Print Page  Close Window



10-K
CHEVRON CORP filed this Form 10-K on 02/23/2017
Entire Document
 
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, 2016
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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes þ          No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer þ
 
Accelerated filer o
 
Non-accelerated filer o 
(Do not check if a smaller
reporting company)
 
Smaller reporting company o 
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).     Yes o       No þ
 Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter — $197,763,938,564 (As of June 30, 2016)
 Number of Shares of Common Stock outstanding as of February 15, 2017 — 1,893,102,970
 
DOCUMENTS INCORPORATED BY REFERENCE
(To The Extent Indicated Herein)
Notice of the 2017 Annual Meeting and 2017 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, in connection with the company’s 2017 Annual Meeting of Stockholders (in Part III)
 































THIS PAGE INTENTIONALLY LEFT BLANK










TABLE OF CONTENTS
ITEM
 
PAGE
 
 
 
           Upstream
 
           Downstream 
 
           Other Businesses 
4.
Mine Safety Disclosures
 
16.
Form 10-K Summary
 
EX-12.1
EX-31.1
EX-18.1
EX-31.2
EX-21.1
EX-32.1
EX-23.1
EX-32.2
EX-24.1
EX-99.1
EX-24.2
EX-101 INSTANCE DOCUMENT
EX-24.3
EX-101 SCHEMA DOCUMENT
EX-24.4
EX-101 CALCULATION LINKBASE DOCUMENT
EX-24.5
EX-101 LABELS LINKBASE DOCUMENT
EX-24.6
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-24.7
EX-101 DEFINITION LINKBASE DOCUMENT
EX-24.8
 
EX-24.9
 
EX-24.10
 
 
 
 
 


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,” “budgets,” “outlook,” “focus,” “on schedule,” “on track,” “goals,” “objectives,” “strategies” and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, many of which are beyond the company’s control and are difficult to predict. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements. The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this report. Unless legally required, Chevron undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.
Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are: changing crude oil and natural gas prices; changing refining, marketing and chemicals margins; the company's ability to realize anticipated cost savings and expenditure reductions; actions of competitors or regulators; timing of exploration expenses; timing of crude oil liftings; the competitiveness of alternate-energy sources or product substitutes; technological developments; the results of operations and financial condition of the company's suppliers, vendors, partners and equity affiliates, particularly during extended periods of low prices for crude oil and natural gas; the inability or failure of the company’s joint-venture partners to fund their share of operations and development activities; the potential failure to achieve expected net production from existing and future crude oil and natural gas development projects; potential delays in the development, construction or start-up of planned projects; the potential disruption or interruption of the company’s operations due to war, accidents, political events, civil unrest, severe weather, cyber threats and terrorist acts, crude oil production quotas or other actions that might be imposed by the Organization of Petroleum Exporting Countries, or other natural or human causes beyond its control; changing economic, regulatory and political environments in the various countries in which the company operates; general domestic and international economic and political conditions; the potential liability for remedial actions or assessments under existing or future environmental regulations and litigation; significant operational, investment or product changes required by existing or future environmental statutes and regulations, including international agreements and national or regional legislation and regulatory measures to limit or reduce greenhouse gas emissions; the potential liability resulting from other pending or future litigation; the company’s future acquisition or disposition of assets or the delay or failure of such transactions to close based on required closing conditions set forth in the applicable transaction agreements; the potential for gains and losses from asset dispositions or impairments; government-mandated sales, divestitures, recapitalizations, industry-specific taxes, changes in fiscal terms or restrictions on scope of company operations; foreign currency movements compared with the U.S. dollar; material reductions in corporate liquidity and access to debt markets; the effects of changed accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; the company's ability to identify and mitigate the risks and hazards inherent in operating in the global energy industry; and the factors set forth under the heading “Risk Factors” on pages 20 through 22 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-5. As of December 31, 2016, Chevron had approximately 55,200 employees (including about 3,200 service station employees). Approximately 26,500 employees (including about 3,100 service station employees), or 48 percent, were employed in U.S. operations.
Overview of Petroleum Industry
Petroleum industry operations and profitability are influenced by many factors. Prices for crude oil, natural gas, petroleum products and petrochemicals are generally determined by supply and demand. Production levels from the members of the Organization of Petroleum Exporting Countries (OPEC) are a major factor in determining worldwide supply. Demand for crude oil and its products and for natural gas is largely driven by the conditions of local, national and global economies, although weather patterns and taxation relative to other energy sources also play a significant part. Laws and governmental policies, particularly in the areas of taxation, energy and the environment, affect where and how companies conduct their operations and formulate their products and, in some cases, limit their profits directly.
Strong competition exists in all sectors of the petroleum and petrochemical industries in supplying the energy, fuel and chemical needs of industry and individual consumers. Chevron competes with fully integrated, major global petroleum companies, as well as independent and national petroleum companies, for the acquisition of crude oil and natural gas leases and other properties and for the equipment and labor required to develop and operate those properties. In its downstream business, Chevron competes with fully integrated, major petroleum companies, as well as independent refining, marketing, transportation and chemicals entities and national petroleum companies, in the sale or acquisition of various goods or services in many national and international markets.
Operating Environment
Refer to pages FS-2 through FS-9 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” and “us” may refer to Chevron Corporation, one or more of its consolidated subsidiaries, or all of them taken as a whole, but unless stated otherwise they do not include “affiliates” of Chevron — i.e., those companies accounted for by the equity method (generally owned 50 percent or less) or investments accounted for by the cost method. All of these terms are used for convenience only and are not intended as a precise description of any of the separate companies, each of which manages its own affairs.
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, 2016, and assets as of the end of 2016 and 2015 — for the United States and the company’s international geographic areas — are in Note 15 to the Consolidated Financial Statements beginning on page FS-40. Similar comparative data for the company’s investments in and income from equity affiliates and property, plant and equipment are in Notes 16 and 17 on pages FS-43 through FS-44. Refer to page FS-14 of this Form 10-K in Management's Discussion and Analysis of Financial Condition and Results of Operations for a discussion of the company's capital and exploratory expenditures.

