sales Prices and Production Costs per Unit of Production

Refer to Table IV on page 94 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 2018, 2017 and 2016.

Gross and Net Productive Wells

The following table summarizes gross and net productive wells at year-end 2018 for the company and its affiliates:



	At December 31, 2018
	Productive Oil Wells*		Productive Gas Wells*
	Gross	Net	Gross	Net
United States	39,499	28,594	2,619	1,912
Other Americas	1,067	646	164	98
Africa	1,748	676	21	8
Asia	14,397	12,509	3,697	2,113
Australia/Oceania	560	313	105	29
Europe	324	70	169	35
Total Consolidated Companies	57,595	42,808	6,775	4,195
Affiliates	1,586	554	—	—
Total Including Affiliates	59,181	43,362	6,775	4,195
Multiple completion wells included above	802	525	147	116
* Gross wells represent the total number of wells in which Chevron has an ownership interest. Net wells represent the sum of Chevron's ownership interest in gross wells.

Acreage

At December 31, 2018, the company owned or had under lease or similar agreements undeveloped and developed crude oil and natural gas properties throughout the world. The geographical distribution of the company’s acreage is shown in the following table:



	Undeveloped²		Developed		Developed and Undeveloped
Thousands of acres¹	Gross	Net	Gross	Net	Gross	Net
United States	3,596	3,441	4,137	2,895	7,733	6,336
Other Americas	14,970	9,663	1,221	277	16,191	9,940
Africa	3,804	1,459	2,237	933	6,041	2,392
Asia	24,368	10,958	1,670	924	26,038	11,882
Australia/Oceania	25,664	17,036	2,002	803	27,666	17,839
Europe	669	300	407	53	1,076	353
Total Consolidated Companies	73,071	42,857	11,674	5,885	84,745	48,742
Affiliates	499	220	305	116	804	336
Total Including Affiliates	73,570	43,077	11,979	6,001	85,549	49,078
¹ Gross acres represent the total number of acres in which Chevron has an ownership interest. Net acres represent the sum of Chevron's ownership interest in gross acres.
²The gross undeveloped acres that will expire in 2019, 2020 and 2021 if production is not established by certain required dates are 1,042, 651 and 2,057, 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 293 billion cubic feet of natural gas to third parties from 2019 through 2021. The company believes it can satisfy these contracts through a combination of equity production from the company’s proved developed U.S. reserves and third-party purchases. These commitments are all based on contracts with indexed pricing terms.

Outside the United States, the company is contractually committed to deliver a total of 2,442 billion cubic feet of natural gas to third parties from 2019 through 2021 from operations in Australia, Colombia, Indonesia 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 91 for details associated with the company’s development expenditures and costs of proved property acquisitions for 2018, 2017 and 2016.

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, 2018. A “development well” is a well drilled within the known area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.



	Wells Drilling*		Net Wells Completed
	at 12/31/18		2018		2017		2016
	Gross	Net	Prod.	Dry	Prod.	Dry	Prod.	Dry
United States	246	211	509	1	435	4	420	4
Other Americas	22	14	43	—	40	—	45	—
Africa	3	2	8	—	34	—	17	—
Asia	44	17	289	5	246	2	470	6
Australia/Oceania	—	—	1	—	—	—	4	—
Europe	2	—	2	—	4	—	3	—
Total Consolidated Companies	317	244	852	6	759	6	959	10
Affiliates	37	16	39	—	36	—	38	—
Total Including Affiliates	354	260	891	6	795	6	997	10
* Gross wells represent the total number of wells in which Chevron has an ownership interest. Net wells represent the sum of Chevron's ownership interest in gross wells.

Exploration Activities

Refer to Table I on page 91 for detail on the company’s exploration expenditures and costs of unproved property acquisitions for 2018, 2017 and 2016.

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, 2018. “Exploratory wells” are wells drilled to find and produce crude oil or natural gas in unknown 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.



	Wells Drilling*		Net Wells Completed
	at 12/31/18		2018		2017		2016
	Gross	Net	Prod.	Dry	Prod.	Dry	Prod.	Dry
United States	5	3	13	2	7	1	4	1
Other Americas	—	—	1	1	—	—	4	—
Africa	1	1	—	—	—	—	1	1
Asia	—	—	1	—	—	—	3	—
Australia/Oceania	—	—	—	—	—	—	—	—
Europe	—	—	—	1	—	1	—	—
Total Consolidated Companies	6	4	15	4	7	2	12	2
Affiliates	—	—	—	—	—	—	—	—
Total Including Affiliates	6	4	15	4	7	2	12	2
* Gross wells represent the total number of wells in which Chevron has an ownership interest. Net wells represent the sum of Chevron's ownership interest in gross wells.

Review of Ongoing Exploration and Production Activities in Key Areas

Chevron has exploration and production activities in most of the world's major hydrocarbon basins. Chevron’s 2018 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 32, 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-7.

The discussion that follows references the status of proved reserves recognition for significant long-lead-time projects not on production as well as for projects recently placed on production. Reserves are not discussed for exploration activities or recent discoveries that have not advanced to a project stage, or for mature areas of production that do not have individual projects requiring significant levels of capital or exploratory investment.

United States

Upstream activities in the United States are primarily located in the midcontinent region, the Gulf of Mexico, California and the Appalachian Basin. Net oil-equivalent production in the United States during 2018 averaged 791,000 barrels per day.

The company's activities in the midcontinent region are primarily in Colorado, New Mexico and Texas. During 2018, net daily production in these areas averaged 198,000 barrels of crude oil, 651 million cubic feet of natural gas and 77,000 barrels of natural gas liquids (NGLs). In 2018, the company divested properties in New Mexico, Oklahoma and Texas. The company is pursuing opportunities to increase development efficiency across the region.

In the Permian Basin of West Texas and southeast New Mexico, the company holds approximately 500,000 and 1,200,000 net acres of shale and tight resources in the Midland and Delaware basins, respectively. This acreage includes multiple stacked formations that enable production from several layers of rock in different geologic zones. Chevron has implemented a factory development strategy in the basin, which utilizes multiwell pads to drill a series of horizontal wells that are completed concurrently using hydraulic fracture stimulation. The company is also applying data analytics and technology on its Permian well information to drive improvements in well targets and performance. In 2018, the company's net daily production in the basin averaged 159,000 barrels of crude oil, 501 million cubic feet of natural gas and 66,000 barrels of NGLs.

During 2018, net daily production in the Gulf of Mexico averaged 186,000 barrels of crude oil, 117 million cubic feet of natural gas and 13,000 barrels of NGLs. Chevron is engaged in various operated and nonoperated exploration, development and production activities in the deepwater Gulf of Mexico. Chevron also holds nonoperated interests in several shelf fields.

The deepwater Jack and St. Malo fields are being jointly developed with a host floating production unit (FPU) located between the two fields. Chevron has a 50 percent interest in the Jack Field and a 51 percent interest in the St. Malo Field. Both fields are company operated. The company has a 40.6 percent interest in the production host facility, which is designed to accommodate production from the Jack/St. Malo development and third-party tiebacks. Total daily production from the Jack and St. Malo fields in 2018 averaged 139,000 barrels of liquids (71,000 net) and 21 million cubic feet of natural gas (11 million net). Additional development opportunities for the Jack and St. Malo fields progressed in 2018. Stage 2 of the development plan was completed with four planned wells on production. Development drilling continued on Stage 3, with two of the three planned wells completed at the end of 2018. Proved reserves have been recognized for these phases. The St. Malo Stage 4 waterflood project entered front-end engineering design (FEED) in 2018 and is expected to reach final investment decision in third quarter 2019. At the end of 2018, proved reserves had not been recognized for this project. The Jack and St. Malo fields have an estimated remaining production life of 30 years.

At the 58 percent-owned and operated deepwater Tahiti Field, net daily production averaged 51,000 barrels of crude oil, 22 million cubic feet of natural gas, and 3,000 barrels of NGLs. Infill drilling continued in 2018 with one new infill well completed. The Tahiti Vertical Expansion project, the next development phase of the Tahiti Field, is developing shallower reservoirs and encompassing four new wells and associated subsea infrastructure. First oil was achieved from three wells in June 2018, and a fourth well is scheduled to come on line in second quarter 2019. The Tahiti Field has an estimated remaining production life of at least 25 years.

The company has a 15.6 percent nonoperated working interest in the deepwater Mad Dog Field. In 2018, net daily production averaged 8,000 barrels of liquids and 1 million cubic feet of natural gas. Project execution continued in 2018 with the next development phase, the Mad Dog 2 Project. This phase of the plan is to develop the southwestern extension of the Mad Dog Field including a new floating production platform with a design capacity of 140,000 barrels of crude oil per day. First oil is expected in 2021. Proved reserves have been recognized for the Mad Dog 2 Project.

The development plan for the 60 percent-owned and operated deepwater Big Foot Project includes a 15-slot drilling and production tension leg platform with water injection facilities and a design capacity of 75,000 barrels of crude oil and 25 million cubic feet of natural gas per day. First oil was achieved in November 2018 and is expected to continue ramp up during 2019. The field has an estimated production life of 35 years.

Chevron holds a 25 percent nonoperated working interest in the Stampede Project located in the Green Canyon area. First oil was achieved in January 2018. In 2018, total daily production averaged 16,000 barrels of crude oil (4,000 net) and 4 million cubic feet of natural gas (1 million net). Production is expected to continue to ramp up until early 2020. The field has an estimated production life of 30 years.

Chevron has owned and operated interests of 55 to 61.3 percent in the blocks containing the Anchor Field. In 2018, the Anchor Field was expanded to include acreage in two additional blocks. FEED activities commenced in 2018 for Stage 1 of the Anchor development, which consists of a seven-well subsea development and semi-submersible floating production unit. The planned facility has a design capacity of 75,000 barrels of crude oil and 28 million cubic feet of natural gas per day. At the end of 2018, proved reserves had not been recognized for this project.

Chevron has a 60 percent-owned and operated interest in the Ballymore field located in the Mississippi Canyon area and a 40 percent nonoperated working interest in the Whale discovery located in the Perdido area. In January 2018, the company announced a significant crude oil discovery at Ballymore. Appraisal activities are underway to evaluate this opportunity and identify a cost-effective development plan. At the Whale discovery, results of the exploration and appraisal wells are being assessed in parallel to progressing cost-effective development options. At the end of 2018, proved reserves had not been recognized for these projects.

In November 2018, Chevron transferred operatorship of the leases under the Tiber and Guadalupe Units following its decision to exit the Tigris project.

In 2018, Chevron added 29 leases to its deepwater portfolio through two gulf-wide lease sales. Chevron also added one additional lease through an asset swap.

In California, the company has significant production in the San Joaquin Valley. In 2018, net daily production averaged 138,000 barrels of crude oil, 25 million cubic feet of natural gas and 400 barrels of NGLs. Chevron sold its nonoperated working interest in the Elk Hills Field in April 2018.

The company holds approximately 428,000 net acres in the Marcellus Shale and 462,000 net acres in the Utica Shale, primarily located in southwestern Pennsylvania, the West Virginia panhandle and eastern Ohio. During 2018, net daily production in these areas averaged 240 million cubic feet of natural gas, 4,000 barrels of NGLs and 1,000 barrels of condensate. Chevron has implemented a factory development strategy, which enables future co-development of the Marcellus and Utica shales from the same pads in stacked play locations.

Other Americas

“Other Americas” includes Argentina, Brazil, Canada, Colombia, Mexico, Suriname and Venezuela. Net oil-equivalent production from these countries averaged 209,000 barrels per day during 2018.

Canada Upstream activities in Canada are concentrated in Alberta, British Columbia and the offshore Atlantic region. The company also has discovered resource interests in the Beaufort Sea region of the Northwest Territories. Net oil-equivalent production during 2018 averaged 116,000 barrels per day, composed of 50,000 barrels of crude oil, 79 million cubic feet of natural gas and 53,000 barrels of synthetic oil from oil sands.

Chevron holds a 26.9 percent nonoperated working interest in the Hibernia Field and a 23.7 percent nonoperated working interest in the unitized Hibernia Southern Extension areas offshore Atlantic Canada.

The company holds a 29.6 percent nonoperated working interest in the heavy oil Hebron Field, also offshore Atlantic Canada. Total daily crude production averaged 60,000 barrels (18,000 net) in 2018 and is expected to continue ramp up during 2019. The field has an expected economic life of 30 years.

The company holds a 20 percent nonoperated working interest in the Athabasca Oil Sands Project (AOSP) in Alberta. Oil sands are mined from both the Muskeg River and the Jackpine mines, and bitumen is extracted from the oil sands and upgraded into synthetic oil. Carbon dioxide emissions from the upgrade process are reduced by the Quest carbon capture and storage facilities.

The company holds approximately 215,000 net acres in the Duvernay Shale in Alberta. Chevron has a 70 percent-owned and operated interest in most of the Duvernay acreage. Chevron is applying learnings from other company-owned shale assets to lower development costs. A total of 122 wells have been tied into production facilities by early 2019. In 2018, net daily production averaged 9,000 barrels of crude oil and 54 million cubic feet of natural gas.

Chevron holds a 50 percent-owned and operated interest in Flemish Pass Basin Block EL 1138 with 339,000 net acres. The company relinquished its interest in blocks EL 1125 and EL 1126 in 2018.

Chevron holds a 50 percent-owned and operated interest in the proposed Kitimat LNG and Pacific Trail Pipeline projects and a 50 percent owned and operated interest in 290,000 net acres in the Liard and Horn River shale gas basins in British Columbia. The horizontal appraisal drilling program progressed during 2018. The Kitimat LNG Project is planned to include a two-train LNG facility and has a 10.0 million-metric-ton-per-year export license. The total production capacity for the project is expected to be 1.6 billion cubic feet of natural gas per day. Spending is being paced until LNG market conditions and reductions in project costs are sufficient to support the development of this project. At the end of 2018, proved reserves had not been recognized for this project.

Mexico The company owns and operates a 33.3 percent interest in Block 3 in the Perdido area of the Gulf of Mexico covering 139,000 net acres. Seismic reprocessing activities continued in 2018. Chevron also holds a 37.5 percent-owned and operated interest in Block 22 in the deepwater Cuenca Salina area of the Gulf of Mexico covering 267,000 net acres. In October 2018, an environmental baseline study was completed. Seismic data reprocessing activities have extended into 2019.

Argentina Chevron holds a 50 percent nonoperated interest in the Loma Campana and Narambuena concessions in the Vaca Muerta Shale covering 73,000 net acres. Chevron also holds an 85 percent-owned and operated interest in the El Trapial concession covering 94,000 net acres with both conventional production and Vaca Muerta Shale potential. Net oil-equivalent production in 2018 averaged 24,000 barrels per day, composed of 20,000 barrels of crude oil and 24 million cubic feet of natural gas. Nonoperated development activities continued in 2018 at the Loma Campana concession in the Vaca Muerta Shale. During 2018, the drilling program continued with 32 horizontal wells drilled. This concession expires in 2048.

The company utilizes waterflood operations to mitigate declines at the operated El Trapial Field and continues to evaluate the potential of the Vaca Muerta Shale. Chevron initiated a shale appraisal drilling program in November 2018. The El Trapial concession expires in 2032.

Evaluation of the nonoperated Narambuena Block continued in 2018, with appraisal activity planned for 2019.

Chevron conducted an environmental review on the 90 percent owned and operated Loma del Molle Norte Block adjacent to the El Trapial concession, which covers 43,000 net acres.

Brazil In January 2019, Chevron signed an agreement for the sale of its 51.7 percent interest in the Frade field and its 50 percent-owned and operated interest in Block CE-M715. The sale is expected to close in 2019. Net oil-equivalent production in 2018 averaged 11,000 barrels per day, composed of 10,000 barrels of crude oil and 4 million cubic feet of natural gas.

Additionally, Chevron holds a 37.5 percent nonoperated interest in the Papa-Terra field that expires in 2032.

In 2018, Chevron won six deepwater blocks in the prolific Brazil pre-salt trend within the Campos and Santos basins. The company holds between 30 to 50 percent of both operated and nonoperated interest in the six new blocks. The six blocks cover 470,000 net acres.

Colombia The company operates the offshore Chuchupa and onshore Ballena natural gas fields and receives 43 percent of the production for the remaining life of each field. Net daily production in 2018 averaged 82 million cubic feet of natural gas.

Suriname Chevron holds a 33.3 percent and a 50 percent nonoperated working interest in deepwater Blocks 42 and 45 offshore Suriname, respectively. Two exploratory wells were drilled in Blocks 42 and 45 in 2018, with additional exploratory drilling activity planned.

Venezuela Chevron's production activities in Venezuela are located in western Venezuela and the Orinoco Belt. Net oil-equivalent production during 2018 averaged 44,000 barrels per day, composed of 42,000 barrels of crude oil and 9 million cubic feet of natural gas.

Chevron has a 30 percent interest in the Petropiar affiliate that operates the heavy oil Huyapari Field, formerly known as Hamaca. The production and upgrading project is located in Venezuela’s Orinoco Belt under an agreement expiring in 2033.

Petropiar drilled 64 development wells in 2018. Chevron also holds a 39.2 percent interest in the Petroboscan affiliate that operates the Boscan Field in western Venezuela and a 25.2 percent interest in the Petroindependiente affiliate that operates the LL-652 Field in Lake Maracaibo, both of which are under agreements expiring in 2026. Petroboscan drilled 21 development wells in 2018.

Chevron also holds a 34 percent interest in the Petroindependencia affiliate, which includes the Carabobo 3 heavy oil project located within the Orinoco Belt. The Petroindependencia contract expires in 2035.

Greenland Chevron relinquished its 29.2 percent-owned and operated interest in two exploration blocks off the northeast coast of Greenland in 2018.

Africa

In Africa, the company is engaged in upstream activities in Angola, Nigeria and Republic of Congo. Net oil-equivalent production averaged 450,000 barrels per day during 2018 in this region.

Angola The company operates and holds a 39.2 percent interest in Block 0, a concession adjacent to the Cabinda coastline, and a 31 percent interest in a production-sharing contract (PSC) for deepwater Block 14. The concession for Block 0 extends through 2030 and the development and production rights for the various producing fields in Block 14 expire between 2023 and 2031. During 2018, net production averaged 107,000 barrels of liquids and 308 million cubic feet of natural gas per day.

The Mafumeira Sul development achieved its first liquefied petroleum gas (LPG) export in January 2018. Ramp-up continued at the main production facility with total daily production in 2018 averaging 52,000 barrels of liquids (17,000 net) and 147 million cubic feet of natural gas (57 million net), exported to the Angola LNG Plant. Additionally, six new wells were drilled in 2018.

Chevron has a 36.4 percent interest in Angola LNG Limited, which operates an onshore natural gas liquefaction plant in Soyo, Angola. The plant has the capacity to process 1.1 billion cubic feet of natural gas per day. This is the world's first LNG plant supplied with associated gas, where the natural gas is a byproduct of crude oil production. Feedstock for the plant originates from multiple fields and operators. Total daily production in 2018 averaged 685 million cubic feet of natural gas (249 million net) and 23,000 barrels of NGLs (8,500 net).

Angola-Republic of Congo Joint Development Area Chevron operates and holds a 31.3 percent interest in the Lianzi Unitization Zone, located in an area shared equally by Angola and the Republic of Congo. Production from Lianzi is reflected in the totals for Angola and the Republic of Congo.

Republic of Congo Chevron has a 31.5 percent nonoperated working interest in the offshore Haute Mer permit areas (Nkossa and Moho-Bilondo). The licenses for Nkossa and Moho-Bilondo expire in 2027 and 2030, respectively. Additionally, the company has a 20.4 percent nonoperated working interest in the offshore Haute Mer B permit area. Average net daily production in 2018 was 49,000 barrels of liquids.

Two exploration wells were drilled in 2018, with one in the Moho Bilondo area and a second in the Haute Mer B area.

Nigeria Chevron operates and holds a 40 percent interest in eight concessions in the onshore and near-offshore regions of the Niger Delta. The company also holds acreage positions in three operated and six nonoperated deepwater blocks, with working interests ranging from 20 to 100 percent. In 2018, the company’s net oil-equivalent production in Nigeria averaged 239,000 barrels per day, composed of 194,000 barrels of crude oil, 233 million cubic feet of natural gas and 6,000 barrels of LPG.

Chevron completed the final well in its infill drilling program in the Niger Delta in first quarter 2019. Further infill drilling programs are beginning in 2019. The company is the operator of the Escravos Gas Plant (EGP) with a total processing capacity of 680 million cubic feet per day of natural gas and LPG and condensate export capacity of 58,000 barrels per day. The company is also the operator of the 33,000-barrel-per-day Escravos gas-to-liquids facility. The 40 percent-owned and operated Sonam Field Development Project is designed to process natural gas through the EGP facilities and deliver it to the domestic gas market. Net daily production in 2018 averaged 10,000 barrels of liquids and 80 million cubic feet of natural gas.

In addition, the company holds a 36.7 percent interest in the West African Gas Pipeline Company Limited affiliate, which supplies Nigerian natural gas to customers in Benin, Ghana and Togo.

Chevron operates and holds a 67.3 percent interest in the Agbami Field, located in deepwater Oil Mining Lease (OML) 127 and OML 128. The original Agbami development scope has been completed (Agbami 1, 2 and 3). Infill drilling continued in 2018 to further offset field decline, with additional infill drilling planned for 2019. The leases that contain the Agbami Field expire in 2023 and 2024. Additionally, Chevron holds a 30 percent nonoperated working interest in the Usan Field.

Also in the deepwater area, the Aparo Field in OML 132 and OML 140 and the third-party-owned Bonga SW Field in OML 118 share a common geologic structure and are planned to be jointly developed. Chevron holds a 16.6 percent nonoperated working interest in the unitized area. The development plan involves subsea wells tied back to a floating production, storage and offloading vessel. Work continues to progress towards a final investment decision. At the end of 2018, no proved reserves were recognized for this project.

In deepwater exploration, Chevron operates and holds a 55 percent interest in the deepwater Nsiko discoveries in OML 140. A 3-D seismic acquisition program is planned for OML 140 and the adjacent OML 132 in 2019. Chevron also holds a 30 percent nonoperated working interest in OML 138, which includes the Usan Field and several satellite discoveries, and a 27 percent interest in adjacent licenses OML 139 and OML 154. The company plans to continue to evaluate development options for the multiple discoveries in the Usan area, including the Owowo Field, which straddles OML 139 and Oil Prospecting License (OPL) 223.

Democratic Republic of the Congo Chevron sold its 17.7 percent nonoperated working interest in an offshore concession in April 2018.

Liberia Chevron surrendered its 45 percent interest in Block LB-14 off the coast of Liberia in July 2018.

Morocco The company surrendered its interest in the Cap Cantin Deep and Cap Walidia Deep acreage in September 2018.

Asia

In Asia, the company is engaged in upstream activities in Azerbaijan, Bangladesh, China, Indonesia, Kazakhstan, the Kurdistan Region of Iraq, Myanmar, the Partitioned Zone located between Saudi Arabia and Kuwait, the Philippines, Russia and Thailand. During 2018, net oil-equivalent production averaged 970,000 barrels per day in this region.

Azerbaijan Chevron holds a 9.6 percent nonoperated interest in the Azerbaijan International Operating Company (AIOC) and the crude oil production from the Azeri-Chirag-Gunashli (ACG) fields. AIOC operations are conducted under a PSC that expires in 2049. Net oil-equivalent production in 2018 averaged 20,000 barrels per day, composed of 18,000 barrels of crude oil and 10 million cubic feet of natural gas.

Chevron also has an 8.9 percent interest in the Baku-Tbilisi-Ceyhan (BTC) pipeline affiliate, which transports the majority of ACG production from Baku, Azerbaijan, through Georgia to Mediterranean deepwater port facilities at Ceyhan, Turkey. The BTC pipeline has a capacity of 1 million barrels per day. Another production export route for crude oil is the Western Route Export Pipeline (WREP), which is operated by AIOC. During 2018, WREP transported approximately 76,000 barrels per day from Baku, Azerbaijan, to a marine terminal at Supsa, Georgia, on the Black Sea.

In 2018, Chevron announced its intent to market its share in AIOC and the BTC pipeline affiliate.

Kazakhstan Chevron has a 50 percent interest in the Tengizchevroil (TCO) affiliate and an 18 percent nonoperated working interest in the Karachaganak Field. Net oil-equivalent production in 2018 averaged 399,000 barrels per day, composed of 315,500 barrels of liquids and 507 million cubic feet of natural gas.

TCO is developing the Tengiz and Korolev crude oil fields in western Kazakhstan under a concession agreement that expires in 2033. Net daily production in 2018 from these fields averaged 269,000 barrels of crude oil, 387 million cubic feet of natural gas and 19,500 barrels of NGLs. All of TCO’s crude oil production was exported through the Caspian Pipeline Consortium (CPC) pipeline.

The Future Growth and Wellhead Pressure Management Project (FGP/WPMP) at Tengiz is being managed as a single integrated project. The FGP is designed to increase total daily production by about 260,000 barrels of crude oil and to expand the utilization of sour gas injection technology proven in existing operations to increase ultimate recovery from the reservoir. The WPMP is designed to maintain production levels in existing plants as reservoir pressure declines. Project execution advanced in 2018 with completion of construction and operational readiness of the Cargo Transportation Route facility (CaTRo). During 2018, CaTRo received 28 pre-assembled racks and 12 were successfully set on foundation. Additionally, a major milestone was achieved in September 2018 when the first modular unit of the processing plant arrived at the construction site in Kazakhstan. This module was successfully restacked by the end of the year, along with two gas turbine generator modules. First oil is planned for 2022. Proved reserves have been recognized for the FGP/WPMP.

The Capacity and Reliability Project is designed to reduce facility bottlenecks and increase plant capacity and reliability at Tengiz. The project was completed in second quarter 2018.

The Karachaganak Field is located in northwest Kazakhstan, and operations are conducted under a PSC that expires in 2038. During 2018, net daily production averaged 27,000 barrels of liquids and 120 million cubic feet of natural gas. Most of the exported liquids were transported through the CPC pipeline. Work continues to identify the optimal scope for the future expansion of the field. At the end of 2018, proved reserves had not been recognized for a future expansion.

Kazakhstan/Russia Chevron has a 15 percent interest in the CPC. During 2018, CPC transported an average of 1.3 million barrels of crude oil per day, composed of 1.2 million barrels per day from Kazakhstan and 147,000 barrels per day from Russia.

Bangladesh Chevron operates and holds a 100 percent interest in Block 12 (Bibiyana Field) and Blocks 13 and 14 (Jalalabad and Moulavi Bazar fields). The rights to produce from Jalalabad expire in 2030, from Moulavi Bazar in 2033 and from Bibiyana in 2034. Net oil-equivalent production in 2018 averaged 112,000 barrels per day, composed of 648 million cubic feet of natural gas and 4,000 barrels of condensate.

Myanmar Chevron has a 28.3 percent nonoperated working interest in a PSC for the production of natural gas from the Yadana, Badamyar 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 natural gas to the Myanmar-Thailand border for delivery to power plants in Thailand. Net natural gas production in 2018 averaged 98 million cubic feet per day.

Chevron also holds a 55 percent-owned and operated interest in Blocks AD3 and A5. Seismic processing and interpretation continued in 2018.

Thailand Chevron holds operated interests in the Pattani Basin, located in the Gulf of Thailand, with ownership ranging from 35 percent to 80 percent. Concessions for producing areas within this basin expire between 2022 and 2035. Chevron also has a 16 percent nonoperated working interest in the Arthit Field located in the Malay Basin. Concessions for the producing areas within this basin expire between 2036 and 2040. Net oil-equivalent production in 2018 averaged 236,000 barrels per day, composed of 66,000 barrels of crude oil and condensate and 1.0 billion cubic feet of natural gas.

In the Pattani Basin, the 35 percent-owned and operated Ubon Project in Block 12/27 completed FEED on a Central Processing Platform with a floating, storage and offloading vessel for oil export. At the end of 2018, proved reserves had not been recognized for this project. Chevron also holds ownership ranging from 70 to 80 percent of the Erawan concession, which expires in 2022. Following the concession expiration, Chevron expects to transfer the Erawan operations to the Government of Thailand. Erawan concession's net average daily production in 2018 was 46,000 barrels of crude oil and condensate and 800 million cubic feet of natural gas.

Chevron holds between 30 and 80 percent operated and nonoperated working interests in the Thailand-Cambodia overlapping claim area that are inactive, pending resolution of border issues between Thailand and Cambodia.

China Chevron has operated and nonoperated working interests in several areas in China. The company’s net daily production in 2018 averaged 16,000 barrels of crude oil and 84 million cubic feet of natural gas.

The company operates the 49 percent-owned Chuandongbei Project, located onshore in the Sichuan Basin. The Xuanhan Gas Plant has three gas processing trains with a design outlet capacity of 258 million cubic feet per day. Total daily production in 2018 averaged 183 million cubic feet of natural gas (84 million net).

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

Philippines The company holds a 45 percent nonoperated working interest in the offshore Malampaya natural gas field. Net oil-equivalent production in 2018 averaged 26,000 barrels per day, composed of 138 million cubic feet of natural gas and 3,000 barrels of condensate. The concession expires in 2024.

Indonesia Chevron holds working interests through various PSCs in Indonesia. In Sumatra, the company holds a 100 percent-owned and operated interest in the Rokan PSC, which expires in 2021. Chevron also operates three PSCs in the Kutei Basin (Makassar Strait, Rapak and Ganal), located offshore eastern Kalimantan. These interests range from 62 to 72 percent. Net oil-equivalent production in 2018 averaged 132,000 barrels per day, composed of 113,000 barrels of liquids and 113 million cubic feet of natural gas. In fourth quarter 2018, Chevron relinquished the expired East Kalimantan PSC.

There are two deepwater natural gas development projects in the Kutei Basin progressing under a single plan of development. Collectively, these projects are referred to as the Indonesia Deepwater Development and the company's interest is 62 percent. One of these projects, Bangka, includes a two-well subsea tieback to the West Seno FPU, and is producing.

The other project, Gendalo-Gehem, has a planned design capacity of 920 million cubic feet of natural gas and 30,000 barrels of condensate per day. A revised plan of development was submitted to the Government of Indonesia for approval in 2018. Gas from the project is expected to be marketed for both domestic sale and LNG export after liquefaction at the state-owned

Bontang LNG plant in East Kalimantan. The company continues to work toward a final investment decision, subject to economic competitiveness, timing of government approvals, including extension of the associated PSCs, and securing new LNG sales contracts. At the end of 2018, proved reserves had not been recognized for this project.

Kurdistan Region of Iraq The company operates and holds 80 percent contractor interests in the Sarta and Qara Dagh PSCs. In July 2018, the company entered into an agreement with the Kurdistan Regional Government for the Qara Dagh block, which allows the company to continue evaluating exploration opportunities through October 2020. The company has drilled two exploration wells and an appraisal well in the Sarta block and evaluation of these resource opportunities is ongoing. The Sarta PSC expires in 2047. Chevron signed an agreement to farm out a 30 percent interest in the Sarta block and a 40 percent interest in the Qara Dagh block, which is expected to close in 2019, pending government approval.

Partitioned Zone Chevron holds a concession to operate the Kingdom of Saudi Arabia's 50 percent interest in the hydrocarbon resources in the onshore area of the Partitioned Zone between Saudi Arabia and Kuwait. The concession expires in 2039. Beginning in May 2015, production in the Partitioned Zone was shut in as a result of continued difficulties in securing work and equipment permits. As of early 2019, production remains shut in, and the exact timing of a production restart is uncertain and dependent on dispute resolution between Saudi Arabia and Kuwait and the acquisition of necessary permits.

Processing and interpretation of the 3-D seismic survey, which was acquired in 2016 and covers the entire onshore Partitioned Zone, is complete. Work is underway to mature several exploration prospects.

Australia/Oceania

In Australia/Oceania, the company is engaged in upstream activities in Australia and New Zealand. During 2018 net oil-equivalent production averaged 426,000 barrels per day, all from Australia.

Australia Upstream activities in Australia are concentrated offshore Western Australia, where the company is the operator of two major LNG projects, Gorgon and Wheatstone, and has a nonoperated working interest in the North West Shelf (NWS) Venture and exploration acreage in the Browse Basin and the Carnarvon Basin. The company also holds exploration acreage in the Bight Basin offshore South Australia. The company's relinquishment of the Bright Basin acreage is pending government approval. During 2018, the company's net daily production averaged 42,000 barrels of liquids and 2.3 billion cubic feet of natural gas.

Chevron holds a 47.3 percent interest in and is the operator of the Gorgon Project, which includes the development of the Gorgon and Jansz-Io fields. The project includes a three-train, 15.6 million-metric-ton-per-year LNG facility, a domestic gas plant, and a carbon dioxide capture and injection facility with first injection expected in 2019. The facilities are located on Barrow Island. In April 2018, the company reached final investment decision on Stage 2 of Gorgon which will include 11 new wells in the Gorgon and Jansz-Io fields and additional subsea infrastructure. Drilling of the new wells is expected to begin in second quarter 2019. Total daily production from all three trains in 2018 averaged 18,000 barrels of condensate (8,500 barrels net) and 2.6 billion cubic feet of natural gas (1.2 billion net). The project's estimated economic life exceeds 40 years.

Chevron holds an 80.2 percent interest in the offshore licenses and a 64.1 percent interest in the LNG facilities associated with the Wheatstone Project. The project includes the development of the Wheatstone and Iago fields, a two-train, 8.9 million-metric-ton-per-year LNG facility, and a domestic gas plant. The onshore facilities are located at Ashburton North on the coast of Western Australia. The total production capacity for the Wheatstone and Iago fields and nearby third-party fields is expected to be approximately 1.6 billion cubic feet of natural gas and 30,000 barrels of condensate per day. LNG Train 2 start-up and first cargo were achieved in June 2018. Total daily production averaged 16,000 barrels of condensate (12,800 net) and 801 million cubic feet of natural gas (642 million net) in 2018. The project's estimated economic life exceeds 30 years.

