Document


 
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
OR
o  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from ______ to ______
Commission File Number 001-00368
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.
Large accelerated filer  þ
 
Accelerated filer 
 
 
 
o
Non-accelerated filer  o
 
Smaller reporting company
 
o
 
 
Emerging growth company 
 
o
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
 
 
 
           Upstream
 
           Downstream 
 
           Other Businesses 
4.
Mine Safety Disclosures
 
Executive Officers of the Registrant
 
16.
Form 10-K Summary
 

1





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.
 

2





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.
3





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.
4





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

 
Affiliates2,5
447

466

 
339

355

 
645

661

 
Total Including Affiliates6 
2,930

2,728

 
1,782

1,723

 
6,889

6,032

 
 
 
 
 
 
 
 
 
 
 
1 Oil-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.
 
5 Volumes 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 565 million 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.
 

5





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.
 
2 The 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.

6





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.
 

7





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.


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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.

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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.

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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.

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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.

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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

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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.

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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

15





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

 

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 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.

17





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

18





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.

19





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

20





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

21





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.

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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.


23





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.

24





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.

25
































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26


Financial Table of Contents


 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Off-Balance-Sheet Arrangements, Contractual Obligations,
    Guarantees and Other Contingencies
 
 
 
 
 
 
 
 
 
 
 
Consolidated Financial Statements
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Changes in Accumulated Other
    Comprehensive Losses
Note 3
Information Relating to the Consolidated
Note 4
Note 5
Note 6
Note 7
Note 8
Note 9
Note 10
Assets Held for Sale
Note 11
Note 12
Note 13
Note 14
Note 15
Note 16
Note 17
Properties, Plant and Equipment
Note 18
Note 19
Note 20
Note 21
Note 22
Note 23
Note 24
Note 25
Revenue
Note 26
Other Financial Information
 
 
 
 
 

27



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 Corporation1,2
$
14,824

 
$
9,195

 
$
(497
)
1  Includes foreign currency effects:
$
611

 
$
(446
)
 
$
58

2 Income 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.

28



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.
beochart2018.jpg
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

29



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.
a2018productiona04.jpg

30



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.

31



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.
a2018earnings.jpg
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

32



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.

33



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.

34



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

35



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.


36



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

Selected Operating Data1,2
 
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

1 Includes company share of equity affiliates.
2 MBPD – thousands of barrels per day; MMCFPD – millions of cubic feet per day; MBOEPD – thousands of barrels of oil-equivalents per day; Bbl – barrel; MCF – thousands of cubic feet. Oil-equivalent gas (OEG) conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of 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.



37



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

Liquidity and Capital Resources
Sources and uses of cash
a2018sourcesandusesofcash2.jpg
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.


38



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

a2018cashpovidedby.jpg
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


39



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.

40



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 Debt3, 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 20202021 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

41



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.”

42



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:

43



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:
1.
Amortization - Capitalized exploratory drilling and development costs are depreciated on a unit-of-production (UOP) basis using proved developed reserves. Acquisition costs of proved properties are amortized on a UOP basis using total proved reserves. During 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.
2.
Impairment - Oil and gas reserves are used in assessing oil and gas producing properties for impairment. A significant reduction in the estimated reserves of a property would trigger an impairment review. 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

44



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.

45



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.

46






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.
 
 

47






 
 
 
 
 
 
 
 
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.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
wirtha01.gif
 
     

   peysignaturea19.gif
 
jouradasiga01.gif
 
 
 
 
 
 
 
 
 
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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


48






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

 

49



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
)
 
 
1 2017 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.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

50



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.
 
 
 
 
 
 
 
 
 
 
 
 
 
 


51



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

 
 
1 Includes capital lease obligations of $127 and $94 at December 31, 2018 and 2017, respectively.
 
 
 
 
 
2 Refer to Note 23, "Other Contingencies and Commitments" beginning on page 86.
 
 
 
 
 
See accompanying Notes to the Consolidated Financial Statements.
 
 
 
 
 
 
 
 
 
 

52



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 Activities1,2
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 investment1,2
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 Activities1,2
(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.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

53



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.
 
 
 
 
 
 
 
 
 
 


54



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.”

55



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

56



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.

57



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.

58



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.

59



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.

60



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.


61



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.

62



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

63



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.

64



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
 
 
 
 
 
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.

65



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
)
 
1 There 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.

66



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

67



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

1 Other 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.

68



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.


69



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

70



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

71



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

72



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).

73



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.

74



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.

75



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.


76



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

1    Weighted-average interest rates at December 31, 2018 and 2017, were 2.43 percent and 1.30 percent, respectively.
 
 
 
 
2    Net 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.

77



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.

78



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


79



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


1    Expected term is based on historical exercise and post-vesting cancellation data.
2    Volatility rate is based on historical stock prices over an appropriate period, generally equal to the expected term.
A summary of option activity during 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.

80



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
)

81



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

82



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:

83



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


84



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 3060 percent, Fixed Income and Cash 2065 percent, Real Estate 015 percent, and Alternative Investments 015 percent. For the U.K. pension plan, the U.K. Board of Trustees has established the following asset allocation guidelines: Equities 2545 percent, Fixed Income and Cash 4075 percent, and Real Estate 515 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.

85



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

86



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.

87



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

88



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.

89



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

 
 
 
 
 
 
 
 
 
 
 
 
 
 

90



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



91



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

 


92



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.


93



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.




94



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



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

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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

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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.

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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.

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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.


99



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




101






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) 
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
3.2
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
4.3
10.1+
10.2+
10.3+
10.4+
10.5+
10.6+
10.7+*
10.8+
10.9+
10.10+
10.11+
10.12+
10.13+

103





Exhibit No.
Description
10.14+
10.15+
10.16+
10.17+
10.18+
10.19+
10.20+
21.1*
23.1*
24.1*
31.1*
31.2*
  32.1**
  32.2**
99.1*
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