Upstream
Reserves
Refer to Table V beginning on page FS-69 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 2014 and each year-end from 2014 through 2016. 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, 2016, 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, 2016, 23 percent of the company's net proved oil-equivalent reserves were located in Kazakhstan, 20 percent were located in Australia and 18 percent were located in the United States.
The net proved reserve balances at the end of each of the three years 2014 through 2016 are shown in the following table:
 
At December 31
 
 
 
2016

 
2015

 
2014

 
Liquids — Millions of barrels
 
 
 
 
 
 
  Consolidated Companies
4,131

 
4,262

 
4,285

 
  Affiliated Companies
2,197

 
2,000

 
1,964

 
Total Liquids
6,328

 
6,262

 
6,249

 
Natural Gas — Billions of cubic feet
 
 
 
 
 
 
  Consolidated Companies
25,432

 
25,946

 
25,707

 
  Affiliated Companies
3,328

 
3,491

 
3,409

 
Total Natural Gas
28,760

 
29,437

 
29,116

 
Oil-Equivalent — Millions of barrels*
 
 
 
 
 
 
  Consolidated Companies
8,370

 
8,586

 
8,570

 
  Affiliated Companies
2,752

 
2,582

 
2,532

 
Total Oil-Equivalent
11,122

 
11,168

 
11,102

 
* 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 2016 and 2015 by the company and its affiliates. Worldwide oil-equivalent production of 2.594 million barrels per day in 2016 was down 1 percent from 2015. Production increases from major capital projects, shale and tight properties, and base business were more than offset by normal field declines, the impact of asset sales, the Partitioned Zone shut-in, the effects of civil unrest in Nigeria and planned turnaround activity. Refer to the “Results of Operations” section beginning on page FS-6 for a detailed discussion of the factors explaining the 2014 through 2016 changes in production for crude oil and natural gas liquids, and natural gas, and refer to Table V on pages FS-69 and FS-72 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)
2016