Chevron has a 16.7 percent nonoperated working interest in the NWS Venture in Western Australia.

Chevron holds 50 percent-owned and operated interests in four exploration permits in the northern Carnarvon Basin. Chevron continued to evaluate exploration potential in the Carnarvon Basin during 2018.

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

Chevron has a 100 percent-owned and operated interest in the Clio, Acme and Acme West fields. The company is collaborating with other Carnarvon Basin participants to assess the opportunity of Clio Acme being developed through shared utilization of existing infrastructure.

New Zealand Chevron holds a 50 percent interest and operates three deepwater exploration permits in the offshore Pegasus and East Coast basins. Seismic processing and interpretation continued in 2018.

Europe

In Europe, the company is engaged in upstream activities in Denmark and the United Kingdom. Net oil-equivalent production averaged 84,000 barrels per day during 2018.

Denmark Chevron signed an agreement to sell its 12 percent nonoperated working interest in the Danish Underground Consortium in September 2018. The sale is expected to close in 2019, pending regulatory approval.

United Kingdom The company’s net oil-equivalent production in 2018 averaged 65,000 barrels per day, composed of 43,000 barrels of liquids and 133 million cubic feet of natural gas. In 2018, Chevron announced its intent to market its Central North Sea assets, including Captain.

The Captain Enhanced Oil Recovery (EOR) Project is the next development phase of the Captain Field, which is designed to increase field recovery by injecting a polymer/water mixture into the Captain reservoir. Stage 1 of the project is an expansion of the existing polymer injection system on the wellhead production platform that includes six new polymer injection wells and modifications to the platform facilities. Proved reserves have been recognized for Stage 1 of this project. During 2018, construction continued to progress on Captain EOR Stage 2, which involves subsea expansion of the technology. At the end of 2018, proved reserves had not been recognized for Stage 2 of the project.

Chevron has a 19.4 percent nonoperated working interest in the Clair Ridge Project, located west of the Shetland Islands. The project is the second development phase of the Clair Field. The design capacity of the project is 120,000 barrels of crude oil and 100 million cubic feet of natural gas per day. First production was achieved in November 2018. The Clair Field has an estimated production life extending until 2050.

In January 2019, Chevron sold its 40 percent operated working interest in the Rosebank Field.

Norway In November 2018, the company divested its 20 percent nonoperated working interest in exploration Block PL 859, located in the Barents Sea.

Sales of Natural Gas and Natural Gas Liquids

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

During 2018, U.S. and international sales of natural gas averaged 3.5 billion and 5.6 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 Angola, Australia, Bangladesh, Europe, Kazakhstan, Indonesia, Latin America, Myanmar, Nigeria, the Philippines and Thailand.

U.S. and international sales of NGLs averaged 184,000 and 96,000 barrels per day, respectively, in 2018. Substantially all of the international sales of NGLs from the company's producing interests are from operations in Angola, Australia, Canada, Indonesia, Nigeria and the United Kingdom.

Refer to “Selected Operating Data,” on page 37 in Management’s Discussion and Analysis of Financial Condition and Results of Operations, for further information on the company’s sales volumes of natural gas and natural gas liquids. Refer also to “Delivery Commitments” beginning on page 6 for information related to the company’s delivery commitments for the sale of crude oil and natural gas.

Downstream

Refining Operations

At the end of 2018, the company had a refining network capable of processing nearly 1.6 million barrels of crude oil per day. Operable capacity at December 31, 2018, and daily refinery inputs for 2016 through 2018 for the company and affiliate refineries are summarized in the table on the next page.

Average crude oil distillation capacity utilization was 93 percent in 2018 and 2017. At the U.S. refineries, crude oil distillation capacity utilization averaged 97 percent in 2018, compared with 98 percent in 2017. Chevron processes both imported and domestic crude oil in its U.S. refining operations. Imported crude oil accounted for about 70 percent and 71 percent of Chevron’s U.S. refinery inputs in 2018 and 2017, respectively.

In the United States, the company continued work on projects to improve refinery flexibility and reliability. At the Richmond refinery in California, first production commenced at the new hydrogen plant in November 2018 and full operation of the

project is expected in 2019. At the refinery in Salt Lake City, Utah, construction continues for the alkylation retrofit project. Project start-up is expected in 2020. In January 2019, the company signed an agreement to acquire a refinery in Pasadena, Texas.

Outside the United States, the company has three large refineries in South Korea, Singapore and Thailand. The Singapore Refining Company (SRC), a 50 percent-owned joint venture, processes up to 276,000 barrels of crude per day and manufactures a wide range of petroleum products. The company continues to progress evaluation and development of upgrading projects to convert low-value products into higher-value products. The 50 percent-owned, GS Caltex operated, Yeosu Refinery in South Korea remains one of the world's largest and is targeted for additional investment with the addition of olefins production capacity. The company's 60.6 percent-owned refinery in Map Ta Phut, Thailand, continues to supply high-quality petroleum products through the Caltex brand in the Thailand market.

In September 2018, the company completed the sale of its interest in the Cape Town refinery in South Africa.

Petroleum Refineries: Locations, Capacities and Inputs



Capacities and inputs in thousands of barrels per day		December 31, 2018		Refinery Inputs
Locations		Number	Operable Capacity	2018	2017	2016
Pascagoula	Mississippi	1	351	332	349	355
El Segundo	California	1	269	273	251	267
Richmond	California	1	257	249	248	188
Kapolei¹	Hawaii	—	—	—	—	37
Salt Lake City	Utah	1	55	51	53	53
Total Consolidated Companies — United States		4	932	905	901	900
Map Ta Phut	Thailand	1	157	160	152	162
Cape Town²	South Africa	—	—	49	68	78
Burnaby, B.C.³	Canada	—	—	—	40	51
Total Consolidated Companies — International		1	157	209	260	291
Affiliates	Various Locations	3	538	494	500	497
Total Including Affiliates — International		4	695	703	760	788
Total Including Affiliates — Worldwide		8	1,627	1,608	1,661	1,688


¹	In November 2016, the company sold the Hawaii refinery.


²	In September 2018, the company sold its interest in the Cape Town refinery.


³	In September 2017, the company sold the Burnaby, B.C. refinery.

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, 2018.

Refined Products Sales Volumes



Thousands of barrels per day	2018	2017	2016
United States
Gasoline	627	625	631
Jet Fuel	255	242	242
Diesel/Gas Oil	188	179	182
Residual Fuel Oil	48	48	59
Other Petroleum Products¹	100	103	99
Total United States	1,218	1,197	1,213
International²
Gasoline	336	365	382
Jet Fuel	276	274	261
Diesel/Gas Oil	446	490	468
Residual Fuel Oil	177	162	144
Other Petroleum Products¹	202	202	207
Total International	1,437	1,493	1,462
Total Worldwide²	2,655	2,690	2,675
¹ Principally naphtha, lubricants, asphalt and coke.
² Includes share of affiliates’ sales:	373	366	377

In the United States, the company markets under the Chevron and Texaco brands. At year-end 2018, the company supplied directly or through retailers and marketers approximately 7,900 Chevron- and Texaco- branded service stations, primarily in the southern and western states. Approximately 310 of these outlets are company-owned or -leased stations.

Outside the United States, Chevron supplied directly or through retailers and marketers approximately 5,000 branded service stations, including affiliates. The company markets in Latin America using the Texaco brand. In 2018, Chevron continued to grow, expanding to 135 branded stations in northwestern Mexico at the end of the year. In the Asia-Pacific region and the Middle East, the company uses the Caltex brand. The company also operates through affiliates under various brand names. In South Korea, the company operates through its 50 percent-owned affiliate, GS Caltex. In September 2018, the company completed the sale of its marketing and lubricants businesses in southern Africa and Botswana.

Chevron markets commercial aviation fuel at approximately 90 airports worldwide. The company also markets an extensive line of lubricant and coolant products under the product names Havoline, Delo, Ursa, Meropa, Rando, Clarity and Taro in the United States and worldwide under the three brands: Chevron, Texaco and Caltex.

Chemicals Operations

Chevron Oronite Company develops, manufactures and markets performance additives for lubricating oils and fuels and conducts research and development for additive component and blended packages. At the end of 2018, the company manufactured, blended or conducted research at 10 locations around the world. In June 2018, a final investment decision was reached for a lubricant additive blending and shipping plant in Ningbo, China. Commercial production is anticipated to begin in 2021.

Chevron owns a 50 percent interest in its Chevron Phillips Chemical Company LLC (CPChem) affiliate. CPChem produces olefins, polyolefins and alpha olefins and is a supplier of aromatics and polyethylene pipe, in addition to participating in the specialty chemical and specialty plastics markets. At the end of 2018, CPChem owned or had joint-venture interests in 28 manufacturing facilities and two research and development centers around the world.

In March 2018, CPChem commenced operations of a new ethane cracker with an annual design capacity of 1.5 million metric tons of ethylene located at the Cedar Bayou facility, and reached design capacity during second quarter 2018.

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

GS Caltex expects to reach a final investment decision in first quarter 2019 to build an olefins mixed-feed cracker and polyethylene unit within the existing refining and aromatics facilities in Yeosu, South Korea.

Transportation

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

Refer to pages 11 through 13 in the Upstream section for information on the West African Gas Pipeline, the Baku-Tbilisi-Ceyhan Pipeline, the Western Route Export Pipeline and the Caspian Pipeline Consortium.

Shipping The company's marine fleet includes both U.S. and foreign flagged vessels. The operated fleet consists of conventional crude tankers, product carriers, and LNG carriers. These vessels transport crude oil, LNG, refined products and feedstocks in support of the company's global upstream and downstream businesses.

Other Businesses

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

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

In 2018, Chevron joined the Oil and Gas Climate Initiative and separately launched the Chevron Future Energy Fund. Both initiatives invest in technology designed to economically lower emissions.

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

Some of the investments the company makes in the areas described above are in new or unproven technologies and business processes, and ultimate technical or commercial successes are not certain. Refer to Note 26 on page 89 for a summary of the company's research and development expenses.

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

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

The company is committed to improving energy efficiency in its day-to-day operations and is required to comply with the greenhouse gas-related laws and regulations to which it is subject. Refer to Item 1A. Risk Factors on pages 18 through 21 for further discussion of greenhouse gas regulation and climate change and the associated risks to Chevron’s business.

Refer to Management's Discussion and Analysis of Financial Condition and Results of Operations on page 43 for additional information on environmental matters and their impact on Chevron, and on the company's 2018 environmental expenditures. Refer to page 43 and Note 23 beginning on page 86 for a discussion of environmental remediation provisions and year-end reserves.

Item 1A. Risk Factors

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

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

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

The scope of Chevron’s business will decline if the company does not successfully develop resources The company is in an extractive business; therefore, if it is not successful in replacing the crude oil and natural gas it produces with good prospects

for future organic opportunities 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; reservoir optimization; ability to bring long-lead-time, capital-intensive projects to completion on budget and on schedule; and efficient and profitable operation of mature properties.

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

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

Cyberattacks targeting Chevron’s process control networks or other digital infrastructure could have a material adverse impact on the company’s business and results of operations There are numerous and evolving risks to Chevron's cybersecurity and privacy from cyber threat actors, including criminal hackers, state-sponsored intrusions, industrial espionage and employee malfeasance. These cyber threat actors, whether internal or external to Chevron, are becoming more sophisticated and coordinated in their attempts to access the company’s information technology (IT) systems and data, including the IT systems of cloud providers and other third parties with whom the company conducts business. Although Chevron devotes significant resources to prevent unwanted intrusions and to protect its systems and data, whether such data is housed internally or by external third parties, the company has experienced and will continue to experience cyber incidents of varying degrees in the conduct of its business. Cyber threat actors could compromise the company’s process control networks or other critical systems and infrastructure, resulting in disruptions to its business operations, injury to people, harm to the environment or its assets, disruptions in access to its financial reporting systems, or loss, misuse or corruption of its critical data and proprietary information, including without limitation its intellectual property and business information and that of its employees, customers, partners and other third parties. Any of the foregoing can be exacerbated by a delay or failure to detect a cyber incident. Further, the company has exposure to cyber incidents and the negative impacts of such incidents related to its critical data and proprietary information housed on third-party IT systems, including the cloud. The company has limited control and visibility over such third-party IT systems. Cyber events could result in significant financial losses, legal or regulatory violations, reputational harm, and legal liability and could ultimately have a material adverse effect on the company’s business and results of operations.

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

Chevron’s business subjects the company to liability risks from litigation or government action The company produces, transports, refines and markets potentially hazardous materials, and it purchases, handles and disposes of other potentially hazardous 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, see Note 15 to the Consolidated Financial Statements, beginning on page 70.

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 self-insured, 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 legal and regulatory environment could harm Chevron’s business The company’s operations, particularly exploration and production, can be affected by changing economic, regulatory and political environments in the various countries in which it operates. As has occurred in the past, actions could be taken by governments to increase public ownership of the company’s partially or wholly owned businesses or to impose additional taxes or royalties. In certain locations, governments have proposed or imposed restrictions on the company’s operations, trade, currency exchange controls, burdensome taxes, and public disclosure requirements that might harm the company’s competitiveness or relations with other governments or third parties. In other countries, political conditions have existed that may threaten the safety of employees and the company’s continued presence in those countries, and internal unrest, acts of violence or strained relations between a government and the company or other governments may adversely affect the company’s operations. Those developments have, at times, significantly affected the company’s operations and results and are carefully considered by management when evaluating the level of current and future activity in such countries. Further, Chevron is required to comply with U.S. sanctions and other trade laws and regulations which, depending upon their scope, could adversely impact the company's operations in certain countries. In addition, litigation or changes in national, state or local environmental regulations or laws, including those designed to stop or impede the development or production of oil and gas, such as those related to the use of hydraulic fracturing or bans on drilling, could adversely affect the company's current or anticipated future operations and profitability.

Regulation of greenhouse gas (GHG) emissions could increase Chevron’s operational costs and reduce demand for Chevron’s hydrocarbon and other products In the years ahead, companies in the energy industry, like Chevron, may be challenged by an increase in international and domestic regulation relating to GHG emissions. Like any significant changes in the regulatory environment, GHG regulation could have the impact of curtailing profitability in the oil and gas sector or rendering the extraction of the company’s oil and gas resources economically infeasible. Although the IEA’s World Energy Outlook scenarios anticipate oil and gas continuing to make up a significant portion of the global energy mix through 2040 and beyond given their respective advantages in transportation and power generation, if a new onset of regulation contributes to a decline in the demand for the company’s products, this could have a material adverse effect on the company and its financial condition.

International agreements and national, regional and state legislation (e.g., California AB32, SB32 and AB398) and regulatory measures that aim to limit or reduce GHG emissions are currently in various stages of implementation. For example, the Paris Agreement went into effect in November 2016, and a number of countries are studying and may adopt additional policies to meet their Paris Agreement goals. In some jurisdictions, the company is already subject to currently implemented programs such as the U.S. Renewable Fuel Standard program, the European Union Emissions Trading System, and the California cap-and-trade program and related low carbon fuel standard obligations. Other jurisdictions are considering adopting or are in the process of implementing laws or regulations to directly regulate GHG emissions through similar or other mechanisms such as, for example, via a carbon tax (e.g., Singapore and Canada) or via a cap-and-trade program (e.g., Mexico and China). The landscape continues to be in a state of constant re-assessment and legal challenge with respect to these laws and regulations, making it difficult to predict with certainty the ultimate impact they will have on the company in the aggregate.

GHG emissions-related laws and related regulations and the effects of operating in a potentially carbon-constrained environment may result in increased and substantial capital, compliance, operating and maintenance costs and could, among other things, reduce demand for hydrocarbons and the company’s hydrocarbon-based products, make the company’s products more expensive, adversely affect the economic feasibility of the company’s resources, and adversely affect the company’s sales volumes, revenues and margins. GHG emissions (e.g., carbon dioxide and methane) that could be regulated include, among others, those associated with the company’s exploration and production of hydrocarbons such as crude oil and natural gas; the upgrading of production from oil sands into synthetic oil; power generation; the conversion of crude oil and natural gas into refined hydrocarbon products; the processing, liquefaction and regasification of natural gas; the transportation of

crude oil, natural gas and related products and consumers’ or customers’ use of the company’s hydrocarbon products. Many 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. In addition, increasing attention to climate change risks has resulted in an increased possibility of governmental investigations and additional private litigation against the company.

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

The ultimate effect of international agreements and national, regional and state legislation and regulatory measures to limit GHG emissions on the company’s financial performance, and the timing of these effects, will depend on a number of factors. Such factors include, among others, the sectors covered, the GHG emissions reductions required, the extent to which Chevron would be entitled to receive emission allowance allocations or would need to purchase compliance instruments on the open market or through auctions, the price and availability of emission allowances and credits, and the extent to which the company is able to recover the costs incurred through the pricing of the company’s products in the competitive marketplace. Further, the ultimate impact of GHG emissions-related agreements, legislation and measures on the company’s financial performance is highly uncertain because the company is unable to predict with certainty, for a multitude of individual jurisdictions, the outcome of political decision-making processes and the variables and tradeoffs that inevitably occur in connection with such processes.

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 impairments to property, plant and equipment; estimates of crude oil and natural gas recoverable reserves; accruals for estimated liabilities, including litigation reserves; and measurement of benefit obligations for pension and other postretirement benefit plans. Changes in estimates or assumptions or the information underlying the assumptions, such as changes in the company’s business plans, general market conditions or changes in commodity prices, could affect reported amounts of assets, liabilities or expenses.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

The location and character of the company’s crude oil and natural gas properties and its refining, marketing, transportation and chemicals facilities are described beginning 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 91 through 101. Note 17, “Properties, Plant and Equipment,” to the company’s financial statements is on page 77.

Item 3. Legal Proceedings

Governmental Proceedings The following is a description of legal proceedings that the company has determined to disclose for this reporting period that involve governmental authorities and certain monetary sanctions under federal, state and local laws that have been enacted or adopted regulating the discharge of materials into the environment or primarily for the purpose of protecting the environment.

As previously disclosed, on August 6, 2012, a piping failure and fire occurred at the Chevron refinery in Richmond, California. The United States Environmental Protection Agency (EPA) issued alleged findings of violation related to the incident on

December 17, 2013, pursuant to its authority under the Clean Air Act Risk Management Plan program (RMP). Following the Richmond incident, EPA also conducted RMP inspections at Chevron’s refineries in El Segundo, California; Pascagoula, Mississippi; Kapolei, Hawaii; and Salt Lake City, Utah. On October 24, 2018, the U.S. Department of Justice (DOJ) lodged with the United States District Court for the Northern District of California a consent decree executed by Chevron, DOJ, EPA, and the State of Mississippi that resolves all of EPA’s alleged findings of violation related to the Richmond incident and subsequent RMP inspections. The consent decree includes the payment of a civil penalty of $2.95 million and the funding of supplemental environmental projects totaling $10 million. Chevron also agreed, as part of the consent decree, to investments in process safety enhancements at its current refineries, estimated at $150 million, a portion of which has already been spent. The consent decree is pending court approval.

Chevron facilities within the jurisdiction of California’s Bay Area Air Quality Management District (BAAQMD) currently have multiple outstanding Notices of Violation (NOVs) issued by BAAQMD. Resolution of the alleged violations may result in the payment of a civil penalty of $100,000 or more. As previously disclosed, on June 26, 2018, Chevron received a proposal from the BAAQMD seeking to collectively resolve certain NOVs issued between 2015 and 2017 to Chevron’s Richmond Refinery. On November 5, 2018, Chevron and the BAAQMD entered into a settlement agreement to resolve allegations in the disputed NOVs for a civil penalty of $222,000.

Chevron facilities within the jurisdiction of California’s South Coast Air Quality Management District (SCAQMD) currently have multiple outstanding NOVs issued by SCAQMD. Resolution of the alleged violations may result in the payment of a civil penalty of $100,000 or more.

Other Proceedings Information related to other legal proceedings is included beginning on page 70 in Note 15 to the Consolidated Financial Statements.

Item 4. Mine Safety Disclosures

Not applicable.

Executive Officers of the Registrant

Information relating to the company's executive officers is included under “Executive Officers” in Part III, Item 10, “Directors, Executive Officers and Corporate Governance” on page 24, and is incorporated herein by reference.

PART II

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

The company’s common stock is listed on the New York Stock Exchange (trading symbol: CVX). As of February 11, 2019, stockholders of record numbered approximately 124,000. There are no restrictions on the company’s ability to pay dividends. The information on Chevron’s dividends are contained in the Quarterly Results tabulations on page 47.

Chevron Corporation Issuer Purchases of Equity Securities for Quarter Ended December 31, 2018



	Total Number	Average		Total Number of Shares	Maximum Number of Shares
	of Shares	Price Paid		Purchased as Part of Publicly	That May Yet be Purchased
Period	Purchased^1,2	per Share		Announced Program	Under the Program²
Oct. 1 – Oct. 31, 2018	2,472,282		$118.35	2,472,126	—
Nov. 1 – Nov. 30, 2018	3,130,770	117.24		3,130,770	—
Dec. 1 – Dec. 31, 2018	3,046,000		$111.75	3,046,000	—
Total Oct. 1 – Dec. 31, 2018	8,649,052		$115.62	8,648,896	—


¹	Includes common shares repurchased from company employees and directors for 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 and director stock options. The options were issued to and exercised by management under Chevron long-term incentive plans.


²	Refer to "Liquidity and Capital Resources" on page 38 for additional detail regarding the company's authorized stock repurchase program.

Item 6. Selected Financial Data

The selected financial data for years 2014 through 2018 are presented on page 90.

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 27.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

The company’s discussion of interest rate, foreign currency and commodity price market risk is contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations — “Financial and Derivative Instrument Market Risk,” beginning on page 41 and in Note 9 to the Consolidated Financial Statements, “Financial and Derivative Instruments,” beginning on page 64.

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 27.

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 (Exchange Act)) as of the end of the period covered by this report. Based on this evaluation, management concluded that the company’s disclosure controls and procedures were effective as of December 31, 2018.

(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 defined in the Exchange Act Rules 13a-15(f) and 15d-15(f). The company’s management, including the Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of the company’s internal control over financial reporting based on the Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on the results of this evaluation, the company’s management concluded that internal control over financial reporting was effective as of December 31, 2018.

The effectiveness of the company’s internal control over financial reporting as of December 31, 2018, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report included herein.

(c) Changes in Internal Control Over Financial Reporting During the quarter ended December 31, 2018, there were no changes in the company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the company’s internal control over financial reporting.

Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Executive Officers of the Registrant at February 22, 2019

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



Name	Age	Current and Prior Positions (up to five years)	Primary Areas of Responsibility
M.K. Wirth	58	Chairman of the Board and Chief Executive Officer (since Feb 2018) Vice Chairman of the Board (Feb 2017 - Jan 2018) and Executive Vice President, Midstream and Development (Jan 2016 - Jan 2018) Executive Vice President, Downstream (Mar 2006 - Dec 2015)	Chairman of the Board and Chief Executive Officer
J.W. Johnson	59	Executive Vice President, Upstream (since Jun 2015) Senior Vice President, Upstream (Jan 2014 - Jun 2015)	Worldwide Exploration and Production Activities
P.R. Breber¹	54	Executive Vice President, Downstream (since Jan 2016) Executive Vice President, Gas and Midstream (Apr 2015 - Dec 2015) Vice President, Gas and Midstream (Jan 2014 - Mar 2015)	Worldwide Manufacturing, Marketing and Lubricants; Chemicals
J.C. Geagea	59	Executive Vice President, Technology, Projects and Services (since Jun 2015) Senior Vice President, Technology, Projects and Services (Jan 2014 - Jun 2015)	Technology; Health, Environment and Safety; Project Resources Company; Procurement
M.A. Nelson²	55	Vice President, Midstream, Strategy and Policy (since Feb 2018) Vice President, Strategic Planning (Apr 2016 - Jan 2018) President, International Products (Jun 2010 - Mar 2016)	Corporate Strategy; Policy, Government and Public Affairs; Supply and Trading Activities; Shipping; Pipeline; Power and Energy Management
P.E. Yarrington¹	62	Vice President and Chief Financial Officer (since Jan 2009)	Finance
R.H. Pate	56	Vice President and General Counsel (since Aug 2009)	Law, Governance and Compliance
R.J. Morris	53	Vice President and Chief Human Resources Officer (since Feb 2019) Vice President, Human Resources (Oct 2016 - Jan 2019) Vice President, Downstream Human Resources (Sep 2012 - Sep 2016)	Human Resources; Health and Medical; Diversity and Inclusion
¹ Effective April 1, 2019, Mr. Breber will assume the position of Vice President and Chief Financial Officer
² Effective March 1, 2019, Mr. Nelson will assume the position of Executive Vice President, Downstream

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 2019 Annual Meeting of Stockholders and 2019 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 2019 Annual Meeting (the “2019 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 2019 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

The information required by Item 406 of Regulation S-K and contained under the heading “Corporate Governance — Business Conduct and Ethics Code” in the 2019 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

The information required by Item 407(d)(4) and (5) of Regulation S-K and contained under the heading “Corporate Governance — Board Committees” in the 2019 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

Item 11. Executive Compensation

The information required by Item 402 of Regulation S-K and contained under the headings “Executive Compensation,” “CEO Pay Ratio” and “Director Compensation” in the 2019 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

The information required by Item 407(e)(4) of Regulation S-K and contained under the heading “Corporate Governance — Board Committees” in the 2019 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

The information required by Item 407(e)(5) of Regulation S-K and contained under the heading “Corporate Governance — Management Compensation Committee Report” in the 2019 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 2019 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 2019 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 2019 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

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

The information required by Item 404 of Regulation S-K and contained under the heading “Corporate Governance — Related Person Transactions” in the 2019 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

The information required by Item 407(a) of Regulation S-K and contained under the heading “Corporate Governance — Director Independence” in the 2019 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

Item 14. Principal Accounting Fees and Services

The information required by Item 9(e) of Schedule 14A and contained under the heading “Board Proposal to Ratify PricewaterhouseCoopers LLP as the Independent Registered Public Accounting Firm for 2019” in the 2019 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

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Financial Table of Contents






	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Key Financial Results	28
	Earnings by Major Operating Area	28
	Business Environment and Outlook	28
	Operating Developments	31
	Results of Operations	32
	Consolidated Statement of Income	34
	Selected Operating Data	37
	Liquidity and Capital Resources	38
	Financial Ratios	40
	Off-Balance-Sheet Arrangements, Contractual Obligations, Guarantees and Other Contingencies	40
	Financial and Derivative Instrument Market Risk	41
	Transactions With Related Parties	42
	Litigation and Other Contingencies	42
	Environmental Matters	43
	Critical Accounting Estimates and Assumptions	43
	New Accounting Standards	46
	Quarterly Results	47

	Consolidated Financial Statements
	Reports of Management	48
	Report of Independent Registered Public Accounting Firm	49
	Consolidated Statement of Income	50
	Consolidated Statement of Comprehensive Income	51
	Consolidated Balance Sheet	52
	Consolidated Statement of Cash Flows	53
	Consolidated Statement of Equity	54






Notes to the Consolidated Financial Statements
Note 1	Summary of Significant Accounting Policies	55
Note 2	Changes in Accumulated Other Comprehensive Losses	58
Note 3	Information Relating to the Consolidated Statement of Cash Flows	59
Note 4	New Accounting Standards	60
Note 5	Lease Commitments	62
Note 6	Summarized Financial Data – Chevron U.S.A. Inc.	63
Note 7	Summarized Financial Data – Tengizchevroil LLP	63
Note 8	Fair Value Measurements	63
Note 9	Financial and Derivative Instruments	64
Note 10	Assets Held for Sale	66
Note 11	Equity	66
Note 12	Earnings Per Share	66
Note 13	Operating Segments and Geographic Data	66
Note 14	Investments and Advances	69
Note 15	Litigation	70
Note 16	Taxes	74
Note 17	Properties, Plant and Equipment	77
Note 18	Short-Term Debt	77
Note 19	Long-Term Debt	78
Note 20	Accounting for Suspended Exploratory Wells	79
Note 21	Stock Options and Other Share-Based Compensation	80
Note 22	Employee Benefit Plans	81
Note 23	Other Contingencies and Commitments	86
Note 24	Asset Retirement Obligations	88
Note 25	Revenue	88
Note 26	Other Financial Information	89

Five-Year Financial Summary		90
Supplemental Information on Oil and Gas Producing Activities		91

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

Key Financial Results



Millions of dollars, except per-share amounts	2018			2017			2016
Net Income (Loss) Attributable to Chevron Corporation	$	14,824		$	9,195		$	(497	)
Per Share Amounts:
Net Income (Loss) Attributable to Chevron Corporation
– Basic	$	7.81		$	4.88		$	(0.27	)
– Diluted	$	7.74		$	4.85		$	(0.27	)
Dividends	$	4.48		$	4.32		$	4.29
Sales and Other Operating Revenues	$	158,902		$	134,674		$	110,215
Return on:
Capital Employed	8.2		%	5.0		%	(0.1		)%
Stockholders’ Equity	9.8		%	6.3		%	(0.3		)%
Earnings by Major Operating Area
Millions of dollars	2018			2017			2016
Upstream
United States	$	3,278		$	3,640		$	(2,054	)
International	10,038			4,510			(483		)
Total Upstream	13,316			8,150			(2,537		)
Downstream
United States	2,103			2,938			1,307
International	1,695			2,276			2,128
Total Downstream	3,798			5,214			3,435
All Other	(2,290		)	(4,169		)	(1,395		)
Net Income (Loss) Attributable to Chevron Corporation^1,2	$	14,824		$	9,195		$	(497	)
¹ Includes foreign currency effects:	$	611		$	(446	)	$	58
²Income net of tax, also referred to as “earnings” in the discussions that follow.

Refer to the “Results of Operations” section beginning on page 32 for a discussion of financial results by major operating area for the three years ended December 31, 2018.

Business Environment and Outlook

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

Earnings of the company depend mostly on the profitability of its upstream business segment. The most significant factor affecting the results of operations for the upstream segment is the price of crude oil, which is determined in global markets outside of the company’s control. In the company's downstream business, crude oil is the largest cost component of refined products. It is the company's objective to deliver competitive results and stockholder value in any business environment. Periods of sustained lower prices could result in the impairment or write-off of specific assets in future periods and cause the company to adjust operating expenses and capital and exploratory expenditures, along with other measures intended to improve financial performance.

The effective tax rate for the company can change substantially during periods of significant earnings volatility. This is due to the mix effects that are impacted both by the absolute level of earnings or losses and whether they arise in higher or lower tax rate jurisdictions. As a result, a decline or increase in the effective income tax rate in one period may not be indicative of expected results in future periods. Note 16 provides the company’s effective income tax rate for the last three years.

Refer to the "Cautionary Statement Relevant to Forward-Looking Information" on page 2 and to "Risk Factors" in Part I, Item 1A, on pages 18 through 21 for a discussion of some of the inherent risks that could materially impact the company's results of operations or financial condition.

The company continually evaluates opportunities to dispose of assets that are not expected to provide sufficient long-term value or to acquire assets or operations complementary to its asset base to help augment the company’s financial performance and value growth. Asset dispositions and restructurings may result in significant gains or losses in future periods. The company's asset sale program for 2018 through 2020 is targeting before-tax proceeds of $5-10 billion. Proceeds related to asset sales were $2.0 billion in 2018.

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

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

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

Upstream Earnings for the upstream segment are closely aligned with industry 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 production and inventory levels, technology advancements, production quotas or other actions imposed by the Organization of Petroleum Exporting Countries (OPEC) or other producers, actions of regulators, weather-related damage and disruptions, competing fuel prices, and regional supply interruptions or fears thereof that may be caused by military conflicts, civil unrest or political uncertainty. Any of these factors could also inhibit the company’s production capacity in an affected region. The company closely monitors developments in the countries in which it operates and holds investments, and seeks to manage risks in operating its facilities and businesses. The longer-term trend in earnings for the upstream segment is also a function of other factors, including the company’s ability to find or acquire and efficiently produce crude oil and natural gas, changes in fiscal terms of contracts, and changes in tax and other applicable laws and regulations.

The company continues to actively manage its schedule of work, contracting, procurement and supply-chain activities to effectively manage costs. However, price levels for capital and exploratory costs and operating expenses associated with the production of crude oil and natural gas can be subject to external factors beyond the company’s control including, among other things, the general level of inflation, tariffs or other taxes imposed on goods or services, 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. Modest cost pressures continue in rig-related services across North America unconventional markets. Cost pressures have softened in well completion activity particularly in the Permian Basin, but are expected to rise when pipeline takeaway constraints are resolved in late 2019. International and offshore markets are showing indications of increased activity levels with limited cost pressures to date.

Capital and exploratory expenditures and operating expenses could also be affected by damage to production facilities caused by severe weather or civil unrest, delays in construction, or other factors.

The chart above shows the trend in benchmark prices for Brent crude oil, West Texas Intermediate (WTI) crude oil and U.S. Henry Hub natural gas. The majority of the company’s equity crude production is priced based on the Brent benchmark. The Brent price averaged $71 per barrel for the full-year 2018, compared to $54 in 2017. Crude oil prices increased throughout the first three quarters of 2018 due to solid demand combined with OPEC production cuts. Late in the year, continued U.S. shale growth, combined with unexpected short-term waivers from Iranian sanctions granted to several countries, led to excess supply conditions, resulting in a decrease in oil prices. In response, OPEC agreed to new production cuts in early December. As of mid-February 2019, the Brent price was $64 per barrel.

