10-K 1 cvx12312018-10kdoc.htm 10-K 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