2015

 
2016

2015

 
2016

2015

 
United States
691

720

 
504

501

 
1,120

1,310

 
Other Americas
 
 
 
 
 
 
 
 
 
  Argentina
26

27

 
20

21

 
32

36

 
  Brazil
16

18

 
16

17

 
5

5

 
  Canada2
92

69

 
83

67

 
55

14

 
  Colombia
21

27

 


 
127

161

 
  Trinidad and Tobago
12

19

 


 
74

116

 
Total Other Americas
167

160

 
119

105

 
293

332

 
Africa
 
 
 
 
 
 
 
 
 
  Angola
114

119

 
106

110

 
52

52

 
  Democratic Republic of the Congo
2

3

 
2

2

 
1

1

 
  Nigeria
235

270

 
208

230

 
159

246

 
  Republic of Congo
25

20

 
23

18

 
11

11

 
Total Africa
376

412

 
339

360

 
223

310

 
Asia
 
 
 
 
 
 
 
 
 
  Azerbaijan
32

34

 
30

32

 
13

12

 
  Bangladesh
114

123

 
4

3

 
658

720

 
  China
27

24

 
18

24

 
51


 
  Indonesia
203

207

 
173

176

 
182

185

 
  Kazakhstan
62

56

 
37

34

 
154

138

 
  Myanmar
21

20

 


 
128

117

 
  Partitioned Zone3

28

 

27

 

5

 
  Philippines
26

23

 
3

3

 
138

122

 
  Thailand
245

238

 
71

66

 
1,051

1,033

 
Total Asia
730

753

 
336

365

 
2,375

2,332

 
Australia/Oceania
 
 
 
 
 
 
 
 
 
  Australia
124

94

 
21

21

 
615

439

 
Total Australia/Oceania
124

94

 
21

21

 
615

439

 
Europe
 
 
 
 
 
 
 
 
 
  Denmark
22

24

 
14

16

 
48

50

 
  United Kingdom
64

59

 
43

40

 
122

115

 
Total Europe
86

83

 
57

56

 
170

165

 
Total Consolidated Companies
2,174

2,222

 
1,376

1,408

 
4,796

4,888

 
Affiliates2,4
420

400

 
343

336

 
456

381

 
Total Including Affiliates5 
2,594

2,622

 
1,719

1,744

 
5,252

5,269

 
 
 
 
 
 
 
 
 
 
 
1 Oil-equivalent conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of crude oil.
 
2 Includes synthetic oil: Canada, net
50

47

 
50

47

 


 
  Venezuelan affiliate, net
28

29

 
28

29

 


 
3 Located between Saudi Arabia and Kuwait.
 
 
 
 
 
 
 
 
 
4 Volumes represent Chevron’s share of production by affiliates, including Tengizchevroil in Kazakhstan; Petroboscan, Petroindependiente and Petropiar in Venezuela; and Angola LNG in Angola.
 
5 Volumes include natural gas consumed in operations of 486 million and 496 million cubic feet per day in 2016 and 2015, respectively. Total “as sold” natural gas volumes were 4,766 million and 4,773 million cubic feet per day for 2016 and 2015, respectively.
 

5





Production Outlook
The company estimates its average worldwide oil-equivalent production in 2017 will grow 4 to 9 percent compared to 2016, assuming a Brent crude oil price of $50 per barrel and before asset sales. This estimate is subject to many factors and uncertainties, as described beginning on page FS-4. Refer to the “Review of Ongoing Exploration and Production Activities in Key Areas,” beginning on page 8, for a discussion of the company’s major crude oil and natural gas development projects.
Average Sales Prices and Production Costs per Unit of Production
Refer to Table IV on page FS-68 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 2016, 2015 and 2014.
Gross and Net Productive Wells
The following table summarizes gross and net productive wells at year-end 2016 for the company and its affiliates:
 
At December 31, 2016
 
 
 
Productive Oil Wells*
 
Productive Gas Wells *
 
 
 