The WTI price averaged $65 per barrel for the full-year 2018, compared to $51 in 2017. WTI traded at a discount to Brent throughout 2018. Differentials to Brent have ranged between $3 to $10 in 2018 primarily due to pipeline infrastructure constraints which have restricted flows on the inland crude to export outlets on the Gulf Coast, in addition to variability in

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

other factors impacting supply and demand of each benchmark crude. As of mid-February 2019, the WTI price was $54 per barrel.

Chevron has interests in the production of heavy crude oil in California, Indonesia, the Partitioned Zone between Saudi Arabia and Kuwait, Venezuela and in certain fields in Angola, China and the United Kingdom sector of the North Sea. (See page 37 for the company’s average U.S. and international crude oil sales prices.)

In contrast to price movements in the global market for crude oil, price changes for natural gas are more closely aligned with supply-and-demand conditions in regional markets. Fluctuations in the price of natural gas in the United States are closely associated with customer demand relative to the volumes produced and stored in North America. In the United States, prices at Henry Hub averaged $3.12 per thousand cubic feet (MCF) during 2018, compared with $2.97 during 2017. As of mid-February 2019, the Henry Hub spot price was $2.61 per MCF.

Outside the United States, price changes for natural gas depend on a wide range of supply, demand and regulatory circumstances. Chevron sells natural gas into the domestic pipeline market in many locations. In some locations, Chevron has invested in long-term projects to produce and liquefy natural gas for transport by tanker to other markets. The company's long-term contract prices for liquefied natural gas (LNG) are typically linked to crude oil prices. Most of the equity LNG offtake from the operated Australian LNG projects is committed under binding long-term contracts, with the remainder to be sold in the Asian spot LNG market. The Asian spot market reflects the supply and demand for LNG in the Pacific Basin and is not directly linked to crude oil prices. International natural gas realizations averaged $6.29 per MCF during 2018, compared with $4.62 per MCF during 2017. (See page 37 for the company’s average natural gas realizations for the U.S. and international regions.)

The company’s worldwide net oil-equivalent production in 2018 averaged 2.930 million barrels per day. About one-sixth of the company’s net oil-equivalent production in 2018 occurred in the OPEC-member countries of Angola, Nigeria, Republic of Congo and Venezuela. OPEC quotas had no effect on the company’s net crude oil production in 2018 or 2017.

The company estimates that net oil-equivalent production in 2019 will grow 4 to 7 percent compared to 2018, assuming a Brent crude oil price of $60 per barrel and excluding the impact of anticipated 2019 asset sales. This estimate is subject to many factors and uncertainties, including quotas or other actions that may be imposed by OPEC; price effects on entitlement volumes; changes in fiscal terms or restrictions on the scope of company operations; delays in construction; reservoir performance; greater-than-expected declines in production from mature fields; start-up or ramp-up of projects; fluctuations in demand for natural gas in various markets; weather conditions that may shut in production; civil unrest; changing geopolitics; delays in completion of maintenance turnarounds; or other disruptions to operations. The outlook for future production levels is also affected by the size and number of economic investment opportunities and the time lag between initial exploration and the beginning of production. The company has increased its investment emphasis on short-cycle projects.

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

In the Partitioned Zone between Saudi Arabia and Kuwait, production was shut-in beginning in May 2015 as a result of difficulties in securing work and equipment permits. Net oil-equivalent production in the Partitioned Zone in 2014 was 81,000 barrels per day. During 2015, net oil-equivalent production averaged 28,000 barrels per day. As of early 2019, production remains shut in and the exact timing of a production restart is uncertain and dependent on dispute resolution between Saudi Arabia and Kuwait. The financial effects from the loss of production in 2018 were not significant and are not expected to be significant in 2019.

Chevron has interests in Venezuelan crude oil production assets operated by independent equity affiliates. During 2018, net oil equivalent production in Venezuela averaged 44,000 barrels per day. The operating environment in Venezuela has been deteriorating for some time. In January 2019, the United States government issued sanctions against the Venezuelan national oil company, Petroleos de Venezuela, S.A. (PdVSA), which is the company’s partner in the equity affiliates. The equity affiliates continue to operate, and the company is conducting its business pursuant to general licenses issued coincident with the new sanctions. Future events could result in the environment in Venezuela becoming more challenged, which could lead to increased business disruption and volatility in the associated financial results.

Net proved reserves for consolidated companies and affiliated companies totaled 12.1 billion barrels of oil-equivalent at year-end 2018, an increase of 3 percent from year-end 2017. The reserve replacement ratio in 2018 was 136 percent. Refer to Table V beginning on page 95 for a tabulation of the company’s proved net oil and gas reserves by geographic area, at the beginning of 2016 and each year-end from 2016 through 2018, and an accompanying discussion of major changes to proved reserves by geographic area for the three-year period ending December 31, 2018.

Refer to the “Results of Operations” section on pages 32 through 34 for additional discussion of the company’s upstream business.

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

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

The company’s most significant marketing areas are the West Coast and Gulf Coast of the United States and Asia. Chevron operates or has significant ownership interests in refineries in each of these areas.

Refer to the “Results of Operations” section on pages 32 through 34 for additional discussion of the company’s downstream operations.

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

Operating Developments

Key operating developments and other events during 2018 and early 2019 included the following:

Upstream

Australia Achieved start-up of Train 2 at the Wheatstone LNG Project.

United States Produced first oil from the Big Foot Project in the deepwater Gulf of Mexico.

Downstream

South Africa and Botswana Completed the sale of refining, marketing and lubricant assets.

United States Chevron Phillips Chemical Company LLC (CPChem), the company’s 50 percent-owned affiliate, commenced operations of a new ethane cracker at its Cedar Bayou facility in Baytown, Texas.

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

United States In January 2019, Chevron announced it has signed an agreement to acquire a 110,000 barrels per day refinery located in Pasadena, Texas. The transaction is expected to close later in the first-half of 2019, subject to regulatory approvals.

Other

Common Stock Dividends The 2018 annual dividend was $4.48 per share, making 2018 the 31st consecutive year that the company increased its annual per share dividend payout. In January 2019, the company's Board of Directors approved a $0.07 per share increase in the quarterly dividend to $1.19 per share, payable in March 2019, representing an increase of 6 percent.

Common Stock Repurchase Program The company purchased $1.75 billion of its common stock in 2018 under its stock repurchase program.

Results of Operations

The following section presents the results of operations and variances on an after-tax basis for the company’s business segments – Upstream and Downstream – as well as for “All Other.” Earnings are also presented for the U.S. and international geographic areas of the Upstream and Downstream business segments. Refer to Note 13, beginning on page 66, for a discussion of the company’s “reportable segments.” This section should also be read in conjunction with the discussion in “Business Environment and Outlook” on pages 28 through 31.

U.S. Upstream



Millions of dollars	2018		2017		2016
Earnings	$	3,278	$	3,640	$	(2,054	)

U.S. upstream earnings were $3.28 billion in 2018, compared with $3.64 billion in 2017. The decrease in earnings was primarily due to the absence of the 2017 benefit from U.S. tax reform of $3.33 billion, higher other tax items of $160 million and higher exploration expense of $350 million, partially offset by higher crude oil realizations of $2.45 billion and higher crude oil production of $1.12 billion.

U.S. upstream earnings were $3.64 billion in 2017, compared with a loss of $2.05 billion from 2016. The improvement in earnings reflected a benefit of $3.33 billion from U.S. tax reform, higher crude oil and natural gas realizations of $1.3 billion and lower depreciation expenses of $650 million, primarily reflecting a decrease in impairments and other asset write-offs. Lower operating expenses of $140 million also contributed to the improvement.

The company’s average realization for U.S. crude oil and natural gas liquids in 2018 was $58.17 per barrel, compared with $44.53 in 2017 and $35.00 in 2016. The average natural gas realization was $1.86 per thousand cubic feet in 2018, compared with $2.10 in 2017 and $1.59 in 2016.

Net oil-equivalent production in 2018 averaged 791,000 barrels per day, up 16 percent from 2017 and up 14 percent from 2016. Between 2018 and 2017, production increases from shale and tight properties in the Permian Basin in Texas and New

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

Mexico and base business in the Gulf of Mexico were partially offset by the effect of asset sales of 35,000 barrels per day. Between 2017 and 2016, production increases from shale and tight properties in the Permian Basin in Texas and New Mexico and base business in the Gulf of Mexico were more than offset by the effect of asset sales of 59,000 barrels per day and normal field declines.

The net liquids component of oil-equivalent production for 2018 averaged 618,000 barrels per day, up 19 percent from 2017 and up 23 percent from 2016. Net natural gas production averaged 1.03 billion cubic feet per day in 2018, up 7 percent from 2017 and down 8 percent from 2016. Refer to the “Selected Operating Data” table on page 37 for a three-year comparison of production volumes in the United States.

International Upstream



Millions of dollars	2018		2017			2016
Earnings^*	$	10,038	$	4,510		$	(483	)
^*Includes foreign currency effects:	$	545	$	(456	)	$	122

International upstream earnings were $10.04 billion in 2018, compared with $4.51 billion in 2017. The increase in earnings was primarily due to higher crude oil and natural gas realizations of $3.38 billion and $1.38 billion, respectively, higher natural gas sales volumes of $1.67 billion, partially offset by lower gains on asset sales of $640 million, higher depreciation, operating and tax expenses of $470 million, $460 million and $230 million, respectively. Foreign currency effects had a favorable impact on earnings of $1.00 billion between periods.

International upstream earnings were $4.51 billion in 2017, compared with a loss of $483 million in 2016. The increase in earnings was primarily due to higher crude oil realizations of $2.59 billion, higher natural gas sales volumes of $1.22 billion, higher gains on asset sales of $750 million, and lower operating expenses of $410 million. Foreign currency effects had an unfavorable impact on earnings of $578 million between periods.

The company’s average realization for international crude oil and natural gas liquids in 2018 was $64.25 per barrel, compared with $49.46 in 2017 and $38.61 in 2016. The average natural gas realization was $6.29 per thousand cubic feet in 2018, compared with $4.62 and $4.02 in 2017 and 2016, respectively.

International net oil-equivalent production was 2.14 million barrels per day in 2018, up 4 percent from 2017 and up 12 percent from 2016. Between 2018 and 2017, production increases from major capital projects, primarily Wheatstone and Gorgon in Australia, were partially offset by normal field declines, production entitlement effects and the impact of asset sales of 14,000 barrels per day. Between 2017 and 2016, production increases from major capital projects and lower planned maintenance-related downtime were partially offset by production entitlement effects in several locations and normal field declines.

The net liquids component of international oil-equivalent production was 1.16 million barrels per day in 2018, down 3 percent from 2017 and down 4 percent from 2016. International net natural gas production of 5.86 billion cubic feet per day in 2018 was up 16 percent from 2017 and up 42 percent from 2016.

Refer to the “Selected Operating Data” table, on page 37, for a three-year comparison of international production volumes.

U.S. Downstream



Millions of dollars	2018		2017		2016
Earnings	$	2,103	$	2,938	$	1,307

U.S. downstream operations earned $2.10 billion in 2018, compared with $2.94 billion in 2017. The decrease was mainly due to the absence of the 2017 benefit from U.S. tax reform of $1.16 billion and higher operating expenses of $420 million, primarily due to planned refinery turnaround activity. Partially offsetting these were higher margins on refined product sales of $380 million and higher equity earnings from the 50 percent-owned CPChem of $320 million, primarily reflecting the absence of impacts from Hurricane Harvey.

U.S. downstream operations earned $2.94 billion in 2017, compared with $1.31 billion in 2016. The increase was primarily due to a $1.16 billion benefit from U.S. tax reform, higher margins on refined product sales of $380 million, lower operating expenses of $160 million, and the absence of an asset impairment of $110 million. Partially offsetting this increase were lower gains on asset sales of $90 million and lower earnings from the 50 percent-owned CPChem of $70 million, primarily reflecting the impacts from Hurricane Harvey.

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

Total refined product sales of 1.22 million barrels per day in 2018 were up 2 percent from 2017. Sales were 1.20 million barrels per day in 2017, a decrease of 1 percent from 2016, primarily due to the divestment of Hawaii refining and marketing assets in fourth quarter 2016.

Refer to the “Selected Operating Data” table on page 37 for a three-year comparison of sales volumes of gasoline and other refined products and refinery input volumes.

International Downstream



Millions of dollars	2018		2017			2016
Earnings^*	$	1,695	$	2,276		$	2,128
^*Includes foreign currency effects:	$	71	$	(90	)	$	(25	)

International downstream earned $1.70 billion in 2018, compared with $2.28 billion in 2017. The decrease in earnings was largely due to lower margins on refined product sales of $590 million and lower gains on asset sales of $470 million, partially offset by lower operating expenses of $290 million. The sale of the company's Canadian refining and marketing business in third quarter 2017 and the sale of the southern Africa refining and marketing business in third quarter 2018 primarily contributed to the lower margins and operating expenses. Foreign currency effects had a favorable impact on earnings of $161 million between periods.

International downstream earned $2.28 billion in 2017, compared with $2.13 billion in 2016. The increase in earnings was primarily due to higher gains on asset sales of $360 million, partially offset by higher operating expenses of $140 million. Foreign currency effects had an unfavorable impact on earnings of $65 million between periods.

Total refined product sales of 1.44 million barrels per day in 2018 were down 4 percent from 2017, primarily due to the sales of the company's Canadian refining and marketing assets in third quarter 2017 and southern Africa refining and marketing business in third quarter 2018. Sales of 1.49 million barrels per day in 2017 were up 2 percent from 2016, primarily due to higher diesel and jet fuel sales.

Refer to the “Selected Operating Data” table on page 37, for a three-year comparison of sales volumes of gasoline and other refined products and refinery input volumes.

All Other



Millions of dollars	2018			2017			2016
Net charges^*	$	(2,290	)	$	(4,169	)	$	(1,395	)
^*Includes foreign currency effects:	$	(5	)	$	100		$	(39	)

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

Net charges in 2018 decreased $1.88 billion from 2017. The change between periods was mainly due to absence of a prior year tax charge of $2.47 billion related to U.S. tax reform, lower employee expenses and the absence of a reclamation related charge for a former mining asset, partially offset by other unfavorable tax items and higher interest expense. Foreign currency effects increased net charges by $105 million between periods. Net charges in 2017 increased $2.77 billion from 2016, mainly due to higher tax items, primarily reflecting a $2.47 billion expense from U.S. tax reform, higher interest expense and a reclamation related charge for a former mining asset, partially offset by lower employee expense. Foreign currency effects decreased net charges by $139 million between periods.

Consolidated Statement of Income

Comparative amounts for certain income statement categories are shown below:



Millions of dollars	2018		2017		2016
Sales and other operating revenues	$	158,902	$	134,674	$	110,215

Sales and other operating revenues increased in 2018 mainly due to higher crude oil, refined product and natural gas prices. The increase between 2017 and 2016 was primarily due to higher refined product and crude oil prices, higher crude oil volumes, and higher natural gas volumes.

Beginning in 2018, excise, value-added and similar taxes collected on behalf of third parties were no longer included in "Sales and other operating revenue", but were netted in "Taxes other than on income" in accordance with ASU 2014-09. 2017 and 2016 include $7.19 billion and $6.91 billion, respectively, in taxes collected on behalf of third parties.

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



Millions of dollars	2018		2017		2016
Income from equity affiliates	$	6,327	$	4,438	$	2,661

Income from equity affiliates increased in 2018 from 2017 mainly due to higher upstream-related earnings from Tengizchevroil in Kazakhstan, Petroboscan and Petropiar in Venezuela, and higher downstream-related earnings from CPChem.

Income from equity affiliates increased in 2017 from 2016 mainly due to higher upstream-related earnings from Tengizchevroil in Kazakhstan and Angola LNG.

Refer to Note 14, beginning on page 69, for a discussion of Chevron’s investments in affiliated companies.



Millions of dollars	2018		2017		2016
Other income	$	1,110	$	2,610	$	1,596

Other income of $1.1 billion in 2018 included net gains from asset sales of $713 million before-tax. Other income in 2017 and 2016 included net gains from asset sales of $2.2 billion and $1.1 billion before-tax, respectively. Interest income was approximately $192 million in 2018, $107 million in 2017 and $145 million in 2016. Foreign currency effects decreased other income by $123 million in 2018, $131 million in 2017, and $186 million in 2016.



Millions of dollars	2018		2017		2016
Purchased crude oil and products	$	94,578	$	75,765	$	59,321

Crude oil and product purchases increased $18.8 billion in 2018, primarily due to higher crude oil and refined product prices, partially offset by lower crude oil volumes. Purchases increased $16.4 billion in 2017, primarily due to higher crude oil and refined product prices, and higher refined product and crude oil volumes.



Millions of dollars	2018		2017		2016
Operating, selling, general and administrative expenses	$	24,382	$	23,237	$	24,207

Operating, selling, general and administrative expenses increased $1.1 billion between 2018 and 2017. The increase included higher services and fees of $450 million, a receivable write-down for $270 million, higher transportation expenses of $200 million, and a contractual settlement for $180 million.

Operating, selling, general and administrative expenses decreased $1.0 billion between 2017 and 2016. The decrease included lower employee expenses of $690 million and non-operated joint venture expenses of $380 million.



Millions of dollars	2018		2017		2016
Exploration expense	$	1,210	$	864	$	1,033

Exploration expenses in 2018 increased from 2017 primarily due to higher charges for well write-offs, partially offset by lower geological and geophysical expenses. Exploration expenses in 2017 decreased from 2016 primarily due to lower charges for well write-offs.



Millions of dollars	2018		2017		2016
Depreciation, depletion and amortization	$	19,419	$	19,349	$	19,457

Depreciation, depletion and amortization expenses increased in 2018 from 2017 mainly due to higher production levels for certain oil and gas producing fields, partially offset by lower depreciation rates for certain oil and gas producing fields, and lower impairment charges.

The decrease in 2017 from 2016 was primarily due to lower impairments and lower depreciation rates for certain oil and gas producing properties, and the absence of a 2016 impairment of a downstream asset. Partially offsetting the decrease were higher production levels, accretion and write-offs for certain oil and gas producing fields, and a reclamation related charge for a former mining asset.



Millions of dollars	2018		2017		2016
Taxes other than on income	$	4,867	$	12,331	$	11,668

Beginning in 2018, excise, value-added and similar taxes collected on behalf of third parties were netted in "Taxes other than on income" and were no longer included in "Sales and other operating revenues," in accordance with ASU 2014-09. 2017 and 2016 include $7.19 billion and $6.91 billion, respectively, in taxes collected on behalf of third parties. The further decrease in 2018 from 2017 was mainly due to lower local and municipal taxes and licenses, partially offset by higher duties reflecting

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

increased production. Taxes other than on income increased in 2017 from 2016 primarily due to higher duties, higher crude oil, refined product and natural gas sales, and higher production.



Millions of dollars	2018		2017		2016
Interest and debt expense	$	748	$	307	$	201

Interest and debt expenses increased in 2018 from 2017 mainly due to a decrease in the amount of interest capitalized. Interest and debt expenses increased in 2017 from 2016 due to higher interest costs on long-term debt, partially offset by an increase in the amount of interest capitalized.



Millions of dollars	2018		2017		2016
Other components of net periodic benefit costs	$	560	$	648	$	745

Other components of net periodic benefit costs decreased in 2018 from 2017 primarily due to a higher asset base for expected returns and a decrease in recognized actuarial losses arising during the period. The decrease in 2017 from 2016 was mainly due to lower interest costs, lower settlement costs, and a decrease in amortization of prior service costs, partially offset by an increase in plan asset values. This line was added to the Consolidated Statement of Income in accordance with the adoption of ASU 2017-07.



Millions of dollars	2018		2017			2016
Income tax expense (benefit)	$	5,715	$	(48	)	$	(1,729	)

The increase in income tax expense in 2018 of $5.76 billion is due to the increase in total income before tax for the company of $11.35 billion and the absence of the remeasurement benefits from U.S. tax reform recognized in 2017.

U.S. income before tax increased from a loss of $441 million in 2017 to a profit of $4.73 billion in 2018. This increase in earnings before tax was primarily driven by the effect of higher crude oil prices. The U.S. tax charge increased by $3.69 billion between year-over-year periods from a $2.97 billion benefit in 2017 to a $724 million charge in 2018. 2017 included a $2.02 billion benefit from U.S. tax reform, which primarily reflected the remeasurement of U.S. deferred tax assets and liabilities.

International income before tax increased from $9.66 billion in 2017 to $15.84 billion in 2018. This $6.18 billion increase was primarily driven by the effect of higher crude oil prices. The higher crude prices primarily drove the $2.06 billion increase in international income tax expense between year-over-year periods, from $2.93 billion in 2017 to $4.99 billion in 2018.

The decline in income tax benefit in 2017 of $1.68 billion is due to the increase in total income before tax for the company of $11.38 billion and the remeasurement impacts of U.S. tax reform. U.S. losses before tax decreased from a loss of $4.32 billion in 2016 to a loss of $441 million in 2017. This decrease in losses before tax was primarily driven by the effect of higher crude oil prices. The U.S. tax benefit increased by $650 million between year-over-year periods from $2.32 billion in 2016 to $2.97 billion in 2017. The U.S. tax benefit for 2017 included a $2.02 billion benefit from U.S. tax reform, which primarily reflected the remeasurement of U.S. deferred tax assets and liabilities, and a reduction of $1.37 billion as result of the impact of a decrease in losses before tax of $3.88 billion.

International income before tax increased from $2.16 billion in 2016 to $9.66 billion in 2017. This $7.50 billion increase was primarily driven by the effect of higher crude oil prices and gains on asset sales primarily in Indonesia and Canada. The higher crude prices primarily drove the $2.34 billion increase in international income tax expense between year-over-year periods, from $588 million in 2016 to $2.93 billion in 2017.

Refer also to the discussion of the effective income tax rate in Note 16 on page 74.

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

Selected Operating Data^1,2



	2018		2017		2016
U.S. Upstream
Net Crude Oil and Natural Gas Liquids Production (MBPD)	618		519		504
Net Natural Gas Production (MMCFPD)³	1,034		970		1,120
Net Oil-Equivalent Production (MBOEPD)	791		681		691
Sales of Natural Gas (MMCFPD)	3,481		3,331		3,317
Sales of Natural Gas Liquids (MBPD)	110		30		30
Revenues from Net Production
Liquids ($/Bbl)	$	58.17	$	44.53	$	35.00
Natural Gas ($/MCF)	$	1.86	$	2.10	$	1.59
International Upstream
Net Crude Oil and Natural Gas Liquids Production (MBPD)⁴	1,164		1,204		1,215
Net Natural Gas Production (MMCFPD)³	5,855		5,062		4,132
Net Oil-Equivalent Production (MBOEPD)⁴	2,139		2,047		1,903
Sales of Natural Gas (MMCFPD)	5,604		5,081		4,491
Sales of Natural Gas Liquids (MBPD)	34		29		24
Revenues from Liftings
Liquids ($/Bbl)	$	64.25	$	49.46	$	38.61
Natural Gas ($/MCF)	$	6.29	$	4.62	$	4.02
Worldwide Upstream
Net Oil-Equivalent Production (MBOEPD)⁴
United States	791		681		691
International	2,139		2,047		1,903
Total	2,930		2,728		2,594
U.S. Downstream
Gasoline Sales (MBPD)⁵	627		625		631
Other Refined Product Sales (MBPD)	591		572		582
Total Refined Product Sales (MBPD)	1,218		1,197		1,213
Sales of Natural Gas Liquids (MBPD)	74		109		115
Refinery Input (MBPD)⁶	905		901		900
International Downstream
Gasoline Sales (MBPD)⁵	336		365		382
Other Refined Product Sales (MBPD)	1,101		1,128		1,080
Total Refined Product Sales (MBPD)⁷	1,437		1,493		1,462
Sales of Natural Gas Liquids (MBPD)	62		64		61
Refinery Input (MBPD)⁸	706		760		788
¹Includes company share of equity affiliates.
²MBPD – thousands of barrels per day; MMCFPD – millions of cubic feet per day; MBOEPD – thousands of barrels of oil-equivalents per day; Bbl – barrel; MCF – thousands of cubic feet. Oil-equivalent gas (OEG) conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of crude oil.
³ Includes natural gas consumed in operations (MMCFPD):
United States	35		37		54
International	584		528		432
⁴ Includes net production of synthetic oil:
Canada	53		51		50
Venezuela affiliate	24		28		28
⁵ Includes branded and unbranded gasoline.
⁶ In November 2016, the company sold its interests in the Hawaii Refinery, which included operable capacity of 54,000 barrels per day.
⁷ Includes sales of affiliates (MBPD):	373		366		377
⁸ In September 2018, the company sold its interest in the Cape Town Refinery in Cape Town, South Africa, which had an operable capacity of 110,000 barrels per day. In September 2017, the company sold the Burnaby Refinery in British Columbia, Canada, which had operable capacity of 55,000 barrels per day.

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

Liquidity and Capital Resources

Sources and uses of cash

The strength of the company’s balance sheet enabled it to fund any timing differences throughout the year between cash inflows and outflows.

Cash, Cash Equivalents, Marketable Securities and Time Deposits Total balances were $10.3 billion and $4.8 billion at December 31, 2018 and 2017, respectively. Cash provided by operating activities in 2018 was $30.6 billion, compared with $20.3 billion in 2017 and $12.7 billion in 2016, reflecting higher crude oil prices and increased production. Cash provided by operating activities was net of contributions to employee pension plans of approximately $1.0 billion in 2018, $1.0 billion in 2017 and $0.9 billion in 2016. Cash provided by investing activities included proceeds and deposits related to asset sales of $2.0 billion in 2018, $4.9 billion in 2017 and $3.2 billion in 2016.

Restricted cash of $1.1 billion and $1.1 billion at December 31, 2018 and 2017, respectively, was held in cash and short-term marketable securities and recorded as “Deferred charges and other assets” and “Prepaid expenses and other current assets” on the Consolidated Balance Sheet. These amounts are generally associated with upstream abandonment activities, tax payments, funds held in escrow for tax-deferred exchanges and refundable deposits related to pending asset sales.

Dividends Dividends paid to common stockholders were $8.5 billion in 2018, $8.1 billion in 2017 and $8.0 billion in 2016.

Debt and Capital Lease Obligations Total debt and capital lease obligations were $34.5 billion at December 31, 2018, down from $38.8 billion at year-end 2017.

The $4.3 billion decrease in total debt and capital lease obligations during 2018 was primarily due to the repayment of long-term notes totaling $6.7 billion as they matured during 2018, partly offset by an increase in commercial paper. 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 $15.6 billion at December 31, 2018, compared with $15.2 billion at year-end 2017. Of these amounts, $9.9 billion and $10.0 billion were reclassified to long-term debt at the end of 2018 and 2017, respectively.

At year-end 2018, settlement of these obligations was not expected to require the use of working capital in 2019, as the company had the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis.

Chevron has an automatic shelf registration statement that expires in May 2021 for an unspecified amount of nonconvertible debt securities issued or guaranteed by the company.

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

The major debt rating agencies routinely evaluate the company’s debt, and the company’s cost of borrowing can increase or decrease depending on these debt ratings. The company has outstanding public bonds issued by Chevron Corporation and Texaco Capital Inc. All of these securities are the obligations of, or guaranteed by, Chevron Corporation and are rated AA by Standard and Poor’s Corporation and Aa2 by Moody’s Investors Service. The company’s U.S. commercial paper is rated A-1+ by Standard and Poor’s and P-1 by Moody’s. All of these ratings denote high-quality, investment-grade securities.

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

Committed Credit Facilities Information related to committed credit facilities is included in Note 18, Short-Term Debt, on page 77.

Common Stock Repurchase Program In July 2010, the Board of Directors approved an ongoing stock repurchase program with no set term or monetary limits. From the inception of the program through the end of 2018, the company purchased 195.8 million shares for $21.75 billion, including 14.9 million shares for $1.75 billion in the second half 2018. On February 1, 2019, the company announced that the Board of Directors authorized a new stock repurchase program with a maximum dollar limit of $25 billion and no set term limits. Repurchases may be made from time to time in the open market, by block purchases, in privately negotiated transactions or in such other manner as determined by the company. The timing of the repurchases and the actual amount repurchased will depend on a variety of factors, including the market price of the company's shares, general market and economic conditions, and other factors. The stock repurchase program does not obligate the company to acquire any particular amount of common stock, and it may be suspended or discontinued at any time.

Capital and Exploratory Expenditures

Capital and exploratory expenditures by business segment for 2018, 2017 and 2016 are as follows:



	2018						2017						2016
Millions of dollars	U.S.		Int’l.		Total		U.S.		Int’l.		Total		U.S.		Int’l.		Total
Upstream	$	7,128	$	10,529	$	17,657	$	5,145	$	11,243	$	16,388	$	4,713	$	15,403	$	20,116
Downstream	1,582		611		2,193		1,656		534		2,190		1,545		527		2,072
All Other	243		13		256		239		4		243		235		5		240
Total	$	8,953	$	11,153	$	20,106	$	7,040	$	11,781	$	18,821	$	6,493	$	15,935	$	22,428
Total, Excluding Equity in Affiliates	$	8,651	$	5,739	$	14,390	$	6,295	$	7,783	$	14,078	$	5,456	$	13,202	$	18,658

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

Total expenditures for 2018 were $20.1 billion, including $5.7 billion for the company’s share of equity-affiliate expenditures, which did not require cash outlays by the company. In 2017 and 2016, expenditures were $18.8 billion and $22.4 billion, respectively, including the company’s share of affiliates’ expenditures of $4.7 billion and $3.8 billion, respectively.

Of the $20.1 billion of expenditures in 2018, 88 percent, or $17.7 billion, related to upstream activities. Approximately 87 percent was expended for upstream operations in 2017 and 90 percent in 2016. International upstream accounted for 60 percent of the worldwide upstream investment in 2018, 69 percent in 2017 and 77 percent in 2016.

The company estimates that 2019 capital and exploratory expenditures will be $20 billion, including $6.3 billion of spending by affiliates. This is in line with 2018 expenditures, and reflects a robust portfolio of upstream and downstream investments, highlighted by the company's Permian Basin position, and additional shale and tight development in other basins. Approximately 87 percent of the total, or $17.3 billion, is budgeted for exploration and production activities. Approximately $10.4 billion of planned upstream capital spending relates to base producing assets, including $3.6 billion for the Permian and $1.6 billion for other shale and tight rock investments. Approximately $5.1 billion of the upstream program is planned for major capital projects underway, including $4.3 billion associated with the Future Growth and Wellhead Pressure Management Project at the Tengiz field in Kazakhstan. Global exploration funding is expected to be about $1.3 billion. Remaining upstream spend is budgeted for early stage projects supporting potential future developments. The company will continue to monitor crude oil market conditions and expects to further restrict capital outlays should oil price conditions deteriorate.

Worldwide downstream spending in 2019 is estimated to be $2.5 billion, with $1.5 billion estimated for projects in the United States.

Investments in technology businesses and other corporate operations in 2019 are budgeted at $0.2 billion.

Noncontrolling Interests The company had noncontrolling interests of $1.1 billion at December 31, 2018 and $1.2 billion at December 31, 2017. Distributions to noncontrolling interests totaled $91 million and $78 million in 2018 and 2017, respectively.

Pension Obligations Information related to pension plan contributions is included beginning on page 81 in Note 22, Employee Benefit Plans, under the heading “Cash Contributions and Benefit Payments.”

Financial Ratios



	At December 31
	2018		2017		2016
Current Ratio	1.3		1.0		0.9
Interest Coverage Ratio	23.4		10.7		(2.6	)
Debt Ratio	18.2	%	20.7	%	24.1		%

Current Ratio Current assets divided by current liabilities, which indicates the company’s ability to repay its short-term liabilities with short-term assets. The current ratio in all periods was adversely affected by the fact that Chevron’s inventories are valued on a last-in, first-out basis. At year-end 2018, the book value of inventory was lower than replacement costs, based on average acquisition costs during the year, by approximately $5.1 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 2018 was higher than 2017 and 2016 due to higher income.

Debt Ratio Total debt as a percentage of total debt plus Chevron Corporation Stockholders' Equity, which indicates the company’s leverage. The company's debt ratio was 18.2 percent at year-end 2018, compared with 20.7 percent and 24.1 percent at year-end 2017 and 2016, respectively.

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

Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements Information related to these matters is included on page 86 in Note 23, Other Contingencies and Commitments.

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

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



	Payments Due by Period
Millions of dollars	Total¹		2019		2020-2021		2022-2023		After 2023
On Balance Sheet:²
Short-Term Debt³	$	5,727	$	5,727	$	—	$	—	$	—
Long-Term Debt^{3, 4}	28,630		—		17,226		7,053		4,351
Noncancelable Capital Lease Obligations	233		30		39		32		132
Interest	4,736		801		1,278		936		1,721
Off Balance Sheet:
Noncancelable Operating Lease Obligations	2,159		540		870		408		341
Throughput and Take-or-Pay Agreements⁵	7,797		773		1,523		1,208		4,293
Other Unconditional Purchase Obligations⁵	2,526		565		963		569		429


¹	Excludes contributions for pensions and other postretirement benefit plans. Information on employee benefit plans is contained in Note 22 beginning on page 81.


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


³	$9.9 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 2020–2021 period. The amounts represent only the principal balance.


⁴	Excludes capital lease obligations.


⁵	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.

As part of the implementation of ASU 2016-02 (Leases) effective January 1, 2019, the company will reclassify some contracts, currently incorporated into the unconditional purchase obligations disclosure, as operating leases in first quarter 2019 results.

Direct Guarantees



	Commitment Expiration by Period
Millions of dollars	Total		2019		2020-2021		2022-2023		After 2023
Guarantee of nonconsolidated affiliate or joint-venture obligations	$	968	$	264	$	489	$	77	$	138

Additional information related to guarantees is included on page 86 in Note 23, Other Contingencies and Commitments.

Indemnifications Information related to indemnifications is included on page 86 in Note 23, Other Contingencies and Commitments.

Financial and Derivative Instrument Market Risk

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

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 2018.

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

Derivatives beyond those designated as normal purchase and normal sale contracts are recorded at fair value on the Consolidated Balance Sheet with resulting gains and losses reflected in income. Fair values are derived principally from published market quotes and other independent third-party quotes. The change in fair value of Chevron’s derivative commodity instruments in 2018 was not material to the company's results of operations.

The company uses the Monte Carlo simulation method as its Value-at-Risk (VaR) model to estimate the maximum potential loss in fair value, at the 95% confidence level with a one-day holding period, from the effect of adverse changes in market

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

conditions on derivative commodity instruments held or issued. Based on these inputs, the VaR for the company's primary risk exposures in the area of derivative commodity instruments at December 31, 2018 and 2017 was not material to the company's cash flows or results of operations.

Foreign Currency The company may enter into foreign currency derivative contracts to manage some of its foreign currency exposures. These exposures include revenue and anticipated purchase transactions, including foreign currency capital expenditures and lease commitments. The foreign currency derivative contracts, if any, are recorded at fair value on the balance sheet with resulting gains and losses reflected in income. There were no open foreign currency derivative contracts at December 31, 2018.

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 2018, the company had no interest rate swaps.

Transactions With Related Parties

Chevron enters into a number of business arrangements with related parties, principally its equity affiliates. These arrangements include long-term supply or offtake agreements and long-term purchase agreements. Refer to “Other Information” on page 70, in Note 14, Investments and Advances, 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 70 in Note 15 under the heading “MTBE.”

Ecuador Information related to Ecuador matters is included in Note 15 under the heading “Ecuador,” beginning on page 70.

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	2018			2017			2016
Balance at January 1	$	1,429		$	1,467		$	1,578
Net Additions	197			323			260
Expenditures	(299		)	(361		)	(371		)
Balance at December 31	$	1,327		$	1,429		$	1,467

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 $14.1 billion for asset retirement obligations at year-end 2018 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 2018 environmental expenditures. Refer to Note 23 on page 86 for additional discussion of environmental remediation provisions and year-end reserves. Refer also to Note 24 on page 88 for additional discussion of the company's asset retirement obligations.

Suspended Wells Information related to suspended wells is included in Note 20, Accounting for Suspended Exploratory Wells, beginning on page 79.

Income Taxes Information related to income tax contingencies is included on pages 74 through 76 in Note 16 and page 86 in Note 23 under the heading “Income Taxes.”

Other Contingencies Information related to other contingencies is included on page 87 in Note 23 to the Consolidated Financial Statements under the heading “Other Contingencies.”

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

Environmental Matters

The company is subject to various international, federal, state and local environmental, health and safety laws, regulations and market-based programs. These laws, regulations and programs continue to evolve and are expected to increase in both number and complexity over time and govern not only the manner in which the company conducts its operations, but also the products it sells. For example, international agreements and national, regional, and state legislation (e.g., California AB32, SB32 and AB398) and regulatory measures that aim to limit or reduce greenhouse gas (GHG) emissions are currently in various stages of implementation. Consideration of GHG issues and the responses to those issues through international agreements and national, regional or state legislation or regulations are integrated into the company’s strategy and planning, capital investment reviews and risk management tools and processes, where applicable. They are also factored into the company’s long-range supply, demand and energy price forecasts. These forecasts reflect long-range effects from renewable fuel penetration, energy efficiency standards, climate-related policy actions, and demand response to oil and natural gas prices. In addition, legislation and regulations intended to address hydraulic fracturing also continue to evolve at the national, state and local levels. Refer to “Risk Factors” in Part I, Item 1A, on pages 18 through 21 for a discussion of some of the inherent risks of increasingly restrictive environmental and other regulation that could materially impact the company’s results of operations or financial condition.

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

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

Using definitions and guidelines established by the American Petroleum Institute, Chevron estimated its worldwide environmental spending in 2018 at approximately $2.0 billion for its consolidated companies. Included in these expenditures were approximately $0.5 billion of environmental capital expenditures and $1.5 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 2019, total worldwide environmental capital expenditures are estimated at $0.5 billion. These capital costs are in addition to the ongoing costs of complying with environmental regulations and the costs to remediate previously contaminated sites.

Critical Accounting Estimates and Assumptions

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

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


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


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

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

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

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

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

Amortization - Capitalized exploratory drilling and development costs are depreciated on a unit-of-production (UOP) basis using proved developed reserves. Acquisition costs of proved properties are amortized on a UOP basis using total proved reserves. During 2018, Chevron's UOP Depreciation, Depletion and Amortization (DD&A) for oil and gas properties was $14.8 billion, and proved developed reserves at the beginning of 2018 were 6.1 billion barrels for consolidated companies. If the estimates of proved reserves used in the UOP calculations for consolidated operations had been lower by 5 percent across all oil and gas properties, UOP DD&A in 2018 would have increased by approximately $800 million.

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

Refer to Table V, “Reserve Quantity Information,” beginning on page 95, for the changes in proved reserve estimates for the three years ended December 31, 2018, and to Table VII, “Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves” on page 101 for estimates of proved reserve values for each of the three years ended December 31, 2018.

This Oil and Gas Reserves commentary should be read in conjunction with the Properties, Plant and Equipment section of Note 1, beginning on page 55, which includes a description of the “successful efforts” method of accounting for oil and gas exploration and production activities.

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

Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters, such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles, and the outlook for global or regional market supply-and-demand conditions for crude oil, natural gas, commodity chemicals and refined products. However, the impairment reviews and calculations are based on assumptions that are generally consistent with the company’s business plans and long-term investment decisions. Refer also to the discussion of impairments of properties, plant and equipment in Note 17 on page 77 and to the section on Properties, Plant and Equipment in Note 1, "Summary of Significant Accounting Policies," beginning on page 55.

The company routinely performs impairment reviews when triggering events arise to determine whether any write-down in the carrying value of an asset or asset group is required. For example, when significant downward revisions to crude oil and natural gas reserves are made for any single field or concession, an impairment review is performed to determine if the carrying value of the asset remains recoverable. Similarly, a significant downward revision in the company's crude oil or natural gas price outlook would trigger impairment reviews for impacted upstream assets. In addition, impairments could occur due to changes in national, state or local environmental regulations or laws, including those designed to stop or impede the development or production of oil and gas. 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. Assets that are not impaired on a held-and-used basis could possibly become impaired if a decision

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

is made to sell such assets. That is, the assets would be impaired if they are classified as held-for-sale and the estimated proceeds from the sale, less costs to sell, are less than the assets’ associated carrying values.

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

No individually material impairments of PP&E or Investments were recorded for 2018 or 2017. The company reported impairments for certain oil and gas properties in Brazil and the United States during 2016 due to reservoir performance and lower crude oil prices. A sensitivity analysis of the impact on earnings for these periods if other assumptions had been used in impairment reviews and impairment calculations is not practicable, given the broad range of the company’s PP&E and the number of assumptions involved in the estimates. That is, favorable changes to some assumptions might have avoided the need to impair any assets in these periods, whereas unfavorable changes might have caused an additional unknown number of other assets to become impaired, or resulted in larger impacts on impaired assets.

Asset Retirement Obligations In the determination of fair value for an asset retirement obligation (ARO), the company uses various assumptions and judgments, including such factors as the existence of a legal obligation, estimated amounts and timing of settlements, discount and inflation rates, and the expected impact of advances in technology and process improvements. A sensitivity analysis of the ARO impact on earnings for 2018 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 24 on page 88 for additional discussions on asset retirement obligations.

Pension and Other Postretirement Benefit Plans Note 22, beginning on page 81, 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 83 in Note 22 under the relevant headings. Actual rates may vary significantly from estimates because of unanticipated changes beyond the company's control.

For 2018, the company used an expected long-term rate of return of 6.75 percent and a discount rate for service costs of 3.7 percent and a discount rate for interest cost of 3.0 percent for U.S. pension plans. The actual return for 2018 was negative. For the 10 years ended December 31, 2018, actual asset returns averaged 7.9 percent for these plans. Additionally, with the exception of three years within this 10-year period, actual asset returns for these plans equaled or exceeded 6.75 percent during each year.

Total pension expense for 2018 was $1.1 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 63 percent of companywide pension expense, would have reduced total pension plan expense for 2018 by approximately $83 million. A 1 percent increase in the discount rates for this same plan would have reduced pension expense for 2018 by approximately $271 million.

The aggregate funded status recognized at December 31, 2018, was a net liability of approximately $3.9 billion. An increase in the discount rate would decrease the pension obligation, thus changing the funded status of a plan. At December 31, 2018, the company used a discount rate of 4.2 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 62 percent of the companywide pension obligation, would have reduced the plan obligation by approximately $339 million, and would have decreased the plan’s underfunded status from approximately $1.8 billion to $1.4 billion.

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

For the company’s OPEB plans, expense for 2018 was $123 million, and the total liability, all unfunded at the end of 2018, was $2.4 billion. For the main U.S. OPEB plan, the company used a discount rate for service cost of 3.8 percent and a discount rate for interest cost of 3.2 percent to measure expense in 2018, and a 4.3 percent discount rate to measure the benefit obligations at December 31, 2018. Discount rate changes, similar to those used in the pension sensitivity analysis, resulted in an immaterial impact on 2018 OPEB expense and OPEB liabilities at the end of 2018. For information on the sensitivity of the health care cost-trend rate, refer to page 83 in Note 22 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 82 in Note 22 for a description of the method used to amortize the $4.6 billion of before-tax actuarial losses recorded by the company as of December 31, 2018, and an estimate of the costs to be recognized in expense during 2019. In addition, information related to company contributions is included on page 85 in Note 22 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 23 beginning on page 86. 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, 2018.

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 4 beginning on page 60 for information regarding new accounting standards.

Quarterly Results

Unaudited



	2018									2017
Millions of dollars, except per-share amounts	4th Q			3rd Q		2nd Q		1st Q			4th Q			3rd Q		2nd Q		1st Q
Revenues and Other Income
Sales and other operating revenues¹	$	40,338		$	42,105	$	40,491	$	35,968		$	36,381		$	33,892	$	32,877	$	31,524
Income from equity affiliates	1,642			1,555		1,493		1,637			936			1,036		1,316		1,150
Other income	372			327		252		159			299			1,277		287		747
Total Revenues and Other Income	42,352			43,987		42,236		37,764			37,616			36,205		34,480		33,421
Costs and Other Deductions
Purchased crude oil and products	23,920			24,681		24,744		21,233			21,158			18,776		18,325		17,506
Operating expenses ²	5,645			4,985		5,213		4,701			5,106			4,845		4,590		4,586
Selling, general and administrative expenses ²	1,080			1,018		1,017		723			1,262			1,111		927		810
Exploration expenses	250			625		177		158			356			239		125		144
Depreciation, depletion and amortization	5,252			5,380		4,498		4,289			4,735			5,109		5,311		4,194
Taxes other than on income¹	901			1,259		1,363		1,344			3,182			3,213		3,065		2,871
Interest and debt expense	190			182		217		159			173			35		48		51
Other components of net periodic benefit costs²	216			158		102		84			163			219		136		130
Total Costs and Other Deductions	37,454			38,288		37,331		32,691			36,135			33,547		32,527		30,292
Income (Loss) Before Income Tax Expense	4,898			5,699		4,905		5,073			1,481			2,658		1,953		3,129
Income Tax Expense (Benefit)	1,175			1,643		1,483		1,414			(1,637		)	672		487		430
Net Income (Loss)	$	3,723		$	4,056	$	3,422	$	3,659		$	3,118		$	1,986	$	1,466	$	2,699
Less: Net income attributable to noncontrolling interests	(7		)	9		13		21			7			34		16		17
Net Income (Loss) Attributable to Chevron Corporation	$	3,730		$	4,047	$	3,409	$	3,638		$	3,111		$	1,952	$	1,450	$	2,682
Per Share of Common Stock
Net Income (Loss) Attributable to Chevron Corporation
– Basic	$	1.97		$	2.13	$	1.79	$	1.92		$	1.65		$	1.03	$	0.77	$	1.43
– Diluted	$	1.95		$	2.11	$	1.78	$	1.90		$	1.64		$	1.03	$	0.77	$	1.41
Dividends	$	1.12		$	1.12	$	1.12	$	1.12		$	1.08		$	1.08	$	1.08	$	1.08
¹ Includes excise, value-added and similar taxes:	$	—		$	—	$	—	$	—		$	1,874		$	1,867	$	1,771	$	1,677
Beginning in 2018, excises taxes are netted in "Taxes other than on income" in accordance with ASU 2014-09. Refer to Note 25, "Revenue" beginning on page 88.
² 2017 adjusted to conform to ASU 2017-07. Refer to Note 4, "New Accounting Standards" beginning on page 60.




Management’s Responsibility for Financial Statements

To the Stockholders of Chevron Corporation Management of Chevron Corporation is responsible for preparing the accompanying consolidated financial statements and the related information appearing in this report. The statements were prepared in accordance with accounting principles generally accepted in the United States of America and fairly represent the transactions and financial position of the company. The financial statements include amounts that are based on management’s best estimates and judgments. As stated in its report included herein, the independent registered public accounting firm of PricewaterhouseCoopers LLP has audited the company’s consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). The Board of Directors of Chevron has an Audit Committee composed of directors who are not officers or employees of the company. The Audit Committee meets regularly with members of management, the internal auditors and the independent registered public accounting firm to review accounting, internal control, auditing and financial reporting matters. Both the internal auditors and the independent registered public accounting firm have free and direct access to the Audit Committee without the presence of management. The company's management has evaluated, with the participation of the Chief Executive Officer and Chief Financial Officer, the effectiveness of the company's disclosure controls and procedures (as defined in the Exchange Act Rules 13a-15(e) and 15d-15(e)) as of December 31, 2018. Based on that evaluation, management concluded that the company's disclosure controls are effective in ensuring that information required to be recorded, processed, summarized and reported, are done within the time periods specified in the U.S. Securities and Exchange Commission's rules and forms.

Management’s Report on Internal Control Over Financial Reporting
The company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in the Exchange Act Rules 13a-15(f) and 15d-15(f). The company’s management, including the Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of the company’s internal control over financial reporting based on the Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on the results of this evaluation, the company’s management concluded that internal control over financial reporting was effective as of December 31, 2018. The effectiveness of the company’s internal control over financial reporting as of December 31, 2018, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report included herein.




Michael K. Wirth	Patricia E. Yarrington	Jeanette L. Ourada
Chairman of the Board	Vice President	Vice President
and Chief Executive Officer	and Chief Financial Officer	and Comptroller

February 22, 2019




	Report of Independent Registered Public Accounting Firm
	To the Board of Directors and Shareholders of Chevron Corporation:
	Opinions on the Financial Statements and Internal Control over Financial Reporting We have audited the accompanying consolidated balance sheets of Chevron Corporation and its subsidiaries (the "Company") as of December 31, 2018 and 2017, and the related consolidated statements of income, comprehensive income, cash flows and equity for each of the three years in the period ended December 31, 2018, including the related notes and financial statement schedule listed in the index appearing under Item 15(a)(2) (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
	Basis for Opinions The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. 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.
	Definition and Limitations of Internal Control over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

	San Francisco, California
	February 22, 2019
	We have served as the Company’s auditor since 1935.

Consolidated Statement of Income

Millions of dollars, except per-share amounts




	Year ended December 31
	2018		2017			2016
Revenues and Other Income
Sales and other operating revenues¹	$	158,902	$	134,674		$	110,215
Income from equity affiliates	6,327		4,438			2,661
Other income	1,110		2,610			1,596
Total Revenues and Other Income	166,339		141,722			114,472
Costs and Other Deductions
Purchased crude oil and products	94,578		75,765			59,321
Operating expenses²	20,544		19,127			19,902
Selling, general and administrative expenses²	3,838		4,110			4,305
Exploration expenses	1,210		864			1,033
Depreciation, depletion and amortization	19,419		19,349			19,457
Taxes other than on income¹	4,867		12,331			11,668
Interest and debt expense	748		307			201
Other components of net periodic benefit costs²	560		648			745
Total Costs and Other Deductions	145,764		132,501			116,632
Income (Loss) Before Income Tax Expense	20,575		9,221			(2,160		)
Income Tax Expense (Benefit)	5,715		(48		)	(1,729		)
Net Income (Loss)	14,860		9,269			(431		)
Less: Net income attributable to noncontrolling interests	36		74			66
Net Income (Loss) Attributable to Chevron Corporation	$	14,824	$	9,195		$	(497	)
Per Share of Common Stock
Net Income (Loss) Attributable to Chevron Corporation
- Basic	$	7.81	$	4.88		$	(0.27	)
- Diluted	$	7.74	$	4.85		$	(0.27	)
¹2017 and 2016 include excise, value-added and similar taxes of $7,189 and $6,905, respectively, collected on behalf of third parties. Beginning in 2018, these taxes are netted in "Taxes other than on income" in accordance with Accounting Standards Update (ASU) 2014-09. Refer to Note 25, "Revenue" beginning on page 88.
² 2017 and 2016 adjusted to conform to ASU 2017-07. Refer to Note 4, "New Accounting Standards" beginning on page 60.
See accompanying Notes to the Consolidated Financial Statements.

Consolidated Statement of Comprehensive Income

Millions of dollars



	Year ended December 31
	2018			2017			2016
Net Income (Loss)	$	14,860		$	9,269		$	(431	)
Currency translation adjustment
Unrealized net change arising during period	(19		)	57			(22		)
Unrealized holding gain (loss) on securities
Net gain (loss) arising during period	(5		)	(3		)	27
Defined benefit plans
Actuarial gain (loss)
Amortization to net income of net actuarial loss and settlements	792			817			918
Actuarial gain (loss) arising during period	85			(571		)	(315		)
Prior service credits (cost)
Amortization to net income of net prior service costs and curtailments	(13		)	(20		)	19
Prior service (costs) credits arising during period	(26		)	(1		)	345
Defined benefit plans sponsored by equity affiliates - benefit (cost)	23			19			(19		)
Income (taxes) benefit on defined benefit plans	(230		)	(44		)	(505		)
Total	631			200			443
Other Comprehensive Gain, Net of Tax	607			254			448
Comprehensive Income	15,467			9,523			17
Comprehensive income attributable to noncontrolling interests	(36		)	(74		)	(66		)
Comprehensive Income (Loss) Attributable to Chevron Corporation	$	15,431		$	9,449		$	(49	)
See accompanying Notes to the Consolidated Financial Statements.

Consolidated Balance Sheet

Millions of dollars, except per-share amounts



	At December 31
	2018			2017
Assets
Cash and cash equivalents	$	9,342		$	4,813
Time deposits	950			—
Marketable securities	53			9
Accounts and notes receivable (less allowance: 2018 - $869; 2017 - $490)	15,050			15,353
Inventories:
Crude oil and petroleum products	3,383			3,142
Chemicals	487			476
Materials, supplies and other	1,834			1,967
Total inventories	5,704			5,585
Prepaid expenses and other current assets	2,922			2,800
Total Current Assets	34,021			28,560
Long-term receivables, net	1,942			2,849
Investments and advances	35,546			32,497
Properties, plant and equipment, at cost	340,244			344,485
Less: Accumulated depreciation, depletion and amortization	171,037			166,773
Properties, plant and equipment, net	169,207			177,712
Deferred charges and other assets	6,766			7,017
Goodwill	4,518			4,531
Assets held for sale	1,863			640
Total Assets	$	253,863		$	253,806
Liabilities and Equity
Short-term debt	$	5,726		$	5,192
Accounts payable	13,953			14,565
Accrued liabilities	4,927			5,267
Federal and other taxes on income	1,628			1,600
Other taxes payable	937			1,113
Total Current Liabilities	27,171			27,737
Long-term debt¹	28,733			33,571
Deferred credits and other noncurrent obligations	19,742			21,106
Noncurrent deferred income taxes	15,921			14,652
Noncurrent employee benefit plans	6,654			7,421
Total Liabilities²	$	98,221		$	104,487
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, 2018 and 2017)	1,832			1,832
Capital in excess of par value	17,112			16,848
Retained earnings	180,987			174,106
Accumulated other comprehensive losses	(3,544		)	(3,589		)
Deferred compensation and benefit plan trust	(240		)	(240		)
Treasury stock, at cost (2018 - 539,838,890 shares; 2017 - 537,974,695)	(41,593		)	(40,833		)
Total Chevron Corporation Stockholders' Equity	154,554			148,124
Noncontrolling interests	1,088			1,195
Total Equity	155,642			149,319
Total Liabilities and Equity	$	253,863		$	253,806
¹Includes capital lease obligations of $127 and $94 at December 31, 2018 and 2017, respectively.
²Refer to Note 23, "Other Contingencies and Commitments" beginning on page 86.
See accompanying Notes to the Consolidated Financial Statements.

Consolidated Statement of Cash Flows

Millions of dollars



	Year ended December 31
	2018			2017			2016
Operating Activities
Net Income (Loss)	$	14,860		$	9,269		$	(431	)
Adjustments
Depreciation, depletion and amortization	19,419			19,349			19,457
Dry hole expense	687			198			489
Distributions less than income from equity affiliates¹	(3,580		)	(2,380		)	(1,549		)
Net before-tax gains on asset retirements and sales	(619		)	(2,195		)	(1,149		)
Net foreign currency effects	123			131			186
Deferred income tax provision	1,050			(3,203		)	(3,835		)
Net decrease (increase) in operating working capital²	(718		)	520			(327		)
Decrease (increase) in long-term receivables	418			(368		)	(131		)
Net decrease (increase) in other deferred charges²	—			(254		)	178
Cash contributions to employee pension plans	(1,035		)	(980		)	(870		)
Other	13			251			672
Net Cash Provided by Operating Activities^1,2	30,618			20,338			12,690
Investing Activities
Capital expenditures	(13,792		)	(13,404		)	(18,109		)
Proceeds and deposits related to asset sales and returns of investment^1,2	2,392			5,096			3,476
Net maturities of (investments in) time deposits	(950		)	—			—
Net sales (purchases) of marketable securities	(51		)	4			297
Net repayment (borrowing) of loans by equity affiliates	111			(16		)	(2,034		)
Net Cash Used for Investing Activities^1,2	(12,290		)	(8,320		)	(16,370		)
Financing Activities
Net borrowings (repayments) of short-term obligations	2,021			(5,142		)	2,130
Proceeds from issuances of long-term debt	218			3,991			6,924
Repayments of long-term debt and other financing obligations	(6,741		)	(6,310		)	(1,584		)
Cash dividends - common stock	(8,502		)	(8,132		)	(8,032		)
Distributions to noncontrolling interests	(91		)	(78		)	(63		)
Net sales (purchases) of treasury shares	(604		)	1,117			650
Net Cash Provided by (Used for) Financing Activities	(13,699		)	(14,554		)	25
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Cash	(91		)	65			(53		)
Net Change in Cash, Cash Equivalents and Restricted Cash	4,538			(2,471		)	(3,708		)
Cash, Cash Equivalents and Restricted Cash at January 1	5,943			8,414			12,122
Cash, Cash Equivalents and Restricted Cash at December 31	$	10,481		$	5,943		$	8,414
¹ 2017 and 2016 adjusted to conform to ASU 2016-15. Refer to Note 3, "Information Relating to the Consolidated Statement of Cash Flows" beginning on page 59.
² 2017 and 2016 adjusted to conform to ASU 2016-18. Refer to Note 3, "Information Relating to the Consolidated Statement of Cash Flows" beginning on page 59.
See accompanying Notes to the Consolidated Financial Statements.

Consolidated Statement of Equity

Shares in thousands; amounts in millions of dollars



						Acc. Other			Treasury			Chevron Corp.
	Common		Retained			Comprehensive			Stock			Stockholders'			Noncontrolling			Total
	Stock¹		Earnings			Income (Loss)			(at cost)			Equity			Interests			Equity
Balance at December 31, 2015	$	17,922	$	181,578		$	(4,291	)	$	(42,493	)	$	152,716		$	1,170		$	153,886
Treasury stock transactions	265		—			—			—			265			—			265
Net income (loss)	—		(497		)	—			—			(497		)	66			(431		)
Cash dividends	—		(8,032		)	—			—			(8,032		)	(63		)	(8,095		)
Stock dividends	—		(3		)	—			—			(3		)	—			(3		)
Other comprehensive income	—		—			448			—			448			—			448
Purchases of treasury shares	—		—			—			(2		)	(2		)	—			(2		)
Issuances of treasury shares	—		—			—			661			661			—			661
Other changes, net	—		—			—			—			—			(7		)	(7		)
Balance at December 31, 2016	$	18,187	$	173,046		$	(3,843	)	$	(41,834	)	$	145,556		$	1,166		$	146,722
Treasury stock transactions	253		—			—			—			253			—			253
Net income (loss)	—		9,195			—			—			9,195			74			9,269
Cash dividends	—		(8,132		)	—			—			(8,132		)	(78		)	(8,210		)
Stock dividends	—		(3		)	—			—			(3		)	—			(3		)
Other comprehensive income	—		—			254			—			254			—			254
Purchases of treasury shares	—		—			—			(1		)	(1		)	—			(1		)
Issuances of treasury shares	—		—			—			1,002			1,002			—			1,002
Other changes, net	—		—			—			—			—			33			33
Balance at December 31, 2017	$	18,440	$	174,106		$	(3,589	)	$	(40,833	)	$	148,124		$	1,195		$	149,319
Treasury stock transactions	264		—			—			—			264			—			264
Net income (loss)	—		14,824			—			—			14,824			36			14,860
Cash dividends	—		(8,502		)	—			—			(8,502		)	(91		)	(8,593		)
Stock dividends	—		(3		)	—			—			(3		)	—			(3		)
Other comprehensive income	—		—			607			—			607			—			607
Purchases of treasury shares	—		—			—			(1,751		)	(1,751		)	—			(1,751		)
Issuances of treasury shares	—		—			—			991			991			—			991
Other changes, net²	—		562			(562		)	—			—			(52		)	(52		)
Balance at December 31, 2018	$	18,704	$	180,987		$	(3,544	)	$	(41,593	)	$	154,554		$	1,088		$	155,642

						Common Stock Share Activity
	Issued³					Treasury						Outstanding
Balance at December 31, 2015			2,442,677						(559,863		)				1,882,814
Purchases			—						(20		)				(20		)
Issuances			—						8,713						8,713
Balance at December 31, 2016			2,442,677						(551,170		)				1,891,507
Purchases			—						(10		)				(10		)
Issuances			—						13,205						13,205
Balance at December 31, 2017			2,442,677						(537,975		)				1,904,702
Purchases			—						(14,912		)				(14,912		)
Issuances			—						13,048						13,048
Balance at December 31, 2018			2,442,677						(539,839		)				1,902,838
¹ Beginning and ending balances for all periods include capital in excess of par, common stock issued at par for $1,832, and $(240) associated with Chevron's Benefit Plan Trust. Changes reflect capital in excess of par.
² In 2018, Chevron reclassified stranded tax effects in "Accumulated other comprehensive loss" to "Retained earnings" in conjunction with the adoption of ASU 2018-02. Refer to Note 2, "Changes in Accumulated Other Comprehensive Losses" on page 58 and Note 4, "New Accounting Standards" on page 60.
³ Beginning and ending total issued share balances include 14,168 shares associated with Chevron's Benefit Plan Trust.
See accompanying Notes to the Consolidated Financial Statements.

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Note 1

Summary of Significant Accounting Policies

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

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.

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

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

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 and Consolidated Statement of Equity.

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

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

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

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

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 are primarily stated at cost or net realizable value.

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 20, beginning on page 79, 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 cash flows. Events that can trigger assessments for possible impairments include write-downs of proved reserves based on field performance, significant decreases in the market value of an asset (including changes to the commodity price forecast), significant change in the extent or manner of use of or a physical change in an asset, and a more-likely-than-not expectation that a long-lived asset or asset group will be sold or otherwise disposed of significantly sooner than the end of its previously estimated useful life. Impaired assets are written down to their estimated fair values, generally their discounted, future net cash flows. For proved crude oil and natural gas properties, the company performs impairment reviews on a country, concession, PSC, development area or field basis, as appropriate. In Downstream, impairment reviews are performed on the basis of a refinery, a plant, a marketing/lubricants area or distribution area, as appropriate. Impairment amounts are recorded as incremental “Depreciation, depletion and amortization” expense.

Long-lived assets that are held for sale are evaluated for possible impairment by comparing the carrying value of the asset with its fair value less the cost to sell. If the net book value exceeds the fair value less cost to sell, the asset is considered impaired and adjusted to the lower value. Refer to Note 8, beginning on page 63, relating to fair value measurements. The fair value of a liability for an ARO is recorded as an asset and a liability when there is a legal obligation associated with the retirement of a long-lived asset and the amount can be reasonably estimated. Refer also to Note 24, on page 88, 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. Impairments of capitalized costs of unproved mineral interests are expensed.

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

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

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

Goodwill Goodwill resulting from a business combination is not subject to amortization. The company tests such goodwill at the reporting unit level for impairment annually at December 31, or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting unit below its carrying amount.

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

Liabilities related to future remediation costs are recorded when environmental assessments or cleanups or both are probable and the costs can be reasonably estimated. For crude oil, natural gas and mineral-producing properties, a liability for an ARO

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

is made in accordance with accounting standards for asset retirement and environmental obligations. Refer to Note 24, on page 88, for a discussion of the company’s AROs.

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

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

Revenue Recognition The company accounts for each delivery order of crude oil, natural gas, petroleum and chemical products as a separate performance obligation. Revenue is recognized when the performance obligation is satisfied, which typically occurs at the point in time when control of the product transfers to the customer. Payment is generally due within 30 days of delivery. The company accounts for delivery transportation as a fulfillment cost, not a separate performance obligation, and recognizes these costs as an operating expense in the period when revenue for the related commodity is recognized.

Revenue is measured as the amount the company expects to receive in exchange for transferring commodities to the customer. The company’s commodity sales are typically based on prevailing market-based prices and may include discounts and allowances. Until market prices become known under terms of the company’s contracts, the transaction price included in revenue is based on the company’s estimate of the most likely outcome.

Discounts and allowances are estimated using a combination of historical and recent data trends. When deliveries contain multiple products, an observable standalone selling price is generally used to measure revenue for each product. The company includes estimates in the transaction price only to the extent that a significant reversal of revenue is not probable in subsequent periods.

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 net basis in "Taxes other than on income" on the Consolidated Statement of Income, on page 50. 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.

Prior to the adoption of ASC 606 on January 1, 2018, revenues associated with sales of crude oil, natural gas, petroleum and chemicals products, and all other sources were recorded when title passed 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 were 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 were presented on a gross basis on the Consolidated Statement of Income.

Stock Options and Other Share-Based Compensation The company issues stock options and other share-based compensation to certain employees. For equity awards, such as stock options, total compensation cost is based on the grant date fair value, and for liability awards, such as stock appreciation rights, total compensation cost is based on the settlement value. The company recognizes stock-based compensation expense for all awards over the service period required to earn the award, which is the shorter of the vesting period or the time period in which an employee becomes eligible to retain the award at retirement. The company’s Long-Term Incentive Plan (LTIP) awards include stock options and stock appreciation rights, which have graded vesting provisions by which one-third of each award vests on each of the first, second and third anniversaries of the date of grant. In addition, performance shares granted under the company's LTIP will vest at the end of the three-year performance period. For awards granted under the company's LTIP beginning in 2017, stock options and stock appreciation rights have graded vesting by which one third of each award vests annually on each January 31 on or after the first anniversary of the grant date. Standard restricted stock unit awards have cliff vesting by which the total award will vest on January 31 on or after the fifth anniversary of the grant date, subject to adjustment upon termination pursuant to the satisfaction of certain criteria. The company amortizes these awards on a straight-line basis.

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

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 ended December 31, 2018, are reflected in the table below.



	Currency Translation Adjustments			Unrealized Holding Gains (Losses) on Securities			Derivatives			Defined Benefit Plans			Total
Balance at December 31, 2015	$	(140	)	$	(29	)	$	(2	)	$	(4,120	)	$	(4,291	)
Components of Other Comprehensive Income (Loss)¹:
Before Reclassifications	(22		)	27			—			(161		)	(156		)
Reclassifications²	—			—			—			604			604
Net Other Comprehensive Income (Loss)	(22		)	27			—			443			448
Balance at December 31, 2016	$	(162	)	$	(2	)	$	(2	)	$	(3,677	)	$	(3,843	)
Components of Other Comprehensive Income (Loss)¹:
Before Reclassifications	57			(3		)	—			(310		)	(256		)
Reclassifications²	—			—			—			510			510
Net Other Comprehensive Income (Loss)	57			(3		)	—			200			254
Balance at December 31, 2017	$	(105	)	$	(5	)	$	(2	)	$	(3,477	)	$	(3,589	)
Components of Other Comprehensive Income (Loss)¹:
Before Reclassifications	(19		)	(5		)	—			28			4
Reclassifications²	—			—			—			603			603
Net Other Comprehensive Income (Loss)	(19		)	(5		)	—			631			607
Stranded Tax Reclassification to Retained Earnings³	—			—			—			(562		)	(562		)
Balance at December 31, 2018	$	(124	)	$	(10	)	$	(2	)	$	(3,408	)	$	(3,544	)


¹	All amounts are net of tax.