Gross

 
Net

Gross

 
Net

 
United States
45,659

 
31,679

8,492

 
3,633

 
Other Americas
1,202

 
767

99

 
54

 
Africa
1,824

 
692

17

 
7

 
Asia
15,118

 
12,937

4,029

 
2,352

 
Australia/Oceania
568

 
317

77

 
15

 
Europe
319

 
68

177

 
38

 
Total Consolidated Companies
64,690

 
46,460

12,891

 
6,099

 
Affiliates
1,468

 
508

7

 
2

 
Total Including Affiliates
66,158

 
46,968

12,898

 
6,101

 
Multiple completion wells included above
889

 
608

225

 
184

 
* 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, 2016, 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
4,491

 
3,578

 
5,307

 
3,543

 
9,798

 
7,121

 
Other Americas
27,154

 
14,916

 
1,376

 
368

 
28,530

 
15,284

 
Africa
9,340

 
3,880

 
2,326

 
946

 
11,666

 
4,826

 
Asia
27,890

 
13,328

 
1,719

 
956

 
29,609

 
14,284

 
Australia/Oceania
21,325

 
14,660

 
2,002

 
803

 
23,327

 
15,463

 
Europe
2,121

 
1,023

 
407

 
52

 
2,528

 
1,075

 
Total Consolidated Companies
92,321

 
51,385

 
13,137

 
6,668

 
105,458

 
58,053

 
Affiliates
516

 
225

 
280

 
108

 
796

 
333

 
Total Including Affiliates
92,837

 
51,610

 
13,417

 
6,776

 
106,254

 
58,386

 
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 2017, 2018 and 2019 if production is not established by certain required dates are 2,549, 4,256 and 2,058, 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 140 billion cubic feet of natural gas to third parties from 2017 through 2019. 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 1,913 billion cubic feet of natural gas to third parties from 2017 through 2019 from operations in Australia, Colombia, Denmark, 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 FS-65 for details associated with the company’s development expenditures and costs of proved property acquisitions for 2016, 2015 and 2014.
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, 2016. A “development well” is a well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
 
 
 
Wells Drilling*
 
Net Wells Completed
 
 
 
at 12/31/16
 
2016
 
 
2015
 
 
2014
 
 
 
Gross

Net
 
Prod.

Dry

 
Prod.

Dry

 
Prod.

Dry

 
United States
70

47

 
420

4

 
873

3

 
1,085

8

 
Other Americas
39

21

 
45


 
99


 
81


 
Africa
13

4

 
17


 
9


 
9


 
Asia
50

29

 
470

6

 
828

5

 
1,025

4

 
Australia/Oceania


 
4


 
4


 
9


 
Europe
3


 
3


 
2


 
2


 
Total Consolidated Companies
175

101

 
959

10

 
1,815

8

 
2,211

12

 
Affiliates
43

18

 
38


 
26


 
25

1

 
Total Including Affiliates
218

119

 
997

10

 
1,841

8

 
2,236

13

 
* Gross wells represent the total number of wells in which Chevron has an ownership interest. Net wells represent the sum of Chevron's ownership interest in gross wells.
 
 
Exploration Activities
Refer to Table I on page FS-65 for detail on the company’s exploration expenditures and costs of unproved property acquisitions for 2016, 2015 and 2014.
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, 2016. “Exploratory wells” are wells drilled to find and produce crude oil or natural gas in unproved areas and include delineation and appraisal wells, which are wells drilled to find a new reservoir in a field previously found to be productive of crude oil or natural gas in another reservoir or to extend a known reservoir beyond the proved area.
 
Wells Drilling*
 
Net Wells Completed
 
 
 
at 12/31/16
 
2016
 
 
2015
 
 
2014
 
 
 
Gross

 
Net

 
Prod.

 
Dry

 
Prod.

 
Dry

 
Prod.