²	Refer to Note 22 beginning on page 81, for reclassified components totaling $779 that are included in employee benefit costs for the year ended December 31, 2018. Related income taxes for the same period, totaling $176, are reflected in Income Tax Expense on the Consolidated Statement of Income. All other reclassified amounts were insignificant.


³	Stranded tax reclassification to retained earnings per ASU 2018-02. Refer to Note 4, "New Accounting Standards" on page 60.

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Note 3

Information Relating to the Consolidated Statement of Cash Flows



	Year ended December 31
	2018			2017			2016
Net decrease (increase) in operating working capital was composed of the following:
Decrease (increase) in accounts and notes receivable	$	437		$	(915	)	$	(2,121	)
Decrease (increase) in inventories	(424		)	(267		)	603
Decrease (increase) in prepaid expenses and other current assets ¹	(149		)	173			829
Increase (decrease) in accounts payable and accrued liabilities ¹	(494		)	998			366
Increase (decrease) in income and other taxes payable	(88		)	531			(4		)
Net decrease (increase) in operating working capital	$	(718	)	$	520		$	(327	)
Net cash provided by operating activities includes the following cash payments:
Interest on debt (net of capitalized interest)	$	736		$	265		$	158
Income taxes	4,748			3,132			1,935
Proceeds and deposits related to asset sales and returns of investment consisted of the following gross amounts:
Proceeds and deposits related to asset sales ¹	$	2,000		$	4,930		$	3,154
Returns of investment from equity affiliates ²	392			166			322
Proceeds and deposits related to asset sales and returns of investment	$	2,392		$	5,096		$	3,476
Net maturities (investments) of time deposits consisted of the following gross amounts:
Investments in time deposits	$	(950	)	$	—		$	—
Maturities of time deposits	—			—			—
Net maturities of (investments in) time deposits	$	(950	)	$	—		$	—
Net sales (purchases) of marketable securities consisted of the following gross amounts:
Marketable securities purchased	$	(51	)	$	(3	)	$	(9	)
Marketable securities sold	—			7			306
Net sales (purchases) of marketable securities	$	(51	)	$	4		$	297
Net repayment (borrowing) of loans by equity affiliates:
Borrowing of loans by equity affiliates	$	—		$	(142	)	$	(2,341	)
Repayment of loans by equity affiliates	111			126			307
Net repayment (borrowing) of loans by equity affiliates	$	111		$	(16	)	$	(2,034	)
Net borrowings (repayments) of short-term obligations consisted of the following gross and net amounts:
Proceeds from issuances of short-term obligations	$	2,486		$	5,051		$	14,778
Repayments of short-term obligations	(4,136		)	(8,820		)	(12,558		)
Net borrowings (repayments) of short-term obligations with three months or less maturity	3,671			(1,373		)	(90		)
Net borrowings (repayments) of short-term obligations	$	2,021		$	(5,142	)	$	2,130
¹ 2017 and 2016 adjusted to conform to ASU 2016-18.
² Per ASU 2016-15.

A loan to Tengizchevroil LLP for the development of the Future Growth and Wellhead Pressure Management Project represents the majority of "Net borrowing of loans by equity affiliates" in 2016.

The “Net sales (purchases) of treasury shares” represents the cost of common shares acquired less the cost of shares issued for share-based compensation plans. Purchases totaled $1,751, $1 and $2 in 2018, 2017 and 2016, respectively. The company purchased 14.9 million shares under its stock repurchase plan for $1,750 in 2018. No shares were repurchased under the plan in 2017 or 2016.

The Consolidated Statement of Cash Flows excludes changes to the Consolidated Balance Sheet that did not affect cash. "Depreciation, depletion and amortization," "Dry hole expense" and "Deferred income tax provision" collectively include approximately $1.1 billion in non-cash reductions to properties, plant and equipment recorded in 2018 relating to impairments and other non-cash charges.

Refer also to Note 24, on page 88, 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, 2018.

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

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
	2018			2017		2016
Additions to properties, plant and equipment ^*	$	13,384		$	13,222	$	17,742
Additions to investments	65			25		55
Current-year dry hole expenditures	344			157		313
Payments for other liabilities and assets, net	(1		)	—		(1		)
Capital expenditures	13,792			13,404		18,109
Expensed exploration expenditures	523			666		544
Assets acquired through capital lease obligations and other financing obligations	75			8		5
Capital and exploratory expenditures, excluding equity affiliates	14,390			14,078		18,658
Company's share of expenditures by equity affiliates	5,716			4,743		3,770
Capital and exploratory expenditures, including equity affiliates	$	20,106		$	18,821	$	22,428


^*	Excludes non-cash additions of $25 in 2018, $1,183 in 2017 and $56 in 2016.

On January 1, 2018, Chevron adopted Accounting Standards Updates (ASU) 2016-15 and 2016-18, which require retrospective adjustment of prior periods in the Statement of Cash Flows.

In addition to other requirements, ASU 2016-15 specifies new standards for the classification of distributions from equity affiliates. In adopting these new standards, Chevron utilized the cumulative earnings approach to evaluate returns on and returns of investment from equity affiliates. For the year ended 2017 and 2016, a total of $166 and $322, respectively, was reclassified from “Distributions less than income from equity affiliates” to “Proceeds and deposits related to asset sales and returns of investment.”

Adoption of ASU 2016-18 requires the inclusion of restricted cash and associated changes in restricted cash in the Consolidated Statement of Cash Flows. The impact of ASU 2016-18 is captured across several line items in the Statement of Cash Flows, including “Net decrease (increase) in operating working capital,” “Decrease (increase) in other deferred charges,” and “Proceeds and deposits related to asset sales and returns of investment” with associated net changes captured in both “Net Cash Provided by Operating Activities” and “Net Cash Used for Investing Activities.” The line item “Net sales (purchases) of other short-term investments” was removed in conjunction with the adoption of ASU 2016-18.

The table below quantifies the beginning and ending balances of restricted cash and restricted cash equivalents in the Consolidated Balance Sheet:



	Year ended December 31
	2018		2017		2016		2015
Cash and cash equivalents	$	9,342	$	4,813	$	6,988	$	11,022
Restricted cash included in "Prepaid expenses and other current assets"	341		405		488		196
Restricted cash included in "Deferred charges and other assets"	798		725		938		904
Total cash, cash equivalents and restricted cash	$	10,481	$	5,943	$	8,414	$	12,122

Note 4

New Accounting Standards

Revenue Recognition (Topic 606): Revenue from Contracts with Customers On January 1, 2018, Chevron adopted ASU 2014-09 and its related amendments using the modified retrospective transition method, which did not require the restatement of prior periods. The impact of the adoption of the standard did not have a material effect on the company’s consolidated financial statements. For additional information on the company’s revenue, refer to Note 25 beginning on page 88.

Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20) On January 1, 2018, the company adopted ASU 2017-05, which provides clarification regarding the guidance on accounting for the derecognition of nonfinancial assets. The adoption of the standard had no impact on the company’s consolidated financial statements.

Compensation - Retirement Benefits (Topic 715) Effective January 1, 2018, Chevron adopted ASU 2017-07 on a retrospective basis. The standard requires the disaggregation of the service cost component from the other components of net periodic benefit cost and allows only the service cost component of net benefit cost to be eligible for capitalization. The effects of retrospective adoption on the Consolidated Statement of Income for 2017 and 2016 were to move $310 and $366 from "Operating expenses" and $338 and $379 from "Selling, general and administrative expenses" to "Other components of net periodic benefits cost," respectively.

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Statement of Cash Flows (Topic 230) Classification of Certain Cash Receipts and Cash Payments Effective January 1, 2018, Chevron adopted ASU 2016-15 on a retrospective basis. The standard provides clarification on how certain cash receipts and cash payments are presented and classified on the Consolidated Statement of Cash Flows. The adoption of this ASU did not have a material impact on the company's Consolidated Statement of Cash Flows. For additional information, refer to Note 3 beginning on page 59.

Statement of Cash Flows (Topic 230) Restricted Cash Effective January 1, 2018, Chevron adopted ASU 2016-18 on a retrospective basis. The standard requires an entity to explain the changes in the total of cash, cash equivalents, restricted cash and restricted cash equivalents on the Consolidated Statement of Cash Flows and to provide a reconciliation to the Consolidated Balance Sheet when the cash, cash equivalents, restricted cash and restricted cash equivalents are not separately presented or are presented in more than one line item on the Consolidated Balance Sheet. The company’s restricted cash balances are now included in the beginning and ending balances on the Consolidated Statement of Cash Flows. For additional information, refer to Note 3 beginning on page 59.

Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income In fourth quarter 2018, the company elected to early adopt ASU 2018-02, which permits the reclassification of stranded tax effects in accumulated other comprehensive income as a result of U.S. tax reform. Accordingly, Chevron reclassified $562 from "Accumulated other comprehensive losses" to "Retained earnings" associated with the reduction of the U.S. statutory tax rate from 35 percent to 21 percent. In accordance with its accounting policy, the company releases stranded income tax effects from accumulated other comprehensive income in the period the underlying activity ceases to exist. ASU 2018-02 allowed for the reclassification of stranded tax effects as a result of the change in tax rates due to U.S. tax reform to be recorded upon adoption of the ASU, rather than at the actual date that the underlying activity ceases to exist. For additional detail, refer to Note 2 beginning on page 58.

Leases (Topic 842) In February 2016, the Financial Accounting Standards Board (FASB) issued ASU 2016-02, which became effective for the company January 1, 2019. The standard requires that lessees present right-of-use assets and lease liabilities on the Consolidated Balance Sheet. The company plans to elect the short-term lease exception provided for in the standard and therefore will only recognize right-of-use assets and lease liabilities for leases with a term greater than one year. The company further intends to elect the option to apply the transition provisions of the new standard at the adoption date instead of the earliest comparative period presented in the financial statements. The company plans to elect the package of practical expedients to not re-evaluate existing lease contracts or lease classifications and therefore will not make changes to those leases already recognized on the Consolidated Balance Sheet under ASC 840 until the leases are fully amortized, amended, or modified. In addition, the company will not reassess initial direct costs for any existing leases. The company intends to apply the land easement practical expedient. Chevron plans to elect the practical expedient to not separate non-lease components from lease components for most asset classes except for certain asset classes that have significant non-lease (i.e., service) components in addition to the lease component. The company will reclassify some contracts, currently not classified as leases, as operating leases under the new standard.

The company completed accounting policy and disclosure updates and system implementation necessary to meet the standard's requirements. The company does not expect the adoption of the ASU to have a material impact on finance leases, which are currently referred to as capital leases. The company estimates that the operating lease right-of-use assets and lease liabilities on the Consolidated Balance Sheet are approximately $4 billion, as of January 1, 2019. The company expects the implementation of the standard will have a minimal impact on the Consolidated Statement of Income and Consolidated Statement of Cash Flows.

Financial Instruments - Credit Losses (Topic 326) In June 2016, the FASB issued ASU 2016-13, which becomes effective for the company beginning January 1, 2020. The standard requires companies to use forward-looking information to calculate credit loss estimates. The company is evaluating the effect of the standard on the company’s consolidated financial statements.

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Note 5

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, vessels, 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 below:



	At December 31
	2018		2017
Upstream	$	719	$	678
Downstream	99		99
All Other	—		—
Total	818		777
Less: Accumulated amortization	617		515
Net capitalized leased assets	$	201	$	262

Rental expenses incurred for operating leases during 2018, 2017 and 2016 were as follows:



	Year ended December 31
	2018		2017		2016
Minimum rentals	$	820	$	726	$	943
Contingent rentals	1		1		2
Total	821		727		945
Less: Sublease rental income	5		6		7
Net rental expense	$	816	$	721	$	938

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, 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, 2018, the estimated future minimum lease payments (net of noncancelable sublease rentals) under operating and capital leases, which at inception had a noncancelable term of more than one year, were as follows:



		At December 31
		Operating Leases		Capital Leases *
Year	2019	$	540	$	30
	2020	492		22
	2021	378		17
	2022	242		16
	2023	166		16
	Thereafter	341		132
Total		$	2,159	$	233
Less: Amounts representing interest and executory costs				$	(88	)
Net present values				145
Less: Capital lease obligations included in short-term debt				(18		)
Long-term capital lease obligations				$	127
* Excluded from the table is an executed but not-yet-commenced capital lease with payments of $14, $15, $22, $21, $21, and $219 for 2019, 2020, 2021, 2022, 2023, and thereafter, respectively.

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Note 6

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

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



	Year ended December 31
	2018		2017		2016
Sales and other operating revenues	$	125,076	$	104,054	$	83,715
Total costs and other deductions	121,351		103,904		87,429
Net income (loss) attributable to CUSA	4,334		4,842		(1,177		)



	At December 31
	2018		2017
Current assets	$	12,819	$	12,163
Other assets	55,814		54,994
Current liabilities	16,376		17,379
Other liabilities	12,906		12,541
Total CUSA net equity	$	39,351	$	37,237

Memo: Total debt	$	3,049	$	3,056

Note 7

Summarized Financial Data – Tengizchevroil LLP

Chevron has a 50 percent equity ownership interest in Tengizchevroil LLP (TCO). Refer to Note 14, beginning on page 69, for a discussion of TCO operations. Summarized financial information for 100 percent of TCO is presented in the table below:



	Year ended December 31
	2018		2017		2016
Sales and other operating revenues	$	17,260	$	13,363	$	10,460
Costs and other deductions	7,446		6,507		6,822
Net income attributable to TCO	6,908		4,841		2,563



	At December 31
	2018		2017
Current assets	$	2,374	$	4,239
Other assets	34,727		26,411
Current liabilities	3,069		2,517
Other liabilities	6,357		6,266
Total TCO net equity	$	27,675	$	21,867

Note 8

Fair Value Measurements

The tables on the next page show the fair value hierarchy for assets and liabilities measured at fair value on a recurring and nonrecurring basis at December 31, 2018, and December 31, 2017.

Marketable Securities The company calculates fair value for its marketable securities based on quoted market prices for identical assets. The fair values reflect the cash that would have been received if the instruments were sold at December 31, 2018.

Derivatives The company records its derivative instruments – other than any commodity derivative contracts that are designated as normal purchase and normal sale – on the Consolidated Balance Sheet at fair value, with the offsetting amount to the Consolidated Statement of Income. Derivatives classified as Level 1 include futures, swaps and options contracts traded in active markets such as the New York Mercantile Exchange. Derivatives classified as Level 2 include swaps, options and forward contracts principally with financial institutions and other oil and gas companies, the fair values of which are

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

obtained from third-party broker quotes, industry pricing services and exchanges. The company obtains multiple sources of pricing information for the Level 2 instruments. Since this pricing information is generated from observable market data, it has historically been very consistent. The company does not materially adjust this information.

Properties, Plant and Equipment The company did not have any individually material impairments in 2018 or 2017.

Investments and Advances The company did not have any individually material impairments of investments and advances in 2018 or 2017.

Assets and Liabilities Measured at Fair Value on a Recurring Basis



	At December 31, 2018								At December 31, 2017
	Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3
Marketable securities	$	53	$	53	$	—	$	—	$	9	$	9	$	—	$	—
Derivatives	283		185		98		—		22		—		22		—
Total assets at fair value	$	336	$	238	$	98	$	—	$	31	$	9	$	22	$	—
Derivatives	12		—		12		—		124		78		46		—
Total liabilities at fair value	$	12	$	—	$	12	$	—	$	124	$	78	$	46	$	—

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 2018		Total		Level 1		Level 2		Level 3		Year 2017
Properties, plant and equipment, net (held and used)	$	102	$	—	$	62	$	40	$	97	$	603	$	—	$	—	$	603	$	658
Properties, plant and equipment, net (held for sale)	1,694		—		1,273		421		638		1,378		—		1,378		—		363
Investments and advances	81		—		20		61		69		28		—		1		27		26
Total nonrecurring assets at fair value	$	1,877	$	—	$	1,355	$	522	$	804	$	2,009	$	—	$	1,379	$	630	$	1,047

Assets and Liabilities Not Required to Be Measured at Fair Value The company holds cash equivalents and time deposits in U.S. and non-U.S. portfolios. The instruments classified as cash equivalents are primarily bank time deposits with maturities of 90 days or less and money market funds. “Cash and cash equivalents” had carrying/fair values of $9,342 and $4,813 at December 31, 2018, and December 31, 2017, respectively. The instruments held in "Time deposits" are bank time deposits with maturities greater than 90 days and had carrying/fair values of $950 and zero at December 31, 2018, and December 31, 2017, 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, 2018.

"Cash and cash equivalents” do not include investments with a carrying/fair value of $1,139 and $1,130 at December 31, 2018, and December 31, 2017, respectively. At December 31, 2018, these investments are classified as Level 1 and include restricted funds related to certain upstream abandonment activities, tax payments and a financing program, which are reported in “Deferred charges and other assets” on the Consolidated Balance Sheet. Long-term debt, excluding capital lease obligations, of $18,706 and $23,477 at December 31, 2018, and December 31, 2017, respectively, had estimated fair values of $18,729 and $23,943, respectively. Long-term debt primarily includes corporate issued bonds. The fair value of corporate bonds is $17,858 and classified as Level 1. The fair value of other long-term debt is $871 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, 2018 and 2017, were not material.

Note 9

Financial and Derivative Instruments

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

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

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

Derivative instruments measured at fair value at December 31, 2018, December 31, 2017, and December 31, 2016, and their classification on the Consolidated Balance Sheet and Consolidated Statement of Income are below:

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



				At December 31
Type of Contract	Balance Sheet Classification	2018		2017
Commodity	Accounts and notes receivable, net	$	279	$	22
Commodity	Long-term receivables, net	4		—
Total assets at fair value		$	283	$	22
Commodity	Accounts payable	$	12	$	122
Commodity	Deferred credits and other noncurrent obligations	—		2
Total liabilities at fair value		$	12	$	124

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



		Gain/(Loss)
Type of Derivative	Statement of	Year ended December 31
Contract	Income Classification	2018			2017			2016
Commodity	Sales and other operating revenues	$	135		$	(105	)	$	(269	)
Commodity	Purchased crude oil and products	(33		)	(9		)	(31		)
Commodity	Other income	3			(2		)	—
		$	105		$	(116	)	$	(300	)

The table below represents gross and net derivative assets and liabilities subject to netting agreements on the Consolidated Balance Sheet at December 31, 2018 and December 31, 2017.

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



	Gross Amounts Recognized		Gross Amounts Offset		Net Amounts Presented		Gross Amounts Not Offset		Net Amounts
At December 31, 2018	Gross Amounts Recognized		Gross Amounts Offset		Net Amounts Presented		Gross Amounts Not Offset		Net Amounts
Derivative Assets	$	3,685	$	3,402	$	283	$	—	$	283
Derivative Liabilities	$	3,414	$	3,402	$	12	$	—	$	12
At December 31, 2017
Derivative Assets	$	1,169	$	1,147	$	22	$	—	$	22
Derivative Liabilities	$	1,271	$	1,147	$	124	$	—	$	124

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.

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Note 10

Assets Held for Sale

At December 31, 2018, the company classified $1,863 of net properties, plant and equipment as “Assets held for sale” on the Consolidated Balance Sheet. These assets are primarily associated with upstream operations that are anticipated to be sold in the next 12 months. The revenues and earnings contributions of these assets in 2018 were not material.

Note 11

Equity

Retained earnings at December 31, 2018 and 2017, included approximately $22,362 and $18,473, respectively, for the company’s share of undistributed earnings of equity affiliates.

At December 31, 2018, about 78 million shares of Chevron’s common stock remained available for issuance from the 260 million shares that were reserved for issuance under the Chevron Long-Term Incentive Plan. In addition, 748,211 shares remain available for issuance from the 1,600,000 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 12

Earnings Per Share

Basic earnings per share (EPS) is based upon “Net Income (Loss) 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 21, “Stock Options and Other Share-Based Compensation,” beginning on page 80). The table below sets forth the computation of basic and diluted EPS:



	Year ended December 31
	2018		2017		2016
Basic EPS Calculation
Earnings available to common stockholders - Basic¹	$	14,824	$	9,195	$	(497	)
Weighted-average number of common shares outstanding²	1,897		1,882		1,872
Add: Deferred awards held as stock units	1		1		1
Total weighted-average number of common shares outstanding	1,898		1,883		1,873
Earnings per share of common stock - Basic	$	7.81	$	4.88	$	(0.27	)
Diluted EPS Calculation
Earnings available to common stockholders - Diluted¹	$	14,824	$	9,195	$	(497	)
Weighted-average number of common shares outstanding²	1,897		1,882		1,872
Add: Deferred awards held as stock units	1		1		1
Add: Dilutive effect of employee stock-based awards	16		15		—
Total weighted-average number of common shares outstanding	1,914		1,898		1,873
Earnings per share of common stock - Diluted	$	7.74	$	4.85	$	(0.27	)

¹There was no effect of dividend equivalents paid on stock units or dilutive impact of employee stock-based awards on earnings.
² Millions of shares; 10 million shares of employee-based awards were not included in the 2016 diluted EPS calculation as the result would be anti-dilutive.

Note 13

Operating Segments and Geographic Data

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

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

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

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

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 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
	2018			2017			2016
Upstream
United States	$	3,278		$	3,640		$	(2,054	)
International	10,038			4,510			(483		)
Total Upstream	13,316			8,150			(2,537		)
Downstream
United States	2,103			2,938			1,307
International	1,695			2,276			2,128
Total Downstream	3,798			5,214			3,435
Total Segment Earnings	17,114			13,364			898
All Other
Interest expense	(713		)	(264		)	(168		)
Interest income	137			60			58
Other	(1,714		)	(3,965		)	(1,285		)
Net Income (Loss) Attributable to Chevron Corporation	$	14,824		$	9,195		$	(497	)

Segment Assets Segment assets do not include intercompany investments or receivables. Assets at year-end 2018 and 2017 are as follows:



	At December 31
	2018		2017
Upstream
United States	$	42,594	$	40,770
International	153,861		159,612
Goodwill	4,518		4,531
Total Upstream	200,973		204,913
Downstream
United States	23,866		23,202
International	15,622		17,434
Total Downstream	39,488		40,636
Total Segment Assets	240,461		245,549
All Other
United States	5,100		4,938
International	8,302		3,319
Total All Other	13,402		8,257
Total Assets – United States	71,560		68,910
Total Assets – International	177,785		180,365
Goodwill	4,518		4,531
Total Assets	$	253,863	$	253,806

Segment Sales and Other Operating Revenues Operating segment sales and other operating revenues, including internal transfers, for the years 2018, 2017 and 2016, are presented in the table on the next page. Products are transferred between operating segments at internal product values that approximate market prices.

Revenues for the upstream segment are derived primarily from the production and sale of crude oil and natural gas, as well as the sale of third-party production of natural gas. Revenues for the downstream segment are derived from the refining and

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

marketing of petroleum products such as gasoline, jet fuel, gas oils, lubricants, residual fuel oils and other products derived from crude oil. This segment also generates revenues from the manufacture and sale of fuel and lubricant additives and the transportation and trading of refined products and crude oil. "All Other" activities include revenues from insurance operations, real estate activities and technology companies.



	Year ended December 31¹
	2018			2017			2016
Upstream
United States	$	8,926		$	3,901		$	3,148
Intersegment	13,965			9,341			7,217
Total United States	22,891			13,242			10,365
International	24,143			17,209			13,262
Intersegment	13,679			11,471			9,518
Total International	37,822			28,680			22,780
Total Upstream	60,713			41,922			33,145
Downstream
United States	56,634			48,728			40,366
Excise and similar taxes²	—			4,398			4,335
Intersegment	2,742			14			16
Total United States	59,376			53,140			44,717
International	68,963			57,438			46,388
Excise and similar taxes²	—			2,791			2,570
Intersegment	1,132			1,166			1,068
Total International	70,095			61,395			50,026
Total Downstream	129,471			114,535			94,743
All Other
United States	236			208			145
Intersegment	786			814			960
Total United States	1,022			1,022			1,105
International	—			1			1
Intersegment	22			25			36
Total International	22			26			37
Total All Other	1,044			1,048			1,142
Segment Sales and Other Operating Revenues
United States	83,289			67,404			56,187
International	107,939			90,101			72,843
Total Segment Sales and Other Operating Revenues	191,228			157,505			129,030
Elimination of intersegment sales	(32,326		)	(22,831		)	(18,815		)
Total Sales and Other Operating Revenues	$	158,902		$	134,674		$	110,215
¹Other than the United States, no other country accounted for 10 percent or more of the company’s Sales and Other Operating Revenues.
² Netted in "Taxes other than on income" beginning in 2018 in accordance with ASU 2014-09. Refer to Note 25 beginning on page 88.

Segment Income Taxes Segment income tax expense for the years 2018, 2017 and 2016 is as follows:



	Year ended December 31
	2018			2017			2016
Upstream
United States	$	811		$	(3,538	)	$	(1,172	)
International	4,687			2,249			166
Total Upstream	5,498			(1,289		)	(1,006		)
Downstream
United States	534			(419		)	503
International	328			650			484
Total Downstream	862			231			987
All Other	(645		)	1,010			(1,710		)
Total Income Tax Expense (Benefit)	$	5,715		$	(48	)	$	(1,729	)

Other Segment Information Additional information for the segmentation of major equity affiliates is contained in Note 14, on page 69. Information related to properties, plant and equipment by segment is contained in Note 17, on page 77.

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Note 14

Investments and Advances

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



Investments and Advances							Equity in Earnings
	At December 31						Year ended December 31
	2018			2017			2018			2017			2016
Upstream
Tengizchevroil	$	16,017		$	13,121		$	3,614		$	2,581		$	1,380
Petropiar	1,361			1,152			317			175			326
Petroboscan	1,315			1,080			357			154			(133		)
Caspian Pipeline Consortium	1,022			1,151			170			155			145
Angola LNG Limited	2,496			2,625			172			27			(282		)
Other	1,541			1,714			19			104			(193		)
Total Upstream	23,752			20,843			4,649			3,196			1,243
Downstream
Chevron Phillips Chemical Company LLC	6,218			6,200			1,034			723			840
GS Caltex Corporation	3,924			3,826			373			290			373
Other	1,383			1,251			273			230			209
Total Downstream	11,525			11,277			1,680			1,243			1,422
All Other
Other	(16		)	(15		)	(2		)	(1		)	(4		)
Total equity method	35,261			$	32,105		$	6,327		$	4,438		$	2,661
Other non-equity method investments	285			392
Total investments and advances	$	35,546		$	32,497
Total United States	$	7,500		$	7,582		$	1,033		$	788		$	802
Total International	$	28,046		$	24,915		$	5,294		$	3,650		$	1,859

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

Tengizchevroil Chevron has a 50 percent equity ownership interest in Tengizchevroil (TCO), which operates the Tengiz and Korolev crude oil fields in Kazakhstan. At December 31, 2018, the company’s carrying value of its investment in TCO was about $120 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. Included in the investment is a loan to TCO to fund the development of the Future Growth and Wellhead Pressure Management Project with a balance of $2,060, including accrued interest. See Note 7, on page 63, for summarized financial information for 100 percent of TCO.

Petropiar Chevron has a 30 percent interest in Petropiar, a joint stock company which operates the heavy oil Huyapari Field and upgrading project in Venezuela’s Orinoco Belt. At December 31, 2018, the company’s carrying value of its investment in Petropiar was approximately $136 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.

Petroboscan Chevron has a 39.2 percent interest in Petroboscan, a joint stock company which operates the Boscan Field in Venezuela. At December 31, 2018, the company’s carrying value of its investment in Petroboscan was approximately $97 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. The company also has an outstanding long-term loan to Petroboscan of $626 at year-end 2018.

Caspian Pipeline Consortium Chevron has a 15 percent interest in the Caspian Pipeline Consortium, a variable interest entity, which provides the critical export route for crude oil from both TCO and Karachaganak. The company has investments and advances totaling $1,022, which includes long-term loans of $468 at year-end 2018. 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.

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

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

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

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

Other Information “Sales and other operating revenues” on the Consolidated Statement of Income includes $10,378, $8,165 and $5,786 with affiliated companies for 2018, 2017 and 2016, respectively. “Purchased crude oil and products” includes $6,598, $4,800 and $3,468 with affiliated companies for 2018, 2017 and 2016, respectively.

“Accounts and notes receivable” on the Consolidated Balance Sheet includes $884 and $1,141 due from affiliated companies at December 31, 2018 and 2017, respectively. “Accounts payable” includes $631 and $498 due to affiliated companies at December 31, 2018 and 2017, respectively.

The following table provides summarized financial information on a 100 percent basis for all equity affiliates as well as Chevron’s total share, which includes Chevron's net loans to affiliates of $3,402, $3,853 and $3,535 at December 31, 2018, 2017 and 2016, respectively.



	Affiliates						Chevron Share
Year ended December 31	2018		2017		2016		2018		2017		2016
Total revenues	$	84,469	$	70,744	$	59,253	$	40,679	$	33,460	$	27,787
Income before income tax expense	16,693		13,487		6,587		6,755		5,712		3,670
Net income attributable to affiliates	13,321		10,751		5,127		6,384		4,468		2,876
At December 31
Current assets	$	32,657	$	33,883	$	33,406	$	12,813	$	13,568	$	13,743
Noncurrent assets	87,614		82,261		75,258		36,369		32,643		28,854
Current liabilities	26,006		26,873		24,793		9,843		10,201		8,996
Noncurrent liabilities	20,000		21,447		22,671		4,446		4,224		4,255
Total affiliates' net equity	$	74,265	$	67,824	$	61,200	$	34,893	$	31,786	$	29,346

Note 15

Litigation

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

Ecuador

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

Based on the history described above, Chevron believes that this lawsuit lacks legal or factual merit. As to matters of law, the company believes first, that the court lacks jurisdiction over Chevron; second, that the law under which plaintiffs bring the

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

action, enacted in 1999, cannot be applied retroactively; third, that the claims are barred by the statute of limitations in Ecuador; and, fourth, that the lawsuit is also barred by the releases from liability previously given to Texpet by the Republic of Ecuador and Petroecuador and by the pertinent provincial and municipal governments. With regard to the facts, the company believes that the evidence confirms that Texpet’s remediation was properly conducted and that the remaining environmental damage reflects Petroecuador’s failure to timely fulfill its legal obligations and Petroecuador’s further conduct since assuming full control over the operations.

Lago Agrio Judgment On February 14, 2011, the provincial court rendered a judgment against Chevron. The court rejected Chevron’s defenses to the extent the court addressed them in its opinion. The judgment assessed approximately $8,600 in damages and approximately $900 as an award for the plaintiffs’ representatives. It also assessed an additional amount of approximately $8,600 in punitive damages unless the company issued a public apology within 15 days of the judgment, which Chevron did not do. On February 17, 2011, the plaintiffs appealed the judgment, seeking increased damages, and on March 11, 2011, Chevron appealed the judgment seeking to have the judgment nullified. On January 3, 2012, an appellate panel in the provincial court affirmed the February 14, 2011 decision and ordered that Chevron pay additional attorneys’ fees in the amount of “0.10% of the values that are derived from the decisional act of this judgment.” The plaintiffs filed a petition to clarify and amplify the appellate decision on January 6, 2012, and the provincial 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 (the National Court). 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 to hear the appeal. On March 29, 2012, the matter was transferred from the provincial court to the National Court, and on November 22, 2012, the National Court agreed to hear Chevron's cassation appeal. On August 3, 2012, the provincial court approved a court-appointed liquidator’s report on damages that calculated the total judgment in the case to be $19,100. On November 13, 2013, the National Court ratified the judgment but nullified the $8,600 punitive damage assessment, resulting in a judgment of $9,500. On December 23, 2013, Chevron appealed the decision to the Ecuador Constitutional Court, Ecuador's highest court. The reporting justice of the Constitutional Court heard oral arguments on the appeal on July 16, 2015. On July 10, 2018, Ecuador's Constitutional Court released a decision rejecting Chevron's appeal, which sought to nullify the National Court's judgment against Chevron. No further appeals are available in Ecuador.

Lago Agrio Plaintiffs' Enforcement Actions Chevron has no assets in Ecuador and the Lago Agrio plaintiffs' lawyers have stated in press releases and through other media that they will seek to enforce the Ecuadorian judgment in various countries and otherwise disrupt Chevron's operations. On May 30, 2012, the Lago Agrio plaintiffs filed an action against Chevron Corporation, Chevron Canada Limited, and Chevron Canada Finance Limited in the Ontario Superior Court of Justice in Ontario, Canada, seeking to recognize and enforce the Ecuadorian judgment. On May 1, 2013, the Ontario Superior Court of Justice held that the Court has jurisdiction over Chevron and Chevron Canada Limited for purposes of the action, but stayed the action due to the absence of evidence that Chevron Corporation has assets in Ontario. The Lago Agrio plaintiffs appealed that decision and on December 17, 2013, the Court of Appeal for Ontario affirmed the lower court’s decision on jurisdiction and set aside the stay, allowing the recognition and enforcement action to be heard in the Ontario Superior Court of Justice. Chevron appealed the decision to the Supreme Court of Canada and, on September 4, 2015, the Supreme Court dismissed the appeal and affirmed that the Ontario Superior Court of Justice has jurisdiction over Chevron and Chevron Canada Limited for purposes of the action. On January 20, 2017, the Ontario Superior Court of Justice granted Chevron Canada Limited’s and Chevron Corporation’s motions for summary judgment, concluding that the two companies are separate legal entities with separate rights and obligations. As a result, the Superior Court dismissed the recognition and enforcement claim against Chevron Canada Limited. Chevron Corporation still remains as a defendant in the action. On February 3, 2017, the Lago Agrio plaintiffs appealed the Superior Court's January 20, 2017 decision. On May 24, 2018, the Court of Appeal for Ontario upheld the Superior Court’s dismissal of Chevron Canada Limited from the case. On June 22, 2018, the Lago Agrio plaintiffs filed leave to appeal the decision of the Court of Appeal for Ontario to the Supreme Court of Canada.

On June 27, 2012, the Lago Agrio plaintiffs filed a complaint against Chevron Corporation in the Superior Court of Justice in Brasilia, Brazil, seeking to recognize and enforce the Ecuadorian judgment. On May 13, 2015, the public prosecutor issued its nonbinding opinion and recommended that the Superior Court of Justice reject the plaintiffs' recognition and enforcement request, finding, among other things, that the Lago Agrio judgment was procured through fraud and corruption and cannot be recognized in Brazil because it violates Brazilian and international public order. On November 29, 2017, the Superior Court

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

of Justice issued a decision dismissing the Lago Agrio plaintiffs’ recognition and enforcement proceeding based on jurisdictional grounds. On June 15, 2018, this decision became a final judgment in Brazil.

On October 15, 2012, the provincial court 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. On January 30, 2013, an appellate court upheld the Freeze Order, but on June 4, 2013 the Supreme Court of Argentina revoked the Freeze Order in its entirety. On December 12, 2013, the Lago Agrio plaintiffs served Chevron with notice of their filing of an enforcement proceeding in the National Court, First Instance, of Argentina. Chevron filed its answer on February 27, 2014, to which the Lago Agrio plaintiffs responded on December 29, 2015. On April 19, 2016, the public prosecutor in Argentina issued a non-binding opinion recommending to the National Court, First Instance, of Argentina that it reject the Lago Agrio plaintiffs' request to recognize the Ecuadorian judgment in Argentina. On February 24, 2017, the public prosecutor in Argentina issued a supplemental opinion reaffirming its previous recommendations. On November 1, 2017, the National Court, First Instance, of Argentina issued a decision dismissing the Lago Agrio plaintiffs' recognition and enforcement proceeding based on jurisdictional grounds. On November 2, 2017, the Lago Agrio plaintiffs appealed this decision to the Federal Civil Court of Appeals. On July 3, 2018, the Federal Civil Court of Appeals affirmed the National Court, First Instance’s, dismissal of the Lago Agrio plaintiffs’ recognition and enforcement action based on jurisdictional grounds. On October 5, 2018, the Federal Civil Court of Appeals granted, in part, the admissibility of the Lago Agrio plaintiffs’ appeal to the Supreme Court of Argentina.

Chevron continues to believe the Ecuadorian 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 any enforcement action. Chevron expects to continue a vigorous defense of any imposition of liability and to contest and defend any and all enforcement actions.

Company's Bilateral Investment Treaty Arbitration Claims Chevron and Texpet filed an arbitration claim in September 2009 against the Republic of Ecuador before an arbitral tribunal presiding in the Permanent Court of Arbitration in The Hague under the Rules of the United Nations Commission on International Trade Law. The claim alleges violations of the Republic of Ecuador’s obligations under the United States–Ecuador Bilateral Investment Treaty (BIT) and breaches of the settlement and release agreements between the Republic of Ecuador and Texpet (described above), which are investment agreements protected by the BIT. Through the arbitration, Chevron and Texpet are seeking relief against the Republic of Ecuador, including a declaration that any judgment against Chevron in the Lago Agrio litigation constitutes a violation of Ecuador’s obligations under the BIT. On January 25, 2012, the Tribunal issued its First Interim Measures Award 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 outside of Ecuador of any judgment against Chevron in the Lago Agrio case pending further order of the Tribunal. On February 16, 2012, the Tribunal issued a Second Interim Award mandating that the Republic of Ecuador take all measures necessary (whether by its judicial, legislative or executive branches) to suspend or cause to be suspended the enforcement and recognition within and outside of Ecuador of the judgment against Chevron. On February 27, 2012, the Tribunal issued a Third Interim Award confirming its jurisdiction to hear Chevron's arbitration claims. On February 7, 2013, the Tribunal issued its Fourth Interim Award in which it declared that the Republic of Ecuador “has violated the First and Second Interim Awards under the [BIT], the UNCITRAL Rules and international law in regard to the finalization and enforcement subject to execution of the Lago Agrio Judgment within and outside Ecuador, including (but not limited to) Canada, Brazil and Argentina.” The Republic of Ecuador subsequently filed in the District Court of The Hague a request to set aside the Tribunal’s Interim Awards and the First Partial Award (described below), and on January 20, 2016, the District Court denied the Republic's request. On April 13, 2016, the Republic of Ecuador appealed the decision. On July 18, 2017, the Appeals Court of The Hague denied the Republic's appeal. On October 18, 2017, the Republic appealed the decision of the Appeals Court of The Hague to the Supreme Court of the Netherlands.

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

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

agreement and the remedies that are available to Chevron and Texpet as a result of that breach. Phase Two issues were addressed at a hearing held in April and May 2015.

On August 30, 2018, the Tribunal issued its Phase Two award in favor of Chevron and Texpet. The Tribunal unanimously held that the Ecuadorian judgment was procured through fraud, bribery and corruption and was based on claims that the Republic of Ecuador had settled and released in the mid-1990s, concluding that the Ecuadorian judgment “violates international public policy” and “should not be recognized or enforced by the courts of other States.” Specifically, the Tribunal found that (i) the Republic of Ecuador breached its obligations under the 1995 and 1998 settlement agreements releasing Texpet and its affiliates from public environmental claims (the same claims on which the Ecuadorian judgment was exclusively based) and (ii) the Republic of Ecuador committed a denial of justice under customary international law and under the fair and equitable treatment provision of the BIT due to the fraud and corruption in the Lago Agrio litigation. The Tribunal also found that Texpet satisfied its environmental remediation obligations with a $40 remediation program and that Ecuador certified that Texpet had performed all of its obligations under its settlement agreement. Among other things, the Tribunal ordered the Republic of Ecuador to: (a) take immediate steps to remove the status of enforceability from the Ecuadorian judgment; (b) promptly advise in writing any State where the Lago Agrio plaintiffs may be seeking the enforcement or recognition of the Ecuadorian judgment of the Tribunal’s declarations, orders and awards; (c) take measures to “wipe out all the consequences” of Ecuador's "internationally wrongful acts in regard to the Ecuadorian judgment" and (d) compensate Chevron for any injuries resulting from the Ecuadorian judgment. On December 10, 2018, the Republic of Ecuador filed in the District Court of The Hague a request to set aside the Tribunal's Phase Two Award. The Tribunal has not set a date for Phase Three, the third and final phase of the arbitration, at which damages for Chevron's injuries will be determined.

Company's RICO Action 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 sought relief that included 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. The trial commenced on October 15, 2013 and concluded on November 22, 2013. On March 4, 2014, the Federal District Court entered a judgment in favor of Chevron, prohibiting the defendants from seeking to enforce the Lago Agrio judgment in the United States and further prohibiting them from profiting from their illegal acts. The defendants appealed the Federal District Court's decision, and, on April 20, 2015, the U.S. Court of Appeals for the Second Circuit heard oral arguments. On August 8, 2016, the Second Circuit issued a unanimous opinion affirming in full the judgment of the Federal District Court. On October 27, 2016, the Second Circuit denied the defendants' petitions for en banc rehearing of the opinion on their appeal. On March 27, 2017, two of the defendants filed a petition for a Writ of Certiorari to the United States Supreme Court. On June 19, 2017, the United States Supreme Court denied the defendants' petition for a Writ of Certiorari.

Management's Assessment The ultimate outcome of the foregoing matters, including any financial effect on Chevron, remains uncertain. Management does not believe an estimate of a reasonably possible loss (or a range of loss) can be made in this case. Due to the defects associated with the Ecuadorian judgment, management does not believe the judgment has 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).

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Note 16

Taxes



Income Taxes	Year ended December 31
	2018			2017			2016
Income tax expense (benefit)
U.S. federal
Current	$	(181	)	$	(382	)	$	(623	)
Deferred	738			(2,561		)	(1,558		)
State and local
Current	183			(97		)	(15		)
Deferred	(16		)	66			(121		)
Total United States	724			(2,974		)	(2,317		)
International
Current	4,662			3,634			2,744
Deferred	329			(708		)	(2,156		)
Total International	4,991			2,926			588
Total income tax expense (benefit)	$	5,715		$	(48	)	$	(1,729	)

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:



	2018			2017			2016
Income (loss) before income taxes
United States	$	4,730		$	(441	)	$	(4,317	)
International	15,845			9,662			2,157
Total income (loss) before income taxes	20,575			9,221			(2,160		)
Theoretical tax (at U.S. statutory rate of 21% - 2018, 35% - 2017 & 2016)	4,321			3,227			(756		)
Effect of U.S. tax reform	(26		)	(2,020		)	—
Equity affiliate accounting effect	(1,526		)	(1,373		)	(704		)
Effect of income taxes from international operations^*	3,132			(130		)	608
State and local taxes on income, net of U.S. federal income tax benefit	162			39			(44		)
Prior year tax adjustments, claims and settlements	(51		)	(39		)	(349		)
Tax credits	(163		)	(199		)	(188		)
Other U.S.^*	(134		)	447			(296		)
Total income tax expense (benefit)	$	5,715		$	(48	)	$	(1,729	)

Effective income tax rate	27.8		%	(0.5		)%	80.0		%

^*Includes one-time tax costs (benefits) associated with changes in uncertain tax positions and valuation allowances.

The 2018 increase in income tax charge of $5,763, from a benefit of $48 in 2017 to a charge of $5,715 in 2018, is a result of the year-over-year increase in total income before income tax expense, which is primarily due to higher crude oil realizations offset by lower gains on asset sales in 2018 compared to 2017. U.S. tax reform resulted in a benefit of $2,020 being recognized in 2017 reflecting the remeasurement of U.S. deferred tax assets and liabilities. The company’s effective tax rate changed from (0.5) percent in 2017 to 28 percent in 2018. The change in effective tax rate is a consequence of the mix effect resulting from the absolute level of earnings or losses and whether they arose in higher or lower tax rate jurisdictions and the impact of U.S. tax reform to both the 2018 and 2017 results.

As noted above, U.S. tax reform resulted in the remeasurement of U.S. deferred tax assets and liabilities in 2017. The U.S. tax return for 2017 was prepared and filed in 2018 and did not result in any material change to the the provisional amounts that were recognized in 2017, and the amounts are now considered final.

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

The company records its deferred taxes on a tax-jurisdiction basis. The reported deferred tax balances are composed of the following:



				At December 31
	2018			2017
Deferred tax liabilities
Properties, plant and equipment	$	20,159		$	19,869
Investments and other	4,943			4,796
Total deferred tax liabilities	25,102			24,665
Deferred tax assets
Foreign tax credits	(10,536		)	(11,872		)
Asset retirement obligations/environmental reserves	(5,328		)	(5,511		)
Employee benefits	(2,787		)	(3,129		)
Deferred credits	(1,373		)	(1,769		)
Tax loss carryforwards	(4,948		)	(5,463		)
Other accrued liabilities	(595		)	(842		)
Inventory	(505		)	(336		)
Miscellaneous	(3,481		)	(2,415		)
Total deferred tax assets	(29,553		)	(31,337		)
Deferred tax assets valuation allowance	15,973			16,574
Total deferred taxes, net	$	11,522		$	9,902

Deferred tax liabilities at the end of 2018 increased by approximately $400 from year-end 2017. The increase was primarily related to property, plant and equipment temporary differences.

Deferred tax assets decreased by approximately $1,800 in 2018. The decrease primarily related to lower foreign tax credits and the utilization of tax loss carryforwards.

The overall valuation allowance relates to deferred tax assets for U.S. foreign tax credit carryforwards, tax loss carryforwards and temporary differences. It reduces the deferred tax assets to amounts that are, in management’s assessment, more likely than not to be realized. At the end of 2018, the company had tax loss carryforwards of approximately $13,731 and tax credit carryforwards of approximately $1,198, primarily related to various international tax jurisdictions. Whereas some of these tax loss carryforwards do not have an expiration date, others expire at various times from 2019 through 2036. U.S. foreign tax credit carryforwards of $10,536 will expire between 2019 and 2028.

At December 31, 2018 and 2017, deferred taxes were classified on the Consolidated Balance Sheet as follows:



	At December 31
	2018			2017
Deferred charges and other assets	$	(4,399	)	$	(4,750	)
Noncurrent deferred income taxes	15,921			14,652
Total deferred income taxes, net	$	11,522		$	9,902

Enactment of U.S. tax reform in 2017 imposed a one-time U.S. federal tax on the deemed repatriation of unremitted earnings indefinitely reinvested abroad, which did not have a material impact on the company’s financial results. The indefinite reinvestment assertion continues to apply for the purpose of determining deferred tax liabilities for U.S. state and foreign withholding tax purposes.

U.S. state and foreign withholding 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 $59,900 at December 31, 2018. This amount represents earnings reinvested as part of the company’s ongoing international business. It is not practicable to estimate the amount of state and foreign taxes that might be payable on the possible remittance of earnings that are intended to be reinvested indefinitely. The company does not anticipate incurring significant additional taxes on remittances of earnings that are not indefinitely reinvested.

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

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

The following table indicates the changes to the company’s unrecognized tax benefits for the years ended December 31, 2018, 2017 and 2016. 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.



	2018			2017			2016
Balance at January 1	$	4,828		$	3,031		$	3,042
Foreign currency effects	(6		)	43			1
Additions based on tax positions taken in current year	239			1,853			245
Additions for tax positions taken in prior years	153			1,166			181
Reductions for tax positions taken in prior years	(131		)	(90		)	(390		)
Settlements with taxing authorities in current year	(13		)	(1,173		)	(36		)
Reductions as a result of a lapse of the applicable statute of limitations	—			(2		)	(12		)
Balance at December 31	$	5,070		$	4,828		$	3,031

Approximately 82 percent of the $5,070 of unrecognized tax benefits at December 31, 2018, 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, 2018. For these jurisdictions, the latest years for which income tax examinations had been finalized were as follows: United States – 2013, Nigeria – 2000, Australia – 2006 and Kazakhstan – 2007.

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

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, 2018, accruals of $33 for anticipated interest and penalty obligations were included on the Consolidated Balance Sheet, compared with accruals of $178 as of year-end 2017. Income tax expense (benefit) associated with interest and penalties was $8, $(161) and $38 in 2018, 2017 and 2016, respectively.



Taxes Other Than on Income	Year ended December 31
	2018			2017		2016
United States
Excise and similar taxes on products and merchandise*	$	4,830		$	4,398	$	4,335
Consumer excise taxes collected on behalf of third parties*	(4,830		)	—		—
Import duties and other levies	15			11		9
Property and other miscellaneous taxes	1,577			1,824		1,680
Payroll taxes	246			241		252
Taxes on production	325			206		159
Total United States	2,163			6,680		6,435
International
Excise and similar taxes on products and merchandise*	3,031			2,791		2,570
Consumer excise taxes collected on behalf of third parties*	(3,031		)	—		—
Import duties and other levies	37			45		33
Property and other miscellaneous taxes	2,370			2,563		2,379
Payroll taxes	132			137		145
Taxes on production	165			115		106
Total International	2,704			5,651		5,233
Total taxes other than on income	$	4,867		$	12,331	$	11,668

^*Beginning in 2018, these taxes are netted in "Taxes other than on income" in accordance with ASU 2014-09. Refer to Note 25, "Revenue" beginning on page 88.

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Note 17

Properties, Plant and Equipment¹



	At December 31												Year ended December 31
	Gross Investment at Cost						Net Investment						Additions at Cost²						Depreciation Expense³
	2018		2017		2016		2018		2017		2016		2018		2017		2016		2018		2017		2016
Upstream
United States	$	88,155	$	84,602	$	83,929	$	39,526	$	38,722	$	39,710	$	6,434	$	4,995	$	4,432	$	5,328	$	5,527	$	6,576
International	215,329		224,211		214,557		113,603		123,191		125,502		4,865		7,934		12,084		12,726		12,096		11,247
Total Upstream	303,484		308,813		298,486		153,129		161,913		165,212		11,299		12,929		16,516		18,054		17,623		17,823
Downstream
United States	24,685		23,598		22,795		10,838		10,346		10,196		1,259		907		528		751		753		956
International	7,237		7,094		9,350		3,023		3,074		4,094		278		306		375		282		282		332
Total Downstream	31,922		30,692		32,145		13,861		13,420		14,290		1,537		1,213		903		1,033		1,035		1,288
All Other
United States	4,667		4,798		5,263		2,186		2,341		2,635		224		218		198		320		677		328
International	171		182		183		31		38		49		6		4		6		12		14		18
Total All Other	4,838		4,980		5,446		2,217		2,379		2,684		230		222		204		332		691		346
Total United States	117,507		112,998		111,987		52,550		51,409		52,541		7,917		6,120		5,158		6,399		6,957		7,860
Total International	222,737		231,487		224,090		116,657		126,303		129,645		5,149		8,244		12,465		13,020		12,392		11,597
Total	$	340,244	$	344,485	$	336,077	$	169,207	$	177,712	$	182,186	$	13,066	$	14,364	$	17,623	$	19,419	$	19,349	$	19,457


¹	Other than the United States and Australia, no other country accounted for 10 percent or more of the company’s net properties, plant and equipment (PP&E) in 2018. Australia had PP&E of $53,768, $55,514 and $53,962 in 2018, 2017 and 2016, respectively.


²	Net of dry hole expense related to prior years’ expenditures of $343, $42 and $175 in 2018, 2017 and 2016, respectively.


³	Depreciation expense includes accretion expense of $654, $668 and $749 in 2018, 2017 and 2016, respectively, and impairments of $735, $1,021 and $3,186 in 2018, 2017 and 2016, respectively.

Note 18

Short-Term Debt



	At December 31
	2018			2017
Commercial paper¹	$	7,503		$	5,379
Notes payable to banks and others with originating terms of one year or less	28			—
Current maturities of long-term debt²	4,999			6,720
Current maturities of long-term capital leases	18			15
Redeemable long-term obligations
Long-term debt	3,078			3,078
Capital leases	—			—
Subtotal	15,626			15,192
Reclassified to long-term debt	(9,900		)	(10,000		)
Total short-term debt	$	5,726		$	5,192
¹Weighted-average interest rates at December 31, 2018 and 2017, were 2.43 percent and 1.30 percent, respectively.
²Net of unamortized discounts and issuance costs: $1 in 2018 and $2 in 2017.

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, 2018, the company had no interest rate swaps on short-term debt.

At December 31, 2018, the company had $9,900 in committed credit facilities with various major banks that enable the refinancing of short-term obligations on a long-term basis. The credit facilities consist of a 364-day facility which enables borrowing of up to $9,575 and allows the company to convert any amounts outstanding into a term loan for a period of up to one year, and a $325 five-year facility expiring in December 2020. These facilities support commercial paper borrowing and can also be used for general corporate purposes. The company’s practice has been to continually replace expiring commitments with new commitments on substantially the same terms, maintaining levels management believes appropriate. Any borrowings under the facilities would be unsecured indebtedness at interest rates based on the London Interbank Offered Rate or an average of base lending rates published by specified banks and on terms reflecting the company’s strong credit rating. No borrowings were outstanding under these facilities at December 31, 2018.

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

The company classified $9,900 and $10,000 of short-term debt as long-term at December 31, 2018 and 2017, respectively. Settlement of these obligations is not expected to require the use of working capital within one year, and the company has both the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis.

Note 19

Long-Term Debt

Total long-term debt including capital lease obligations at December 31, 2018, was $28,733. The company’s long-term debt outstanding at year-end 2018 and 2017 was as follows:



	At December 31
	2018			2017
	Principal			Principal
3.191% notes due 2023	$	2,250		$	2,250
2.954% notes due 2026	2,250			2,250
2.355% notes due 2022	2,000			2,000
1.961% notes due 2020	1,750			1,750
4.950% notes due 2019	1,500			1,500
1.561% notes due 2019	1,350			1,350
2.100% notes due 2021	1,350			1,350
2.419% notes due 2020	1,250			1,250
2.427% notes due 2020	1,000			1,000
2.895% notes due 2024	1,000			1,000
Floating rate notes due 2019 (2.905%)¹	850			850
2.193% notes due 2019	750			750
2.566% notes due 2023	750			750
3.326% notes due 2025	750			750
2.498% notes due 2022	700			700
2.411% notes due 2022	700			700
Floating rate notes due 2021 (3.313%)¹	650			650
Floating rate notes due 2022 (3.245%)¹	650			650
1.991% notes due 2020	600			600
1.686% notes due 2019	550			550
Floating rate notes due 2020 (2.948%)²	400			400
3.400% loan³	218			—
8.625% debentures due 2032	147			147
8.625% debentures due 2031	108			108
8.000% debentures due 2032	75			75
9.750% debentures due 2020	54			54
8.875% debentures due 2021	40			40
Medium-term notes, maturing from 2021 to 2038 (6.629%)¹	38			38
1.718% notes due 2018	—			2,000
1.365% notes due 2018	—			1,750
Floating rate notes due 2018	—			1,650
1.790% notes due 2018	—			1,250
Amortizing bank loan due 2018	—			72
Total including debt due within one year	23,730			30,234
Debt due within one year	(5,000		)	(6,722		)
Reclassified from short-term debt	9,900			10,000
Unamortized discounts and debt issuance costs	(24		)	(35		)
Capital lease obligations⁴	127			94
Total long-term debt	$	28,733		$	33,571


¹	Weighted-average interest rate at December 31, 2018.


²	Interest rate at December 31, 2018.


³	Maturity date is conditional upon the occurrence of certain events. 2021 is the earliest period in which the loan may become payable.


⁴	For details on capital lease obligations, see Note 5 beginning on page 62.

Chevron has an automatic shelf registration statement that expires in May 2021. This registration statement is for an unspecified amount of nonconvertible debt securities issued or guaranteed by the company.

Long-term debt excluding capital lease obligations with a principal balance of $23,730 matures as follows: 2019 – $5,000; 2020 – $5,054; 2021 – $2,272; 2022 – $4,050; 2023 – $3,003; and after 2023 – $4,351.

See Note 8, beginning on page 63, for information concerning the fair value of the company’s long-term debt.

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Note 20

Accounting for Suspended Exploratory Wells

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

The following table indicates the changes to the company’s suspended exploratory well costs for the three years ended December 31, 2018:



	2018			2017			2016
Beginning balance at January 1	$	3,702		$	3,540		$	3,312
Additions to capitalized exploratory well costs pending the determination of proved reserves	207			323			465
Reclassifications to wells, facilities and equipment based on the determination of proved reserves	(13		)	(113		)	(119		)
Capitalized exploratory well costs charged to expense	(333		)	(39		)	(118		)
Other reductions^*	—			(9		)	—
Ending balance at December 31	$	3,563		$	3,702		$	3,540

^*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
	2018		2017		2016
Exploratory well costs capitalized for a period of one year or less	$	202	$	307	$	445
Exploratory well costs capitalized for a period greater than one year	3,361		3,395		3,095
Balance at December 31	$	3,563	$	3,702	$	3,540
Number of projects with exploratory well costs that have been capitalized for a period greater than one year^*	30		32		35

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

Of the $3,361 of exploratory well costs capitalized for more than one year at December 31, 2018, $1,585 (14 projects) is related to projects that had drilling activities underway or firmly planned for the near future. The $1,776 balance is related to 16 projects in areas requiring a major capital expenditure before production could begin and for which additional drilling efforts were not underway or firmly planned for the near future. Additional drilling was not deemed necessary because the presence of hydrocarbons had already been established, and other activities were in process to enable a future decision on project development.

The projects for the $1,776 referenced above had the following activities associated with assessing the reserves and the projects’ economic viability: (a) $672 (three projects) – undergoing front-end engineering and design with final investment decision expected within four years; (b) $93 (one project) – development concept under review by government; (c) $963 (eight projects) – development alternatives under review; (d) $48 (four projects) – miscellaneous activities for projects with smaller amounts suspended. While progress was being made on all 30 projects, the decision on the recognition of proved reserves under SEC rules in some cases may not occur for several years because of the complexity, scale and negotiations associated with the projects. More than half of these decisions are expected to occur in the next five years.

The $3,361 of suspended well costs capitalized for a period greater than one year as of December 31, 2018, represents 153 exploratory wells in 30 projects. The tables below contain the aging of these costs on a well and project basis:



Aging based on drilling completion date of individual wells:	Amount		Number of wells
1998-2007	$	410	31
2008-2012	1,076		61
2013-2017	1,875		61
Total	$	3,361	153

Aging based on drilling completion date of last suspended well in project:	Amount		Number of projects
2003-2010	$	338	5
2011-2014	894		10
2015-2018	2,129		15
Total	$	3,361	30

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Note 21

Stock Options and Other Share-Based Compensation

Compensation expense for stock options for 2018, 2017 and 2016 was $105 ($83 after tax), $137 ($89 after tax) and $271 ($176 after tax), respectively. In addition, compensation expense for stock appreciation rights, restricted stock, performance shares and restricted stock units was $60 ($47 after tax), $231 ($150 after tax) and $371 ($241 after tax) for 2018, 2017 and 2016, respectively. No significant stock-based compensation cost was capitalized at December 31, 2018, or December 31, 2017.

Cash received in payment for option exercises under all share-based payment arrangements for 2018, 2017 and 2016 was $1,159, $1,100 and $647, respectively. Actual tax benefits realized for the tax deductions from option exercises were $43, $48 and $21 for 2018, 2017 and 2016, respectively.

Cash paid to settle performance shares, restricted stock units and stock appreciation rights was $157, $187 and $82 for 2018, 2017 and 2016, respectively.

Awards under the Chevron Long-Term Incentive Plan (LTIP) may take the form of, but are not limited to, stock options, restricted stock, restricted stock units, stock appreciation rights, performance shares and nonstock grants. From April 2004 through May 2023, no more than 260 million shares may be issued under the LTIP. For awards issued on or after May 29, 2013, no more than 50 million of those shares may be in a form other than a stock option, stock appreciation right or award requiring full payment for shares by the award recipient. For the major types of awards issued before January 1, 2017, the contractual terms vary between three years for the performance shares and restricted stock units, and 10 years for the stock options and stock appreciation rights. For awards issued after January 1, 2017, contractual terms vary between three years for the performance shares and special restricted stock units, five years for standard restricted stock units and 10 years for the stock options and stock appreciation rights. Forfeitures for performance shares, restricted stock units, and stock appreciation rights are recognized as they occur. Forfeitures for stock options are estimated using historical forfeiture data dating back to 1990.

The fair market values of stock options and stock appreciation rights granted in 2018, 2017 and 2016 were measured on the date of grant using the Black-Scholes option-pricing model, with the following weighted-average assumptions:



	Year ended December 31
	2018			2017			2016
Expected term in years¹	6.5			6.3			6.3
Volatility²	21.2		%	21.7		%	21.7		%
Risk-free interest rate based on zero coupon U.S. treasury note	2.6		%	2.2		%	1.6		%
Dividend yield	3.8		%	4.2		%	4.5		%
Weighted-average fair value per option granted	$	18.18		$	15.31		$	9.53

¹Expected term is based on historical exercise and post-vesting cancellation data.

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

A summary of option activity during 2018 is presented below:



	Shares (Thousands)		Weighted-Average Exercise Price			Averaged Remaining Contractual Term (Years)	Aggregate Intrinsic Value
Outstanding at January 1, 2018	103,765			$	97.40
Granted	4,665			$	125.35
Exercised	(12,991	)		$	88.11
Forfeited	(715	)		$	115.25
Outstanding at December 31, 2018	94,724			$	99.92	5.07		$	1,101
Exercisable at December 31, 2018	81,074			$	99.34	4.60		$	933

The total intrinsic value (i.e., the difference between the exercise price and the market price) of options exercised during 2018, 2017 and 2016 was $506, $407 and $240, respectively. During this period, the company continued its practice of issuing treasury shares upon exercise of these awards.

As of December 31, 2018, there was $53 of total unrecognized before-tax compensation cost related to nonvested share-based compensation arrangements granted under the plan. That cost is expected to be recognized over a weighted-average period of 1.6 years.

At January 1, 2018, the number of LTIP performance shares outstanding was equivalent to 3,090,793 shares. During 2018, 1,491,141 performance shares were granted, 746,450 shares vested with cash proceeds distributed to recipients and 165,754 shares were forfeited. At December 31, 2018, performance shares outstanding were 3,669,730. The fair value of the liability recorded for these instruments was $258, and was measured using the Monte Carlo simulation method.

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

At January 1, 2018, the number of restricted stock units outstanding was equivalent to 1,236,500 shares. During 2018, 819,769 restricted stock units were granted, 222,946 units vested with cash proceeds distributed to recipients and 95,844 units were forfeited. At December 31, 2018, restricted stock units outstanding were 1,737,479. The fair value of the liability recorded for the vested portion of these instruments was $125, valued at the stock price as of December 31, 2018. In addition, outstanding stock appreciation rights that were granted under LTIP totaled approximately 4.2 million equivalent shares as of December 31, 2018. The fair value of the liability recorded for the vested portion of these instruments was $70.

Note 22

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 benefit (OPEB) plans that provide medical and dental benefits, as well as life insurance for some active and qualifying retired employees. The plans are unfunded, and the company and retirees share the costs. For the company's main U.S. medical plan, the increase to the pre-Medicare company contribution for retiree medical coverage is limited to no more than 4 percent each year. Certain life insurance benefits are paid by the company.

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

The funded status of the company’s pension and OPEB plans for 2018 and 2017 follows:



	Pension Benefits
	2018						2017						Other Benefits
	U.S.			Int’l.			U.S.			Int’l.			2018			2017
Change in Benefit Obligation
Benefit obligation at January 1	$	13,580		$	5,540		$	13,271		$	5,169		$	2,788		$	2,549
Service cost	480			141			489			151			42			32
Interest cost	370			206			366			219			94			95
Plan participants' contributions	—			4			—			4			71			78
Plan amendments	—			23			—			1			2			—
Actuarial (gain) loss	(1,051		)	(239		)	1,168			(37		)	(272		)	266
Foreign currency exchange rate changes	—			(227		)	—			374			(9		)	10
Benefits paid	(1,653		)	(432		)	(1,714		)	(310		)	(237		)	(229		)
Divestitures	—			(196		)	—			(31		)	(49		)	(13		)
Benefit obligation at December 31	11,726			4,820			13,580			5,540			2,430			2,788
Change in Plan Assets
Fair value of plan assets at January 1	9,948			4,766			9,550			4,174			—			—
Actual return on plan assets	(566		)	(9		)	1,384			319			—			—
Foreign currency exchange rate changes	—			(221		)	—			358			—			—
Employer contributions	803			232			728			252			166			151
Plan participants' contributions	—			4			—			4			71			78
Benefits paid	(1,653		)	(432		)	(1,714		)	(310		)	(237		)	(229		)
Divestitures	—			(198		)	—			(31		)	—			—
Fair value of plan assets at December 31	8,532			4,142			9,948			4,766			—			—
Funded status at December 31	$	(3,194	)	$	(678	)	$	(3,632	)	$	(774	)	$	(2,430	)	$	(2,788	)

Amounts recognized on the Consolidated Balance Sheet for the company’s pension and OPEB plans at December 31, 2018 and 2017, include:



	Pension Benefits
	2018						2017						Other Benefits
	U.S.			Int’l.			U.S.			Int’l.			2018			2017
Deferred charges and other assets	$	17		$	412		$	21		$	448		$	—		$	—
Accrued liabilities	(180		)	(66		)	(188		)	(100		)	(175		)	(174		)
Noncurrent employee benefit plans	(3,031		)	(1,024		)	(3,465		)	(1,122		)	(2,255		)	(2,614		)
Net amount recognized at December 31	$	(3,194	)	$	(678	)	$	(3,632	)	$	(774	)	$	(2,430	)	$	(2,788	)

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Amounts recognized on a before-tax basis in “Accumulated other comprehensive loss” for the company’s pension and OPEB plans were $4,448 and $5,286 at the end of 2018 and 2017, respectively. These amounts consisted of:



	Pension Benefits
	2018				2017				Other Benefits
	U.S.		Int’l.		U.S.		Int’l.		2018			2017
Net actuarial loss	$	3,694	$	955	$	4,258	$	1,005	$	(56	)	$	207
Prior service (credit) costs	7		104		9		94		(256		)	(287		)
Total recognized at December 31	$	3,701	$	1,059	$	4,267	$	1,099	$	(312	)	$	(80	)

The accumulated benefit obligations for all U.S. and international pension plans were $10,514 and $4,360, respectively, at December 31, 2018, and $12,194 and $5,009, respectively, at December 31, 2017.