 
Dry

 
United States
3


3


4


1


16


4


20


12

 
Other Americas




4




5


1


3



 
Africa




1


1


3




1


2

 
Asia




3




5


1


7


2

 
Australia/Oceania








1


4


3



 
Europe








3




3



 
Total Consolidated Companies
3


3


12


2


33


10


37


16

 
Affiliates















 
Total Including Affiliates
3


3


12


2


33


10


37


16

 
* 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 2016 key upstream activities, some of which are also discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations, beginning on page FS-6, are presented below. The comments include references to “total production” and “net production,” which are defined under “Production” in Exhibit 99.1 on page E-11.
The discussion that follows references the status of proved reserves recognition for significant long-lead-time projects not on production as well as for projects recently placed on production. Reserves are not discussed for exploration activities or recent discoveries that have not advanced to a project stage, or for mature areas of production that do not have individual projects requiring significant levels of capital or exploratory investment. Amounts indicated for project costs represent total project costs, not the company’s share of costs for projects that are less than wholly owned.
United States
Upstream activities in the United States are primarily located in the midcontinent region, the Gulf of Mexico, California and the Appalachian Basin. Net oil-equivalent production in the United States during 2016 averaged 691,000 barrels per day.
The company's activities in the midcontinent region are primarily in Colorado, New Mexico, Oklahoma and Texas. During 2016, net daily production in these areas averaged 123,000 barrels of crude oil, 576 million cubic feet of natural gas and 40,000 barrels of natural gas liquids (NGLs). In 2016, the company divested properties in areas including Oklahoma, Texas and Wyoming. The company is pursuing selected opportunities for divestment of additional properties in 2017.
In the Permian Basin of West Texas and southeast New Mexico, the company holds approximately 500,000 and 1,000,000 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. The stacked plays multiply the basin’s resource and economic potential by allowing for multiple horizontal wells to be developed from a single pad location using shared facilities and infrastructure, which reduces development costs and improves capital efficiency. Chevron has implemented a factory development strategy in the basin, which utilizes multiwell pads to drill multiple horizontal wells that are completed concurrently using multistage hydraulic fracture stimulation. The company drilled 93 wells and participated in 108 nonoperated wells in the Midland and Delaware basins in 2016.
During 2016, net daily production in the Gulf of Mexico averaged 158,000 barrels of crude oil, 183 million cubic feet of natural gas and 13,000 barrels of NGLs. The company divested selected shelf properties in 2016 and is pursuing divestment of additional shelf assets in 2017. Chevron is also engaged in various exploration, development and production activities in the deepwater Gulf of Mexico.
The deepwater Jack and St. Malo fields are being jointly developed with a host floating production unit (FPU) located between the two fields. Chevron has a 50 percent interest in the Jack Field and a 51 percent interest in the St. Malo Field. Both fields are company operated. The company has a 40.6 percent interest in the production host facility, which is designed to accommodate production from the Jack/St. Malo development and third-party tiebacks. Total daily production from the Jack and St. Malo fields in 2016 averaged 94,000 barrels of liquids (47,000 net) and 14 million cubic feet of natural gas (7 million net). Production ramp-up and development drilling for the first development phase continued in 2016. In addition, work continued on Stage 2, the second phase of the development plan, which includes four additional development wells, two each at the Jack and St. Malo fields. Start-up of the first Stage 2 development well was achieved in third quarter 2016. Development drilling is planned to continue in 2017. Proved reserves have been recognized for this project. Production from the Jack/St. Malo development is expected to ramp up to a total daily rate of 128,000 barrels of crude oil and 33 million cubic feet of natural gas. 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 31,000 barrels of crude oil, 13 million cubic feet of natural gas, and 2,000 barrels of NGLs. Four infill production wells were completed in 2016. The next development phase, the Tahiti Vertical Expansion Project, achieved a final investment decision in mid-2016. The expansion project includes four new wells and associated subsea infrastructure. The four wells have been drilled and cased, and completion operations are underway. First oil is expected in 2018. Proved reserves have been recognized for this project. The Tahiti Field has an estimated remaining production life of at least 20 years.
The company has a 15.6 percent nonoperated working interest in the deepwater Mad Dog Field. In 2016, net daily production averaged 8,000 barrels of liquids and 1 million cubic feet of natural gas. The next development phase, the Mad Dog 2 Project, is planned to develop the southern portion of the Mad Dog Field. The development plan includes a new floating production platform with a design capacity of 140,000 barrels of crude oil per day. A final investment decision was reached in February 2017. First oil is expected in 2021. At the end of 2016, proved reserves had not been recognized for the Mad Dog 2 Project.