Information for U.S. and international pension plans with an accumulated benefit obligation in excess of plan assets at December 31, 2018 and 2017, was:



	Pension Benefits
	2018				2017
	U.S.		Int’l.		U.S.		Int’l.
Projected benefit obligations	$	11,667	$	1,277	$	13,514	$	1,590
Accumulated benefit obligations	10,456		1,062		12,129		1,326
Fair value of plan assets	8,456		198		9,862		413

The components of net periodic benefit cost and amounts recognized in the Consolidated Statement of Comprehensive Income for 2018, 2017 and 2016 are shown in the table below:



	Pension Benefits
	2018						2017						2016						Other Benefits
	U.S.			Int’l.			U.S.			Int’l.			U.S.			Int’l.			2018			2017			2016
Net Periodic Benefit Cost
Service cost	$	480		$	141		$	489		$	151		$	494		$	159		$	42		$	32		$	60
Interest cost	370			206			366			219			377			261			94			95			128
Expected return on plan assets	(636		)	(253		)	(597		)	(239		)	(723		)	(243		)	—			—			—
Amortization of prior service costs (credits)	2			10			(5		)	13			(9		)	14			(28		)	(28		)	14
Recognized actuarial losses	304			29			340			44			335			47			15			(5		)	19
Settlement losses	411			33			436			2			511			6			—			—			—
Curtailment losses (gains)	—			3			—			—			—			—			—			—			—
Total net periodic benefit cost	931			169			1,029			190			985			244			123			94			221
Changes Recognized in Comprehensive Income
Net actuarial (gain) loss during period	151			12			381			(94		)	690			55			(248		)	284			(430		)
Amortization of actuarial loss	(715		)	(62		)	(776		)	(46		)	(846		)	(53		)	(15		)	5			(19		)
Prior service (credits) costs during period	—			23			—			1			—			—			3			—			(345		)
Amortization of prior service (costs) credits	(2		)	(13		)	5			(13		)	9			(14		)	28			28			(14		)
Total changes recognized in other comprehensive income	(566		)	(40		)	(390		)	(152		)	(147		)	(12		)	(232		)	317			(808		)
Recognized in Net Periodic Benefit Cost and Other Comprehensive Income	$	365		$	129		$	639		$	38		$	838		$	232		$	(109	)	$	411		$	(587	)

Net actuarial losses recorded in “Accumulated other comprehensive loss” at December 31, 2018, for the company’s U.S. pension, international pension and OPEB plans are being amortized on a straight-line basis over approximately 10, 12 and 13 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 2019, the company estimates actuarial losses of $239, $19 and $(3) will be amortized from “Accumulated other comprehensive loss” for U.S. pension, international pension and OPEB plans, respectively. In addition, the company estimates an additional $290 will be recognized from “Accumulated other comprehensive loss” during 2019 related to lump-sum settlement costs from the main U.S. pension plans.

The weighted average amortization period for recognizing prior service costs (credits) recorded in “Accumulated other comprehensive loss” at December 31, 2018, was approximately 4 and 8 years for U.S. and international pension plans, respectively, and 8 years for OPEB plans. During 2019, the company estimates prior service (credits) costs of $2, $12 and

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

$(28) will be amortized from “Accumulated other comprehensive loss” for U.S. pension, international pension and OPEB plans, respectively.

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



	Pension Benefits
	2018				2017				2016						Other Benefits
	U.S.		Int’l.		U.S.		Int’l.		U.S.		Int’l.		2018		2017		2016
Assumptions used to determine benefit obligations:
Discount rate	4.2	%	4.4	%	3.5	%	3.9	%	3.9	%	4.3	%	4.4	%	3.8	%	4.3	%
Rate of compensation increase	4.5	%	4.0	%	4.5	%	4.0	%	4.5	%	4.5	%	N/A		N/A		N/A
Assumptions used to determine net periodic benefit cost:
Discount rate for service cost	3.7	%	3.9	%	4.2	%	4.3	%	4.4	%	5.3	%	3.9	%	4.6	%	4.9	%
Discount rate for interest cost	3.0	%	3.9	%	3.0	%	4.3	%	3.0	%	5.3	%	3.5	%	3.8	%	4.0	%
Expected return on plan assets	6.8	%	5.5	%	6.8	%	5.5	%	7.3	%	6.3	%	N/A		N/A		N/A
Rate of compensation increase	4.5	%	4.0	%	4.5	%	4.5	%	4.5	%	4.8	%	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 2018, the company used an expected long-term rate of return of 6.75 percent for U.S. pension plan assets, which account for 67 percent of the company’s pension plan assets. In 2017, the company used a long-term rate of return of 6.75 percent for these plans, and in 2016, 7.25 percent.

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

Discount Rate The discount rate assumptions used to determine the U.S. and international pension and OPEB plan obligations and expense reflect the rate at which benefits could be effectively settled, and are equal to the equivalent single rate resulting from yield curve analysis. This analysis considered the projected benefit payments specific to the company's plans and the yields on high-quality bonds. The projected cash flows were discounted to the valuation date using the yield curve for the main U.S. pension and OPEB plans. The effective discount rates derived from this analysis at the end of 2018 were 4.2 percent for the main U.S. pension plan and 4.3 percent for the main U.S. OPEB plan. The discount rates for these plans at the end of 2017 were 3.5 and 3.6 percent, respectively, while in 2016 they were 3.9 and 4.1 percent for these plans, respectively.

Other Benefit Assumptions Assumed health care cost-trend rates can have a significant effect on the amounts reported for retiree health care costs. For the measurement of accumulated postretirement benefit obligation at December 31, 2018, for the main U.S. OPEB plan, the assumed health care cost-trend rates start with 7.2 percent in 2019 and gradually decline to 4.5 percent for 2025 and beyond. For this measurement at December 31, 2017, the assumed health care cost-trend rates started with 7.4 percent in 2018 and gradually declined to 4.5 percent for 2025 and beyond. A 1-percentage-point change in the assumed health care cost-trend rates would have the following effects on worldwide plans:



	1 Percent Increase		1 Percent Decrease
Effect on total service and interest cost components	$	12	$	(10	)
Effect on postretirement benefit obligation	$	197	$	(156	)

Plan Assets and Investment Strategy

The fair value measurements of the company’s pension plans for 2018 and 2017 are on the following page:

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts



	U.S.											Int’l.
	Total		Level 1			Level 2		Level 3		NAV		Total		Level 1			Level 2		Level 3		NAV
At December 31, 2017
Equities
U.S.¹	$	1,331	$	1,331		$	—	$	—	—		$	652	$	651		$	1	$	—	$	—
International	2,060		2,057			3		—		—		691		691			—		—		—
Collective Trusts/Mutual Funds²	1,089		22			—		—		1,067		204		19			4		—		181
Fixed Income
Government	274		—			274		—		—		296		77			219		—		—
Corporate	1,492		—			1,492		—		—		593		—			563		30		—
Bank Loans	117		—			106		11		—		—		—			—		—		—
Mortgage/Asset Backed	1		—			1		—		—		8		—			8		—		—
Collective Trusts/Mutual Funds²	1,130		—			—		—		1,130		1,481		—			16		—		1,465
Mixed Funds³	—		—			—		—		—		80		1			79		—		—
Real Estate⁴	1,096		—			—		—		1,096		376		—			—		56		320
Alternative Investments⁵	1,022		—			—		—		1,022		—		—			—		—		—
Cash and Cash Equivalents	260		255			5		—		—		366		362			4		—		—
Other⁶	76		(2		)	28		43		7		19		(2		)	18		3		—
Total at December 31, 2017	$	9,948	$	3,663		$	1,909	$	54	4,322		$	4,766	$	1,799		$	912	$	89	$	1,966
At December 31, 2018
Equities
U.S.¹	$	1,110	$	1,110		$	—	$	—	$	—	$	520	$	520		$	—	$	—	$	—
International	1,631		1,630			1		—		—		521		520			—		1		—
Collective Trusts/Mutual Funds²	893		21			—		—		872		152		9			—		—		143
Fixed Income
Government	225		—			225		—		—		254		97			157		—		—
Corporate	1,382		—			1,382		—		—		409		—			389		20		—
Bank Loans	119		—			114		5		—		—		—			—		—		—
Mortgage/Asset Backed	1		—			1		—		—		6		—			6		—		—
Collective Trusts/Mutual Funds²	877		—			—		—		877		1,521		15			—		—		1,506
Mixed Funds³	—		—			—		—		—		74		3			71		—		—
Real Estate⁴	1,065		—			—		—		1,065		378		—			—		56		322
Alternative Investments⁵	941		—			—		—		941		—		—			—		—		—
Cash and Cash Equivalents	212		208			4		—		—		287		277			2		—		8
Other⁶	76		(4		)	31		44		5		20		—			17		3		—
Total at December 31, 2018	$	8,532	$	2,965		$	1,758	$	49	$	3,760	$	4,142	$	1,441		$	642	$	80	$	1,979


¹	U.S. equities include investments in the company’s common stock in the amount of $9 at December 31, 2018, and $12 at December 31, 2017.


²	Collective Trusts/Mutual Funds for U.S. plans are entirely index funds; for International plans, they are mostly unit trust and index funds.


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 third-party appraisals that occur at least once a year for each property in the portfolio.


⁵	Alternative investments focus on market-neutral strategies that have a low expected correlation to traditional asset classes.


⁶	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 (Level 3); and investments in private-equity limited partnerships (NAV).

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



	Equity			Fixed Income
	International			Corporate			Bank Loans			Real Estate			Other		Total
Total at December 31, 2016	$	—		$	19		$	11		$	60		$	44	$	134
Actual Return on Plan Assets:
Assets held at the reporting date	—			1			—			1			—		2
Assets sold during the period	—			—			—			—			—		—
Purchases, Sales and Settlements	—			10			3			(5		)	2		10
Transfers in and/or out of Level 3	—			—			(3		)	—			—		(3		)
Total at December 31, 2017	$	—		$	30		$	11		$	56		$	46	$	143
Actual Return on Plan Assets:
Assets held at the reporting date	4			(2		)	—			13			—		15
Assets sold during the period	(4		)	—			—			—			—		(4		)
Purchases, Sales and Settlements	—			(7		)	(4		)	(13		)	—		(24		)
Transfers in and/or out of Level 3	1			—			(2		)	—			—		(1		)
Total at December 31, 2018	$	1		$	21		$	5		$	56		$	46	$	129

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

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

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

For the primary U.S. pension plan, the company's Investment Committee has established the following approved asset allocation ranges: Equities 30–60 percent, Fixed Income and Cash 20–65 percent, Real Estate 0–15 percent, and Alternative Investments 0–15 percent. For the U.K. pension plan, the U.K. Board of Trustees has established the following asset allocation guidelines: Equities 25–45 percent, Fixed Income and Cash 40–75 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 factors, including market conditions and illiquidity constraints. 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 2018, the company contributed $803 and $232 to its U.S. and international pension plans, respectively. In 2019, the company expects contributions to be approximately $700 to its U.S. plans and $200 to its international pension plans. Actual contribution amounts are dependent upon investment returns, changes in pension obligations, regulatory environments, tax law changes and other economic factors. Additional funding may ultimately be required if investment returns are insufficient to offset increases in plan obligations.

The company anticipates paying OPEB benefits of approximately $175 in 2019; $166 was paid in 2018.

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



	Pension Benefits				Other
	U.S.		Int’l.		Benefits
2019	$	1,310	$	271	$	175
2020	$	1,240	$	266	$	172
2021	$	1,170	$	577	$	171
2022	$	1,145	$	228	$	168
2023	$	1,118	$	234	$	166
2024-2028	$	4,972	$	1,392	$	795

Employee Savings Investment Plan Eligible employees of Chevron and certain of its subsidiaries participate in the Chevron Employee Savings Investment Plan (ESIP). Compensation expense for the ESIP totaled $270, $316 and $281 in 2018, 2017 and 2016, respectively.

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 2018, 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, 2018 and 2017, trust assets of $34 and $35, 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 $1,048, $936 and $662 in 2018, 2017 and 2016, 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 21, beginning on page 80.

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Note 23

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 16, beginning on page 74, for a discussion of the periods for which tax returns have been audited for the company’s major tax jurisdictions and a discussion for all tax jurisdictions of the differences between the amount of tax benefits recognized in the financial statements and the amount taken or expected to be taken in a tax return.

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

Guarantees The company has two guarantees to equity affiliates totaling $968. Of this amount, $637 is associated with a financing arrangement with an equity affiliate. Over the approximate 3-year remaining term of this guarantee, the maximum amount will be reduced as payments are made by the affiliate. The remaining amount of $331 is associated with certain payments under a terminal use agreement entered into by an equity affiliate. Over the approximate 9-year remaining term of this 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 either guarantee.

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

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

Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements The company and its subsidiaries have certain contingent liabilities with respect to long-term unconditional purchase obligations and commitments, including throughput and take-or-pay agreements, some of which relate to suppliers’ financing arrangements. The agreements typically provide goods and services, such as pipeline and storage capacity, drill ships, 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: 2019 – $1,300; 2020 – $1,200; 2021 – $1,300; 2022 – $1,000; 2023 – $800; 2023 and after – $4,700. A portion of these commitments may ultimately be shared with project partners. Total payments under the agreements were approximately $1,400 in 2018, $1,300 in 2017 and $1,300 in 2016.

As part of the implementation of ASU 2016-02 (Topic 842) effective January 1, 2019, the company will reclassify some contracts, currently incorporated into the unconditional purchase obligations disclosure, as operating leases in first quarter 2019 results.

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

Although the company has provided for known environmental obligations that are probable and reasonably estimable, it is likely that the company will continue to incur additional liabilities. The amount of additional future costs are not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties. These future costs may be material to results of

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

operations in the period in which they are recognized, but the company does not expect these costs will have a material effect on its consolidated financial position or liquidity.

Chevron’s environmental reserve as of December 31, 2018, was $1,327. Included in this balance was $258 related to remediation activities at approximately 144 sites for which the company had been identified as a potentially responsible party under the provisions of the federal Superfund law or analogous state laws which provide for joint and several liability for all responsible parties. Any future actions by regulatory agencies to require Chevron to assume other potentially responsible parties’ costs at designated hazardous waste sites are not expected to have a material effect on the company’s results of operations, consolidated financial position or liquidity.

Of the remaining year-end 2018 environmental reserves balance of $1,069, $748 is related to the company’s U.S. downstream operations, $24 to its international downstream operations, $296 to upstream operations and $1 to other businesses. Liabilities at all sites were primarily associated with the company’s plans and activities to remediate soil or groundwater contamination or both.

The company manages environmental liabilities under specific sets of regulatory requirements, which in the United States include the Resource Conservation and Recovery Act and various state and local regulations. No single remediation site at year-end 2018 had a recorded liability that was material to the company’s results of operations, consolidated financial position or liquidity.

Refer to Note 24 on page 88 for a discussion of the company’s asset retirement obligations.

Other Contingencies Governmental and other entities in California and other jurisdictions have filed legal proceedings against fossil fuel producing companies, including Chevron, purporting to seek legal and equitable relief to address alleged impacts of climate change. Further such proceedings are likely to be filed by other parties. The unprecedented legal theories set forth in these proceedings entail the possibility of damages liability and injunctions against the production of all fossil fuels that, while we believe remote, could have a material adverse effect on the company’s results of operations and financial condition. Management believes that these proceedings are legally and factually meritless and detract from constructive efforts to address the important policy issues presented by climate change, and will vigorously defend against such proceedings.

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

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

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

Note 24

Asset Retirement Obligations

The company records the fair value of a liability for an asset retirement obligation (ARO) both as an asset and a 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 2018, 2017 and 2016:



	2018			2017			2016
Balance at January 1	$	14,214		$	14,243		$	15,642
Liabilities incurred	96			684			204
Liabilities settled	(830		)	(1,721		)	(1,658		)
Accretion expense	654			668			749
Revisions in estimated cash flows	(84		)	340			(694		)
Balance at December 31	$	14,050		$	14,214		$	14,243

In the table above, the amount associated with "Revisions in estimated cash flows" in 2018 reflects decreased cost estimates to abandon wells, equipment and facilities. The long-term portion of the $14,050 balance at the end of 2018 was $12,957.

Note 25

Revenue

On January 1, 2018, Chevron adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and its related amendments using the modified retrospective transition method, which did not require the restatement of prior periods. The adoption did not result in a material change in the company’s accounting or have a material effect on the company’s financial position, including the measurement of revenue, the timing of revenue recognition and the recognition of contract assets, liabilities and related costs.

The most significant change is the presentation of excise, value-added and similar taxes collected on behalf of third parties, which are no longer presented within “Sales and other operating revenue” on the Consolidated Statement of Income starting in 2018. These taxes, which totaled $7,861 in 2018, are now netted in “Taxes other than on income” on the Consolidated Statement of Income. This change to presentation had no impact on earnings. These taxes totaled $7,189 and $6,905 in 2017 and 2016, respectively.

The company applied the optional exemption to not report any unfulfilled performance obligations related to contracts that have terms of less than one year. The amount of future revenue for unfulfilled performance obligations under long-term contracts with fixed components was insignificant for the year ended December 31, 2018.

Revenue from contracts with customers is presented in “Sales and other operating revenue” along with some activity that is accounted for outside the scope of ASC 606, which is not material to this line, on the Consolidated Statement of Income. 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. Refer to Note 13 beginning on page 66 for additional information on the company’s segmentation of revenue.

Receivables related to revenue from contracts with customers are included in “Accounts and notes receivable, net” on the Consolidated Balance Sheet, net of the allowance for doubtful accounts. The net balance of these receivables was $9,779 and $10,046 at January 1, 2018 and December 31, 2018, respectively. Other items included in “Accounts and notes receivable, net” represent amounts due from partners for their share of joint venture operating and project costs and amounts due from

Notes to the Consolidated Financial Statements

Millions of dollars, except per-share amounts

others, primarily related to derivatives, leases, buy/sell arrangements and product exchanges, which are accounted for outside the scope of ASC 606.

Contract assets and related costs are reflected in “Prepaid expenses and other current assets” and contract liabilities are reflected in “Accrued liabilities” and “Deferred credits and other noncurrent obligations” on the Consolidated Balance Sheet. Amounts for these items are not material to the company’s financial position.

Note 26

Other Financial Information

Earnings in 2018 included after-tax gains of approximately $630 relating to the sale of certain properties. Of this amount, approximately $365 and $265 related to downstream and upstream, respectively. Earnings in 2017 included after-tax gains of approximately $1,800 relating to the sale of certain properties, of which approximately $850 and $950 related to downstream and upstream assets, respectively. Earnings in 2018 included after-tax charges of approximately $2,000 for impairments and other asset write-offs related to upstream. Earnings in 2017 included after-tax charges of approximately $900 for impairments and other asset write-offs related to upstream.



Other financial information is as follows:
	Year ended December 31
	2018		2017			2016
Total financing interest and debt costs	$	921	$	902		$	753
Less: Capitalized interest	173		595			552
Interest and debt expense	$	748	$	307		$	201
Research and development expenses	$	453	$	433		$	476
Excess of replacement cost over the carrying value of inventories (LIFO method)	$	5,134	$	3,937		$	2,942
LIFO profits (losses) on inventory drawdowns included in earnings	$	26	$	(5	)	$	(88	)
Foreign currency effects^*	$	611	$	(446	)	$	58

^*Includes $416, $(45) and $1 in 2018, 2017 and 2016, respectively, for the company’s share of equity affiliates’ foreign currency effects.

The company has $4,518 in goodwill on the Consolidated Balance Sheet, all of which is in the upstream segment and primarily related to the 2005 acquisition of Unocal. The company tested this goodwill for impairment during 2018, and no impairment was required.

Five-Year Financial Summary

Unaudited





Millions of dollars, except per-share amounts	2018		2017			2016			2015		2014
Statement of Income Data
Revenues and Other Income
Total sales and other operating revenues^*	$	158,902	$	134,674		$	110,215		$	129,925	$	200,494
Income from equity affiliates and other income	7,437		7,048			4,257			8,552		11,476
Total Revenues and Other Income	166,339		141,722			114,472			138,477		211,970
Total Costs and Other Deductions	145,764		132,501			116,632			133,635		180,768
Income Before Income Tax Expense (Benefit)	20,575		9,221			(2,160		)	4,842		31,202
Income Tax Expense (Benefit)	5,715		(48		)	(1,729		)	132		11,892
Net Income	14,860		9,269			(431		)	4,710		19,310
Less: Net income attributable to noncontrolling interests	36		74			66			123		69
Net Income (Loss) Attributable to Chevron Corporation	$	14,824	$	9,195		$	(497	)	$	4,587	$	19,241
Per Share of Common Stock
Net Income (Loss) Attributable to Chevron
– Basic	$	7.81	$	4.88		$	(0.27	)	$	2.46	$	10.21
– Diluted	$	7.74	$	4.85		$	(0.27	)	$	2.45	$	10.14
Cash Dividends Per Share	$	4.48	$	4.32		$	4.29		$	4.28	$	4.21
Balance Sheet Data (at December 31)
Current assets	$	34,021	$	28,560		$	29,619		$	34,430	$	41,161
Noncurrent assets	219,842		225,246			230,459			230,110		223,723
Total Assets	253,863		253,806			260,078			264,540		264,884
Short-term debt	5,726		5,192			10,840			4,927		3,790
Other current liabilities	21,445		22,545			20,945			20,540		27,322
Long-term debt	28,733		33,571			35,286			33,622		23,994
Other noncurrent liabilities	42,317		43,179			46,285			51,565		53,587
Total Liabilities	98,221		104,487			113,356			110,654		108,693
Total Chevron Corporation Stockholders' Equity	$	154,554	$	148,124		$	145,556		$	152,716	$	155,028
Noncontrolling interests	1,088		1,195			1,166			1,170		1,163
Total Equity	$	155,642	$	149,319		$	146,722		$	153,886	$	156,191

^*Includes excise, value-added and similar taxes:	$	—	$	7,189		$	6,905		$	7,359	$	8,186

Supplemental Information on Oil and Gas Producing Activities - Unaudited

In accordance with FASB and SEC disclosure requirements for oil and gas producing activities, this section provides supplemental information on oil and gas exploration and producing activities of the company in seven separate tables. Tables I through IV provide historical cost information pertaining to costs incurred in exploration, property acquisitions and

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



	Consolidated Companies														Affiliated Companies
			Other						Australia/
Millions of dollars	U.S.		Americas		Africa		Asia		Oceania		Europe		Total		TCO		Other
Year Ended December 31, 2018
Exploration
Wells	$	508	$	74	$	25	$	55	$	—	$	14	$	676	$	—	$	—
Geological and geophysical	84		41		4		5		7		1		142		—		—
Rentals and other	190		46		35		33		49		23		376		—		—
Total exploration	782		161		64		93		56		38		1,194		—		—
Property acquisitions²
Proved	160		—		7		117		—		—		284		—		—
Unproved	52		494		2		27		—		—		575		—		—
Total property acquisitions	212		494		9		144		—		—		859		—		—
Development³	6,245		856		711		1,095		845		278		10,030		4,883		200
Total Costs Incurred⁴	$	7,239	$	1,511	$	784	$	1,332	$	901	$	316	$	12,083	$	4,883	$	200
Year Ended December 31, 2017
Exploration
Wells	$	479	$	3	$	1	$	36	$	—	$	15	$	534	$	—	$	—
Geological and geophysical	93		46		4		3		33		5		184		—		—
Rentals and other	157		32		52		60		46		128		475		—		—
Total exploration	729		81		57		99		79		148		1,193		—		—
Property acquisitions²
Proved	64		—		—		93		—		—		157		—		—
Unproved	77		—		40		18		1		—		136		—		—
Total property acquisitions	141		—		40		111		1		—		293		—		—
Development³	4,346		944		1,136		1,324		2,580		121		10,451		3,596		147
Total Costs Incurred⁴	$	5,216	$	1,025	$	1,233	$	1,534	$	2,660	$	269	$	11,937	$	3,596	$	147
Year Ended December 31, 2016
Exploration
Wells	$	707	$	51	$	95	$	31	$	1	$	1	$	886	$	—	$	—
Geological and geophysical	67		3		22		31		16		4		143		—		—
Rentals and other	139		40		70		57		54		32		392		—		—
Total exploration	913		94		187		119		71		37		1,421		—		—
Property acquisitions²
Proved	16		—		—		52		—		—		68		—		—
Unproved	27		—		—		—		—		—		27		—		—
Total property acquisitions	43		—		—		52		—		—		95		—		—
Development³	3,814		1,631		2,014		1,866		3,733		550		13,608		2,211		262
Total Costs Incurred⁴	$	4,770	$	1,725	$	2,201	$	2,037	$	3,804	$	587	$	15,124	$	2,211	$	262



¹	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 88.
²	Does not include properties acquired in nonmonetary transactions.
³	Includes $114, $84 and $481 costs incurred on major capital projects prior to assignment of proved reserves for consolidated companies in 2018, 2017, and 2016, respectively.
⁴	Reconciliation of consolidated and affiliated companies total cost incurred to Upstream capital and exploratory (C&E) expenditures - $ billions:
		2018			2017			2016
	Total cost incurred	$	17.2		$	15.7		$	17.6
	Non-oil and gas activities	0.6			1.3			2.5		(Primarily; LNG and transportation activities.)
	ARO	(0.1		)	(0.6		)	—
	Upstream C&E	$	17.7		$	16.4		$	20.1	Reference page 39 Upstream total

Supplemental Information on Oil and Gas Producing Activities - Unaudited

development; capitalized costs; and results of operations. Tables V through VII present information on the company’s estimated net proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves and changes in estimated discounted future net cash flows. The amounts for consolidated companies are organized by geographic areas including the United States, Other Americas, Africa, Asia, Australia/Oceania and Europe. Amounts for affiliated companies include Chevron’s equity interests in Tengizchevroil (TCO) in the Republic of Kazakhstan and in other affiliates, principally in Venezuela and Angola. Refer to Note 14, beginning on page 69, for a discussion of the company’s major equity affiliates.

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



	Consolidated Companies														Affiliated Companies
			Other						Australia/
Millions of dollars	U.S.		Americas		Africa		Asia		Oceania		Europe		Total		TCO		Other
At December 31, 2018
Unproved properties	$	4,687	$	2,463	$	201	$	1,299	$	1,986	$	—	$	10,636	$	108	$	—
Proved properties and related producing assets	75,013		21,796		44,876		57,168		22,047		12,634		233,534		9,892		4,336
Support equipment	2,216		317		1,096		2,149		17,712		124		23,614		1,858		—
Deferred exploratory wells	782		160		405		632		1,323		261		3,563		—		—
Other uncompleted projects	4,730		3,704		1,744		1,292		1,462		300		13,232		11,906		605
Gross Capitalized Costs	87,428		28,440		48,322		62,540		44,530		13,319		284,579		23,764		4,941
Unproved properties valuation	820		694		164		623		107		—		2,408		61		—
Proved producing properties – Depreciation and depletion	45,712		12,984		31,102		43,735		4,631		10,014		148,178		5,289		1,730
Support equipment depreciation	1,466		220		738		1,674		1,531		119		5,748		947		—
Accumulated provisions	47,998		13,898		32,004		46,032		6,269		10,133		156,334		6,297		1,730
Net Capitalized Costs	$	39,430	$	14,542	$	16,318	$	16,508	$	38,261	$	3,186	$	128,245	$	17,467	$	3,211
At December 31, 2017
Unproved properties	$	6,466	$	2,314	$	240	$	1,420	$	1,986	$	23	$	12,449	$	108	$	—
Proved properties and related producing assets	66,390		20,696		43,656		55,616		21,544		10,697		218,599		8,956		4,346
Support equipment	2,248		337		1,104		2,050		15,599		132		21,470		1,731		—
Deferred exploratory wells	969		181		406		562		1,323		261		3,702		—		—
Other uncompleted projects	8,333		3,624		2,528		1,889		3,238		1,966		21,578		8,098		457
Gross Capitalized Costs	84,406		27,152		47,934		61,537		43,690		13,079		277,798		18,893		4,803
Unproved properties valuation	977		855		162		535		107		23		2,659		58		—
Proved producing properties – Depreciation and depletion	43,286		11,795		27,916		40,234		3,193		9,306		135,730		4,690		1,468
Support equipment depreciation	1,359		227		712		1,584		870		123		4,875		846		—
Accumulated provisions	45,622		12,877		28,790		42,353		4,170		9,452		143,264		5,594		1,468
Net Capitalized Costs	$	38,784	$	14,275	$	19,144	$	19,184	$	39,520	$	3,627	$	134,534	$	13,299	$	3,335
At December 31, 2016
Unproved properties	$	9,052	$	3,063	$	263	$	1,273	$	1,986	$	23	$	15,660	$	108	$	—
Proved properties and related producing assets	69,924		18,269		38,903		56,070		11,642		10,738		205,546		8,484		3,898
Support equipment	2,249		357		1,083		2,036		8,598		131		14,454		1,632		—
Deferred exploratory wells	750		190		415		602		1,322		261		3,540		—		—
Other uncompleted projects	7,018		5,900		6,152		2,743		17,559		1,804		41,176		5,075		517
Gross Capitalized Costs	88,993		27,779		46,816		62,724		41,107		12,957		280,376		15,299		4,415
Unproved properties valuation	1,673		903		222		483		107		23		3,411		55		—
Proved producing properties – Depreciation and depletion	45,820		11,635		24,463		38,757		2,300		8,643		131,618		4,148		1,170
Support equipment depreciation	1,165		226		657		1,502		571		118		4,239		750		—
Accumulated provisions	48,658		12,764		25,342		40,742		2,978		8,784		139,268		4,953		1,170
Net Capitalized Costs	$	40,335	$	15,015	$	21,474	$	21,982	$	38,129	$	4,173	$	141,108	$	10,346	$	3,245

Supplemental Information on Oil and Gas Producing Activities - Unaudited

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

The company’s results of operations from oil and gas producing activities for the years 2018, 2017 and 2016 are shown in the following table. Net income (loss) from exploration and production activities as reported on page 67 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 67.



	Consolidated Companies																					Affiliated Companies
				Other									Australia/
Millions of dollars	U.S.			Americas			Africa			Asia			Oceania			Europe			Total			TCO			Other
Year Ended December 31, 2018
Revenues from net production
Sales	$	2,162		$	1,008		$	829		$	5,880		$	4,229		$	619		$	14,727		$	5,987		$	1,369
Transfers	11,645			1,808			7,829			3,206			3,413			1,071			28,972			—			—
Total	13,807			2,816			8,658			9,086			7,642			1,690			43,699			5,987			1,369
Production expenses excluding taxes	(3,203		)	(1,009		)	(1,564		)	(2,653		)	(557		)	(424		)	(9,410		)	(447		)	(295		)
Taxes other than on income	(540		)	(70		)	(112		)	(22		)	(250		)	(2		)	(996		)	160			(210		)
Proved producing properties:
Depreciation and depletion	(4,583		)	(998		)	(3,368		)	(3,714		)	(2,103		)	(411		)	(15,177		)	(703		)	(306		)
Accretion expense²	(186		)	(26		)	(149		)	(146		)	(50		)	(52		)	(609		)	(4		)	(3		)
Exploration expenses	(777		)	(191		)	(52		)	(58		)	(56		)	(41		)	(1,175		)	—			(6		)
Unproved properties valuation	(516		)	(42		)	(3		)	(135		)	—			—			(696		)	—			—
Other income (expense)³	336			4			97			(33		)	31			(161		)	274			(59		)	(280		)
Results before income taxes	4,338			484			3,507			2,325			4,657			599			15,910			4,934			269
Income tax (expense) benefit	(886		)	(400		)	(2,131		)	(1,088		)	(1,415		)	(233		)	(6,153		)	(1,480		)	341
Results of Producing Operations	$	3,452		$	84		$	1,376		$	1,237		$	3,242		$	366		$	9,757		$	3,454		$	610
Year Ended December 31, 2017
Revenues from net production
Sales	$	1,548		$	999		$	487		$	5,381		$	2,061		$	372		$	10,848		$	4,509		$	1,218
Transfers	7,610			1,371			6,533			2,966			937			1,246			20,663			—			—
Total	9,158			2,370			7,020			8,347			2,998			1,618			31,511			4,509			1,218
Production expenses excluding taxes	(3,160		)	(1,021		)	(1,521		)	(2,670		)	(304		)	(415		)	(9,091		)	(425		)	(306		)
Taxes other than on income	(403		)	(85		)	(115		)	(11		)	(183		)	(3		)	(800		)	118			(121		)
Proved producing properties:
Depreciation and depletion	(5,092		)	(1,046		)	(3,531		)	(4,134		)	(1,176		)	(668		)	(15,647		)	(638		)	(365		)
Accretion expense²	(212		)	(23		)	(144		)	(155		)	(40		)	(60		)	(634		)	(3		)	(16		)
Exploration expenses	(299		)	(126		)	(65		)	(108		)	(85		)	(149		)	(832		)	—			—
Unproved properties valuation	(204		)	(259		)	(3		)	(52		)	—			—			(518		)	—			—
Other income (expense)³	580			(87		)	259			273			170			(170		)	1,025			(104		)	(14		)
Results before income taxes	368			(277		)	1,900			1,490			1,380			153			5,014			3,457			396
Income tax (expense) benefit	(88		)	(64		)	(1,199		)	(616		)	(413		)	(174		)	(2,554		)	(1,037		)	20
Results of Producing Operations	$	280		$	(341	)	$	701		$	874		$	967		$	(21	)	$	2,460		$	2,420		$	416


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 24, “Asset Retirement Obligations,” on page 88.


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

Supplemental Information on Oil and Gas Producing Activities - Unaudited

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



	Consolidated Companies																					Affiliated Companies
				Other									Australia/
Millions of dollars	U.S.			Americas			Africa			Asia			Oceania			Europe			Total			TCO			Other
Year Ended December 31, 2016
Revenues from net production
Sales	$	1,178		$	1,038		$	238		$	5,347		$	733		$	436		$	8,970		$	3,416		$	695
Transfers	5,895			1,134			4,896			2,839			478			727			15,969			—			—
Total	7,073			2,172			5,134			8,186			1,211			1,163			24,939			3,416			695
Production expenses excluding taxes	(3,634		)	(1,120		)	(1,806		)	(2,942		)	(250		)	(389		)	(10,141		)	(451		)	(359		)
Taxes other than on income	(341		)	(90		)	(104		)	(10		)	(154		)	(2		)	(701		)	(494		)	(67		)
Proved producing properties:
Depreciation and depletion	(5,913		)	(2,729		)	(2,612		)	(3,848		)	(425		)	(483		)	(16,010		)	(524		)	(196		)
Accretion expense²	(265		)	(26		)	(134		)	(181		)	(30		)	(66		)	(702		)	(3		)	(12		)
Exploration expenses	(399		)	(132		)	(255		)	(109		)	(70		)	(38		)	(1,003		)	—			—
Unproved properties valuation	(342		)	(31		)	(13		)	(44		)	—			—			(430		)	—			—
Other income (expense)³	681			(103		)	(141		)	(39		)	4			431			833			(113		)	(206		)
Results before income taxes	(3,140		)	(2,059		)	69			1,013			286			616			(3,215		)	1,831			(145		)
Income tax (expense) benefit	1,080			139			(267		)	(386		)	(94		)	(57		)	415			(549		)	39
Results of Producing Operations	$	(2,060	)	$	(1,920	)	$	(198	)	$	627		$	192		$	559		$	(2,800	)	$	1,282		$	(106	)


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 24, “Asset Retirement Obligations,” on page 88.


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

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



	Consolidated Companies														Affiliated Companies
			Other						Australia/
	U.S.		Americas		Africa		Asia		Oceania		Europe		Total		TCO		Other
Year Ended December 31, 2018
Average sales prices
Liquids, per barrel	$	58.17	$	58.27	$	69.75	$	63.55	$	68.78	$	66.31	$	62.45	$	56.20	$	56.41
Natural gas, per thousand cubic feet	1.86		2.62		2.55		4.48		8.78		7.54		5.54		0.77		3.19
Average production costs, per barrel²	11.18		17.32		11.29		12.15		3.95		14.21		10.78		3.59		9.29
Year Ended December 31, 2017
Average sales prices
Liquids, per barrel	$	44.53	$	51.26	$	52.12	$	48.45	$	52.32	$	51.15	$	48.61	$	41.47	$	48.68
Natural gas, per thousand cubic feet	2.11		3.15		1.77		4.12		5.75		5.55		4.07		0.88		2.38
Average production costs, per barrel²	12.83		18.64		10.88		11.30		3.60		11.95		11.41		3.34		8.51
Year Ended December 31, 2016
Average sales prices
Liquids, per barrel	$	35.00	$	43.89	$	41.42	$	37.55	$	45.32	$	39.64	$	38.30	$	31.83	$	31.90
Natural gas, per thousand cubic feet	1.58		3.04		1.60		4.19		4.29		4.77		3.45		1.34		2.24
Average production costs, per barrel²	14.56		18.79		13.80		11.34		5.97		12.84		13.15		3.67		15.01


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.

Supplemental Information on Oil and Gas Producing Activities - Unaudited

Table V Reserve Quantity Information

Summary of Net Oil and Gas Reserves



	2018			2017			2016
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.	1,240	—	2,396	1,031	—	2,096	992	—	2,102
Other Americas	159	545	393	101	543	398	92	601	533
Africa	628	—	1,316	664	—	1,276	640	—	1,039
Asia	470	—	4,021	529	—	4,463	621	—	4,962
Australia/Oceania	132	—	10,084	126	—	9,907	124	—	9,176
Europe	84	—	205	83	—	215	77	—	213
Total Consolidated	2,713	545	18,415	2,534	543	18,355	2,546	601	18,025
Affiliated Companies
TCO	700	—	1,179	787	—	1,300	920	—	1,402
Other	76	55	308	84	66	270	92	62	319
Total Consolidated and Affiliated Companies	3,489	600	19,902	3,405	609	19,925	3,558	663	19,746
Proved Undeveloped
Consolidated Companies
U.S.	1,162	—	4,313	885	—	3,084	420	—	1,574
Other Americas	204	—	470	196	—	397	131	3	114
Africa	148	—	1,499	175	—	1,630	236	—	1,788
Asia	109	—	289	102	—	310	99	—	571
Australia/Oceania	29	—	3,647	33	—	3,652	34	—	3,339
Europe	65	—	100	62	—	86	61	—	21
Total Consolidated	1,717	—	10,318	1,453	—	9,159	981	3	7,407
Affiliated Companies
TCO	905	—	755	962	—	883	989	—	840
Other	7	72	601	20	93	769	26	108	767
Total Consolidated and Affiliated Companies	2,629	72	11,674	2,435	93	10,811	1,996	111	9,014
Total Proved Reserves	6,118	672	31,576	5,840	702	30,736	5,554	774	28,760

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 company 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 reserves: 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. Proved undeveloped reserves are the quantities expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

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 Global Reserves, an organization that is separate from the Upstream operating organization. The Manager of Global Reserves has more than 30 years’ experience working in the oil and gas industry and holds both undergraduate and

Supplemental Information on Oil and Gas Producing Activities - Unaudited

graduate degrees in geoscience. His experience includes various technical and management roles in providing reserve and resource estimates in support of major capital and exploration projects, and more than 10 years of overseeing oil and gas reserves processes. He has been named a Distinguished Lecturer by the American Association of Petroleum Geologists and is an active member of the American Association of Petroleum Geologists, the SEPM Society of Sedimentary Geologists and the Society of Petroleum Engineers.

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

The RAC has the following primary responsibilities: establish the policies and processes used within the operating units to estimate reserves; provide independent reviews and oversight of the business units’ recommended reserves estimates and changes; confirm that proved reserves are recognized in accordance with SEC guidelines; determine that reserve volumes are calculated using consistent and appropriate standards, procedures and technology; and maintain the Chevron Corporation 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 senior leadership team including 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 Chevron Corporation Reserves Manual.

Technologies Used in Establishing Proved Reserves Additions In 2018, additions to Chevron’s proved reserves were based on a wide range of geologic and engineering technologies. Information generated from wells, such as well logs, wire line sampling, production and pressure testing, fluid analysis, and core analysis, was integrated with seismic data, regional geologic studies, and information from analogous reservoirs to provide “reasonably certain” proved reserves estimates. Both proprietary and commercially available analytic tools, including reservoir simulation, geologic modeling and seismic processing, have been used in the interpretation of the subsurface data. These technologies have been utilized extensively by the company in the past, and the company believes that they provide a high degree of confidence in establishing reliable and consistent reserves estimates.

Proved Undeveloped Reserves At the end of 2018, proved undeveloped reserves totaled 4.6 billion barrels of oil-equivalent (BOE), an increase of 317 million BOE from year-end 2017. The increase was due to 717 million BOE in extensions and discoveries, 69 million BOE in acquisitions, 58 million BOE in revisions and 6 million BOE in improved recovery, partially offset by the transfer of 531 million BOE to proved developed and 2 million BOE in sales. A major portion of this reserve increase is attributed to the company's activities in the Midland and Delaware basins.

During 2018, investments totaling approximately $10 billion in oil and gas producing activities and about $0.1 billion in non-oil and gas producing activities were expended to advance the development of proved undeveloped reserves. In Asia, expenditures during the year totaled approximately $4.8 billion, primarily related to development projects of the TCO affiliate in Kazakhstan. The United States accounted for about $3.4 billion related primarily to various development activities in the Gulf of Mexico and the Midland and Delaware basins. In Africa, about $0.7 billion was expended on various offshore development and natural gas projects in Nigeria, Angola and Republic of Congo. Development activities in Canada and Argentina were primarily responsible for about $0.9 billion of expenditures in Other Americas.

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

At year-end 2018, the company held approximately 2.1 billion BOE of proved undeveloped reserves that have remained undeveloped for five years or more. The majority of these reserves are in three locations where the company has a proven track record of developing major projects. In Australia, approximately 600 million BOE have remained undeveloped for five years or more related to the Gorgon and Wheatstone projects. The company completed construction of liquefaction and other facilities to develop this natural gas. Further field development to convert the remaining proved undeveloped reserves is scheduled to

Supplemental Information on Oil and Gas Producing Activities - Unaudited

occur in line with operating constraints and infrastructure optimization. In Africa, approximately 300 million BOE have remained undeveloped for five years or more, primarily due to facility constraints at various fields and infrastructure associated with the Escravos gas projects in Nigeria. Affiliates account for about 1.2 billion BOE of proved undeveloped reserves with about 900 million BOE that have remained undeveloped for five years or more, with the majority related to the TCO affiliate in Kazakhstan. At TCO, further field development to convert the remaining proved undeveloped reserves is scheduled to occur in line with reservoir depletion and facility constraints.

Annually, the company assesses whether any changes have occurred in facts or circumstances, such as changes to development plans, regulations or government policies, that would warrant a revision to reserve estimates. In 2018, increases in commodity prices positively impacted the economic limits of oil and gas properties, resulting in proved reserve increases, and negatively impacted proved reserves due to entitlement effects. The year-end reserves volumes have been updated for these circumstances and significant changes have been discussed in the appropriate reserves sections. For 2018, 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 32 percent and 38 percent.

Proved Reserve Quantities For the three years ending December 31, 2018, the pattern of net reserve changes shown in the following tables are not necessarily indicative of future trends. Apart from acquisitions, the company’s ability to add proved reserves can be affected by events and circumstances that are outside the company’s control, such as delays in government permitting, partner approvals of development plans, changes in oil and gas prices, OPEC constraints, geopolitical uncertainties, and civil unrest.

At December 31, 2018, proved reserves for the company were 12.1 billion BOE. The company’s estimated net proved reserves of liquids including crude oil, condensate, natural gas liquids and synthetic oil for the years 2016, 2017 and 2018 are shown in the table on page 98. The company’s estimated net proved reserves of natural gas are shown on page 99.

Noteworthy changes in liquids proved reserves for 2016 through 2018 are discussed below and shown in the table on the following page:

Revisions In 2016, improved field performance at various Gulf of Mexico fields, including Jack/St Malo, and in the San Joaquin Valley were primarily responsible for the 109 million barrel increase in the United States. Entitlement effects were mainly responsible for the 64 million barrel increase in the TCO affiliate in Kazakhstan. In Asia, entitlement effects, drilling and improved performance across numerous assets resulted in the 50 million barrel increase.

In 2017, improved field performance at various Gulf of Mexico fields, including Jack/St Malo and Tahiti, and in the Midland and Delaware basins were primarily responsible for the 280 million barrel increase in the United States. Improved field performance at various fields, including Agbami and Sonam in Nigeria, were responsible for the 79 million barrel increase in Africa. Synthetic oil reserves in Canada decreased by 42 million barrels, primarily due to entitlement effects. In the TCO affiliate in Kazakhstan, entitlement effects were mainly responsible for the 53 million barrel decrease.

In 2018, improved field performance at various Gulf of Mexico fields and in the Midland and Delaware basins were primarily responsible for the 155 million barrel increase in the United States. Improved field performance at various fields, including Agbami in Nigeria and Moho-Bilondo in the Republic of Congo, were responsible for the 68 million barrel increase in Africa. Reserves in Other Americas increased by 60 million barrels, primarily due to improved field performance at the Hebron field in Canada. In Asia, improved performance across numerous assets resulted in the 37 million barrel increase. In the TCO affiliate in Kazakhstan, entitlement effects were mainly responsible for the 39 million barrel decrease.

Improved Recovery In 2016, improved recovery increased reserves by 293 million barrels, primarily due to the Future Growth Project in the TCO affiliate in Kazakhstan.

Extensions and Discoveries In 2016, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 131 million barrel increase in the United States.

In 2017, extensions and discoveries in the Midland and Delaware basins and the Gulf of Mexico were primarily responsible for the 458 million barrel increase in the United States. Extensions and discoveries in the Duvernay Shale in Canada were primarily responsible for the 74 million barrel increase in Other Americas.

In 2018, extensions and discoveries in the Midland and Delaware basins were primarily responsible for the 532 million barrel increase in the United States. Extensions and discoveries in the Duvernay Shale in Canada and Loma Campana in Argentina were primarily responsible for the 36 million barrel increase in Other Americas.

Supplemental Information on Oil and Gas Producing Activities - Unaudited

Purchases In 2017, purchases of 33 million barrels in Asia were due to contract extension in the Azeri-Chirag-Gunashli fields in Azerbaijan.

In 2018, purchases of 50 million barrels in the United States were primarily in the Midland and Delaware basins.

Sales In 2016, sales of 34 million barrels in the United States were primarily in the Gulf of Mexico shelf.

In 2017, sales of 57 million barrels in the United States were primarily in the Gulf of Mexico shelf and in the Midland and Delaware basins.

In 2018, sales of 32 million barrels in the United States were primarily in the San Joaquin Valley.

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



	Consolidated Companies																Affiliated Companies						Total Consolidated
			Other						Australia/				Synthetic						Synthetic				and Affiliated
Millions of barrels	U.S.		Americas¹		Africa		Asia		Oceania		Europe		Oil²		Total		TCO		Oil		Other³		Companies
Reserves at January 1, 2016	1,386		236		957		790		153		143		597		4,262		1,676		193		131		6,262
Changes attributable to:
Revisions	109		(20	)	22		50		12		16		26		215		64		(12	)	(5	)	262
Improved recovery	5		—		11		2		—		—		—		18		273		—		2		293
Extensions and discoveries	131		23		9		1		—		—		—		164		—		—		—		164
Purchases	—		10		—		—		—		—		—		10		—		—		—		10
Sales	(34	)	—		—		—		—		—		—		(34	)	—		—		—		(34	)
Production	(185	)	(26	)	(123	)	(123	)	(7	)	(21	)	(19	)	(504	)	(104	)	(11	)	(10	)	(629	)
Reserves at December 31, 2016⁴	1,412		223		876		720		158		138		604		4,131		1,909		170		118		6,328
Changes attributable to:
Revisions	280		25		79		(17	)	11		30		(42	)	366		(53	)	—		(5	)	308
Improved recovery	9		—		7		1		—		—		—		17		—		—		3		20
Extensions and discoveries	458		74		4		—		—		—		—		536		—		—		—		536
Purchases	4		—		2		33		—		—		—		39		—		—		—		39
Sales	(57	)	(1	)	—		(2	)	—		—		—		(60	)	—		—		—		(60	)
Production	(190	)	(24	)	(129	)	(104	)	(10	)	(23	)	(19	)	(499	)	(107	)	(11	)	(12	)	(629	)
Reserves at December 31, 2017⁴	1,916		297		839		631		159		145		543		4,530		1,749		159		104		6,542
Changes attributable to:
Revisions	155		60		68		37		17		20		21		378		(39	)	(23	)	(10	)	306
Improved recovery	5		—		—		1		—		4		—		10		—		—		—		10
Extensions and discoveries	532		36		1		—		—		—		—		569		—		—		—		569
Purchases	50		—		—		—		—		—		—		50		—		—		—		50
Sales	(32	)	—		(5	)	—		—		—		—		(37	)	—		—		—		(37	)
Production	(224	)	(30	)	(127	)	(90	)	(15	)	(20	)	(19	)	(525	)	(105	)	(9	)	(11	)	(650	)
Reserves at December 31, 2018⁴	2,402		363		776		579		161		149		545		4,975		1,605		127		83		6,790


¹	Ending reserve balances in North America were 291, 234 and 169 and in South America were 72, 63 and 54 in 2018, 2017 and 2016, respectively.


²	Reserves associated with Canada.


³	Ending reserve balances in Africa were 19, 26 and 31 and in South America were 64, 78 and 87 in 2018, 2017 and 2016, respectively.


⁴	Included are year-end reserve quantities related to production-sharing contracts (PSC) (refer to page E-7 for the definition of a PSC). PSC-related reserve quantities are 12 percent, 15 percent and 19 percent for consolidated companies for 2018, 2017 and 2016, respectively.

Supplemental Information on Oil and Gas Producing Activities - Unaudited

Net Proved Reserves of Natural Gas



	Consolidated Companies														Affiliated Companies				Total Consolidated
			Other						Australia/										and Affiliated
Billions of cubic feet (BCF)	U.S.		Americas¹		Africa		Asia		Oceania		Europe		Total		TCO		Other²		Companies
Reserves at January 1, 2016	4,242		714		2,937		5,956		11,873		224		25,946		2,268		1,223		29,437
Changes attributable to:
Revisions	(6	)	(24	)	(29	)	443		853		72		1,309		111		(107	)	1,313
Improved recovery	2		—		—		—		—		—		2		—		—		2
Extensions and discoveries	388		73		—		4		14		—		479		—		—		479
Purchases	4		3		—		—		—		—		7		—		—		7
Sales	(544	)	(10	)	—		—		—		—		(554	)	—		—		(554	)
Production³	(410	)	(109	)	(81	)	(870	)	(225	)	(62	)	(1,757	)	(137	)	(30	)	(1,924	)
Reserves at December 31, 2016⁴	3,676		647		2,827		5,533		12,515		234		25,432		2,242		1,086		28,760
Changes attributable to:
Revisions	670		39		184		65		1,545		143		2,646		87		48		2,781
Improved recovery	3		—		—		—		—		—		3		—		—		3
Extensions and discoveries	1,361		319		—		2		—		—		1,682		—		—		1,682
Purchases	1		—		2		46		—		—		49		—		—		49
Sales	(177	)	(129	)	—		(31	)	—		—		(337	)	—		—		(337	)
Production³	(354	)	(81	)	(107	)	(842	)	(501	)	(76	)	(1,961	)	(146	)	(95	)	(2,202	)
Reserves at December 31, 2017⁴	5,180		795		2,906		4,773		13,559		301		27,514		2,183		1,039		30,736
Changes attributable to:
Revisions	258		(3	)	25		347		1,012		68		1,707		(108	)	(38	)	1,561
Improved recovery	2		2		—		—		1		—		5		—		—		5
Extensions and discoveries	1,627		138		—		5		—		1		1,771		—		3		1,774
Purchases	144		—		1		—		—		—		145		—		—		145
Sales	(125	)	—		(5	)	—		—		—		(130	)	—		—		(130	)
Production³	(377	)	(69	)	(112	)	(815	)	(841	)	(65	)	(2,279	)	(141	)	(95	)	(2,515	)
Reserves at December 31, 2018⁴	6,709		863		2,815		4,310		13,731		305		28,733		1,934		909		31,576


¹	Ending reserve balances in North America and South America were 582, 478, 172 and 281, 317, 475 in 2018, 2017 and 2016, respectively.


²	Ending reserve balances in Africa and South America were 799, 899, 939 and 110, 140, 147 in 2018, 2017 and 2016, respectively.


³	Total “as sold” volumes are 2,289, 1,995 and 1,744 for 2018, 2017 and 2016, respectively.


⁴	Includes reserve quantities related to production-sharing contracts (PSC) (refer to page E-7 for the definition of a PSC). PSC-related reserve quantities are 10 percent, 12 percent and 15 percent for consolidated companies for 2018, 2017 and 2016, respectively.

Noteworthy changes in natural gas proved reserves for 2016 through 2018 are discussed below and shown in the table above:

Revisions In 2016, development activities primarily at Wheatstone were responsible for the 853 BCF increase in Australia. Net revisions of 443 BCF in Asia were primarily due to improved field performance in China and Thailand.

In 2017, reservoir performance and new seismic data in the greater Gorgon area were primarily responsible for the 1.5 TCF increase in Australia. Improved performance in the Midland and Delaware basins were primarily responsible for the 670 BCF increase in the United States. The Sonam Field in Nigeria was primarily responsible for the 184 BCF increase in Africa.

In 2018, reservoir performance, well test and surveillance data at Wheatstone and the greater Gorgon area were responsible for the 1.0 TCF increase in Australia. The Bibiyana Field in Bangladesh and the Pattani Field in Thailand were primarily responsible for the 347 BCF increase in Asia. Improved performance in the Midland and Delaware basins were primarily responsible for the 258 BCF increase in the United States.

Extensions and Discoveries In 2016, extensions and discoveries of 388 BCF in the United States were primarily in the Appalachian region and the Midland and Delaware basins.

In 2017, extensions and discoveries of 1.4 TCF in the United States were primarily in the Appalachian region and the Midland and Delaware basins. Extensions and discoveries in the Duvernay Shale in Canada were primarily responsible for the 319 BCF increase in Other Americas.

In 2018, extensions and discoveries of 1.6 TCF in the United States were primarily in the Appalachian region and the Midland and Delaware basins.

Supplemental Information on Oil and Gas Producing Activities - Unaudited

Sales In 2016, sales of 544 BCF in the United States were primarily in the Gulf of Mexico shelf, Michigan and the midcontinent region.

In 2017, sales of 177 BCF in the United States were primarily from the Midland and Delaware basins. Sale of the company's interests in Trinidad and Tobago was primarily responsible for the 129 BCF decrease in Other Americas.

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

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



	Consolidated Companies																					Affiliated Companies						Total Consolidated
				Other									Australia/															and Affiliated
Millions of dollars	U.S.			Americas			Africa			Asia			Oceania			Europe			Total			TCO			Other			Companies
At December 31, 2018
Future cash inflows from production	$	132,512		$	52,470		$	56,856		$	54,012		$	109,116		$	11,959		$	416,925		$	100,518		$	16,928		$	534,371
Future production costs	(34,679		)	(20,691		)	(18,850		)	(17,359		)	(16,296		)	(6,609		)	(114,484		)	(24,580		)	(4,665		)	(143,729		)
Future development costs	(17,322		)	(5,106		)	(4,112		)	(5,494		)	(7,757		)	(1,393		)	(41,184		)	(14,069		)	(1,692		)	(56,945		)
Future income taxes	(17,369		)	(7,553		)	(23,593		)	(14,514		)	(25,519		)	(1,676		)	(90,224		)	(18,561		)	(4,496		)	(113,281		)
Undiscounted future net cash flows	63,142			19,120			10,301			16,645			59,544			2,281			171,033			43,308			6,075			220,416
10 percent midyear annual discount for timing of estimated cash flows	(29,103		)	(11,136		)	(2,646		)	(4,822		)	(28,276		)	(419		)	(76,402		)	(22,025		)	(2,662		)	(101,089		)
Standardized Measure Net Cash Flows	$	34,039		$	7,984		$	7,655		$	11,823		$	31,268		$	1,862		$	94,631		$	21,283		$	3,413		$	119,327
At December 31, 2017
Future cash inflows from production	$	94,086		$	43,175		$	47,828		$	47,809		$	77,557		$	8,800		$	319,255		$	80,090		$	13,632		$	412,977
Future production costs	(29,049		)	(20,044		)	(18,124		)	(18,640		)	(12,315		)	(6,345		)	(104,517		)	(22,050		)	(4,635		)	(131,202		)
Future development costs	(10,849		)	(5,102		)	(3,808		)	(4,755		)	(6,682		)	(1,114		)	(32,310		)	(17,564		)	(1,760		)	(51,634		)
Future income taxes	(10,803		)	(5,158		)	(17,845		)	(10,901		)	(17,568		)	(615		)	(62,890		)	(12,143		)	(3,250		)	(78,283		)
Undiscounted future net cash flows	43,385			12,871			8,051			13,513			40,992			726			119,538			28,333			3,987			151,858
10 percent midyear annual discount for timing of estimated cash flows	(19,781		)	(8,483		)	(2,058		)	(3,846		)	(19,730		)	207			(53,691		)	(16,310		)	(1,844		)	(71,845		)
Standardized Measure Net Cash Flows	$	23,604		$	4,388		$	5,993		$	9,667		$	21,262		$	933		$	65,847		$	12,023		$	2,143		$	80,013
At December 31, 2016
Future cash inflows from production	$	53,777		$	33,520		$	39,072		$	44,526		$	63,781		$	6,338		$	241,014		$	66,506		$	11,244		$	318,764
Future production costs	(26,530		)	(20,413		)	(19,749		)	(19,815		)	(11,058		)	(5,500		)	(103,065		)	(13,610		)	(5,254		)	(121,929		)
Future development costs	(7,830		)	(4,277		)	(4,186		)	(4,603		)	(7,804		)	(977		)	(29,677		)	(20,855		)	(2,192		)	(52,724		)
Future income taxes	(3,454		)	(2,664		)	(9,684		)	(8,503		)	(13,476		)	69			(37,712		)	(9,613		)	(1,639		)	(48,964		)
Undiscounted future net cash flows	15,963			6,166			5,453			11,605			31,443			(70		)	70,560			22,428			2,159			95,147
10 percent midyear annual discount for timing of estimated cash flows	(5,123		)	(3,646		)	(1,336		)	(3,137		)	(15,284		)	322			(28,204		)	(13,902		)	(972		)	(43,078		)
Standardized Measure Net Cash Flows	$	10,840		$	2,520		$	4,117		$	8,468		$	16,159		$	252		$	42,356		$	8,526		$	1,187		$	52,069

100

Supplemental Information on Oil and Gas Producing Activities - Unaudited

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

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



									Total Consolidated and
Millions of dollars	Consolidated Companies				Affiliated Companies				Affiliated Companies
Present Value at January 1, 2016		$	52,055			$	14,927			$	66,982
Sales and transfers of oil and gas produced net of production costs		(14,415		)		(2,788		)		(17,203		)
Development costs incurred		12,732				2,473				15,205
Purchases of reserves		(41		)		—				(41		)
Sales of reserves		528				—				528
Extensions, discoveries and improved recovery less related costs		1,231				(917		)		314
Revisions of previous quantity estimates		12,851				946				13,797
Net changes in prices, development and production costs		(37,198		)		(9,798		)		(46,996		)
Accretion of discount		7,888				2,113				10,001
Net change in income tax		6,724				2,758				9,482
Net change for 2016		(9,700		)		(5,213		)		(14,913		)
Present Value at December 31, 2016		$	42,355			$	9,714			$	52,069
Sales and transfers of oil and gas produced net of production costs		(21,505		)		(5,234		)		(26,739		)
Development costs incurred		9,417				3,721				13,138
Purchases of reserves		105				—				105
Sales of reserves		(1,148		)		—				(1,148		)
Extensions, discoveries and improved recovery less related costs		3,716				—				3,716
Revisions of previous quantity estimates		11,132				(1,085		)		10,047
Net changes in prices, development and production costs		28,754				8,013				36,767
Accretion of discount		6,116				1,398				7,514
Net change in income tax		(13,095		)		(2,361		)		(15,456		)
Net change for 2017		23,492				4,452				27,944
Present Value at December 31, 2017		$	65,847			$	14,166			$	80,013
Sales and transfers of oil and gas produced net of production costs		(33,535		)		(6,813		)		(40,348		)
Development costs incurred		9,723				5,044				14,767
Purchases of reserves		99				—				99
Sales of reserves		(622		)		—				(622		)
Extensions, discoveries and improved recovery less related costs		5,503				14				5,517
Revisions of previous quantity estimates		15,480				(2,255		)		13,225
Net changes in prices, development and production costs		39,241				17,251				56,492
Accretion of discount		9,413				2,084				11,497
Net change in income tax		(16,518		)		(4,795		)		(21,313		)
Net change for 2018		28,784				10,530				39,314
Present Value at December 31, 2018		$	94,631			$	24,696			$	119,327

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PART IV

Item 15. Exhibits and 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	49
Consolidated Statement of Income for the three years ended December 31, 2018	50
Consolidated Statement of Comprehensive Income for the three years ended December 31, 2018	51
Consolidated Balance Sheet at December 31, 2018 and 2017	52
Consolidated Statement of Cash Flows for the three years ended December 31, 2018	53
Consolidated Statement of Equity for the three years ended December 31, 2018	54
Notes to the Consolidated Financial Statements	55 to 89

(2) Financial Statement Schedules:

Included below is Schedule II - Valuation and Qualifying Accounts.

(3) Exhibits:

The Exhibit Index on the following pages lists the exhibits that are filed as part of this report.

Schedule II — Valuation and Qualifying Accounts



	Year ended December 31
Millions of Dollars	2018			2017			2016
Employee Termination Benefits
Balance at January 1	$	62		$	111		$	308
Additions (reductions) charged to expense	5			20			160
Payments	(48		)	(69		)	(357		)
Balance at December 31	$	19		$	62		$	111
Allowance for Doubtful Accounts
Balance at January 1	$	606		$	487		$	429
Additions to expense	379			128			76
Bad debt write-offs	(5		)	(9		)	(18		)
Balance at December 31	$	980		$	606		$	487
Deferred Income Tax Valuation Allowance^*
Balance at January 1	$	16,574		$	16,069		$	15,412
Additions to deferred income tax expense	2,000			2,681			1,810
Reduction of deferred income tax expense	(2,601		)	(2,176		)	(1,153		)
Balance at December 31	$	15,973		$	16,574		$	16,069

* See also Note 16 to the Consolidated Financial Statements, beginning on page 74.

Item 16. Form 10-K Summary

Not applicable.

102

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 quarter ended June 30, 2008, and incorporated herein by reference.
3.2	By-Laws of Chevron Corporation, as amended September 30, 2015 filed as Exhibit 3.2 to Chevron Corporation's Current Report on Form 8-K filed September 30, 2015, and incorporated herein by reference.
4.1	Indenture, dated as of June 15, 1995, filed as Exhibit 4.1 to Chevron Corporation's Amendment Number 1 to Registration Statement on Form S-3 filed June 14, 1995, and incorporated herein by reference.
4.2	Form of Indenture filed as Exhibit 4.1 to Chevron Corporation's Registration Statement on Form S-3 filed May 3, 2018, and incorporated herein by reference.
4.3	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+	Amendment Number One to the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan, filed as Exhibit 10.1 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, and incorporated herein by reference.
10.3+	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.
10.4+	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.
10.5+	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.
10.6+	Amendment to the Chevron Incentive Plan, effective January 31, 2018, filed as Exhibit 10.6 to Chevron Corporation's Annual Report on Form 10-K for the year ended December 31, 2017, and incorporated herein by reference.
10.7+*	Summary of Chevron Incentive Plan Award Criteria.
10.8+	Long-Term Incentive Plan of Chevron Corporation, filed as Appendix B to Chevron Corporation’s Notice of the 2013 Annual Meeting and 2013 Proxy Statement filed April 11, 2013, and incorporated herein by reference.
10.9+	Form of Performance Share Agreement 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 4, 2019, and incorporated herein by reference.
10.10+	Form of Standard Restricted Stock Unit Award Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.2 to Chevron Corporation's Current Report on Form 8-K filed February 4, 2019, and incorporated herein by reference.
10.11+	Form of Special Restricted Stock Unit Award Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.3 to Chevron Corporation's Current Report on Form 8-K filed February 4, 2019, and incorporated herein by reference.
10.12+	Form of Non-Qualified Stock Options Award Agreement 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 2, 2018, and incorporated herein by reference.
10.13+	Form of Stock Appreciation Rights Grant Agreement under the Long-Term Incentive Plan of Chevron Corporation, filed as Exhibit 10.10 to Chevron Corporation's Annual Report on Form 10-K for the year ended December 31, 2014, and incorporated herein by reference.

103



Exhibit No.	Description
10.14+	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.
10.15+	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.
10.16+	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.
10.17+	Amendment Number One to the Chevron Corporation Retirement Restoration Plan, filed as Exhibit 10.23 to Chevron Corporation's Annual Report on Form 10-K for the year ended December 31, 2017, and incorporated herein by reference.
10.18+	Chevron Corporation ESIP Restoration Plan, Amended and Restated as of January 1, 2018, filed as Exhibit 10.1 to Chevron Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2017, and incorporated herein by reference.
10.19+	Agreement between Chevron Corporation and R. Hewitt Pate, filed as Exhibit 10.16 to Chevron Corporation's Annual Report on Form 10-K for the year ended December 31, 2011, and incorporated herein by reference.
10.20+	Contract, effective as of June 29, 2018, by and between Chevron Corporation and John S. Watson, filed as Exhibit 10.1 to Chevron Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2018, and incorporated herein by reference.
21.1*	Subsidiaries of Chevron Corporation (page E-1).
23.1*	Consent of PricewaterhouseCoopers LLP (page E-2).
24.1*	Power of Attorney for certain directors of Chevron Corporation, authorizing the signing of the Annual Report on Form 10-K on their behalf.
31.1*	Rule 13a-14(a)/15d-14(a) Certification by the company’s Chief Executive Officer (page E-3).
31.2*	Rule 13a-14(a)/15d-14(a) Certification by the company’s Chief Financial Officer (page E-4).
32.1**	Rule 13a-14(b)/15d-14(b) Certification by the company’s Chief Executive Officer (page E-5).
32.2**	Rule 13a-14(b)/15d-14(b) Certification by the company’s Chief Financial Officer (page E-6).
99.1*	Definitions of Selected Energy and Financial Terms (pages E-7 through E-8).
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.”

______________________________

+ Indicates a management contract or compensatory plan or arrangement.


*	Filed herewith.


**	Furnished herewith.

Pursuant to Item 601(b)(4) of Regulation S-K, certain instruments with respect to the company's long-term debt are not filed with this Annual Report on Form 10-K. A copy of any such instrument will be furnished to the Securities and Exchange Commission upon request.

104

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 day of February, 2019.



	Chevron Corporation
By:	/s/ MICHAEL K. WIRTH
	Michael K. Wirth, 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 day of February, 2019.

Principal Executive Officer

(and Director)

/s/ MICHAEL K. WIRTH
Michael K. Wirth, Chairman of the
Board and Chief Executive Officer

Principal Financial Officer

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

Principal Accounting Officer

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

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

Directors

WANDA M. AUSTIN^*
Wanda M. Austin

JOHN B. FRANK^*
John B. Frank

ALICE P. GAST^*
Alice P. Gast

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

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

DAMBISA F. MOYO^*
Dambisa F. Moyo

DEBRA REED-KLAGES^*
Debra Reed-Klages

RONALD D. SUGAR^*
Ronald D. Sugar

INGE G. THULIN^*
Inge G. Thulin

D. JAMES UMPLEBY III^*D. James Umpleby III

105