8





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. Fabrication of replacement mooring tendons began in mid-2016. Platform installation is expected to resume in late 2017, with first oil expected in late 2018. The field has an estimated production life of 35 years from the time of start-up. Proved reserves have been recognized for this project.
Chevron holds a 25 percent nonoperated working interest in the Stampede Project, the unitized development of the deepwater Knotty Head and Pony discoveries. The planned facilities have a design capacity of 80,000 barrels of crude oil and 40 million cubic feet of natural gas per day. Fabrication and development drilling activities progressed in 2016, with first oil expected in 2018. The field has an estimated production life of 30 years from the time of start-up. Proved reserves have been recognized for this project.
During 2016 and early 2017, the company participated in five appraisal wells and four exploration wells in the deepwater Gulf of Mexico. Drilling was completed on an appraisal well at the Sicily discovery in first quarter 2016. No further operations are planned, and the leases expired in 2016. Drilling was completed on two successful appraisal wells at the Anchor discovery, one in second quarter 2016 and one in early 2017.
Chevron is the operator of an exploration and appraisal program and potential development named Tigris, covering a number of jointly held offshore leases in the northwest portion of Keathley Canyon. This area may have the potential to support a cost-effective, deepwater hub development of multiple fields to a new central host. In 2016, two successful appraisal wells were drilled at the 41 percent-owned Tiber and the 50 percent-owned Guadalupe discoveries. The planned appraisal programs have been completed for the Tiber and Guadalupe discoveries and Chevron filed for Suspension of Production (SOP) on both the Tiber and Guadalupe units. The SOPs are intended to hold the associated leases as the planned development concept matures.
Chevron added ten leases to its deepwater portfolio as a result of awards from the central Gulf of Mexico Lease Sale 241, held in first quarter 2016.
In California, the company has significant production in the San Joaquin Valley. In 2016, net daily production averaged 159,000 barrels of crude oil, 54 million cubic feet of natural gas and 3,000 barrels of NGLs.
The company holds approximately 472,000 net acres in the Marcellus Shale and 309,000 net acres in the Utica Shale, primarily located in southwestern Pennsylvania, eastern Ohio and the West Virginia panhandle. During 2016, net daily production in these areas averaged 290 million cubic feet of natural gas, 5,000 barrels of NGLs and 3,000 barrels of condensate. In April 2016, the company divested its interest in the Antrim Shale in Michigan.
Other Americas
“Other Americas” includes Argentina, Brazil, Canada, Colombia, Greenland, Mexico, Suriname, Trinidad and Tobago and Venezuela. Net oil-equivalent production from these countries averaged 226,000 barrels per day during 2016.
Canada Upstream activities in Canada are concentrated in Alberta, British Columbia and the offshore Atlantic region. The company also has exploration interests in the Beaufort Sea region of the Northwest Territories. Net oil-equivalent production during 2016 averaged 92,000 barrels per day, composed of 33,000 barrels of crude oil, 55 million cubic feet of natural gas and 50,000 barrels of synthetic oil from oil sands.
Chevron holds a 26.9 percent nonoperated working interest in the Hibernia Field, which comprises the Hibernia and Ben Nevis Avalon (BNA) reservoirs, and a 23.8 percent nonoperated working interest in the unitized Hibernia Southern Extension (HSE) areas offshore Atlantic Canada. Infill drilling continued in 2016.
The company holds a 29.6 percent nonoperated working interest in the heavy oil Hebron Field, also offshore Atlantic Canada. The development plan includes a platform with a design capacity of 150,000 barrels of crude oil per day. The mating of the integrated topside with the gravity-based structure was completed in 2016. The platform is scheduled to be towed to the field in first-half 2017, and first oil is expected in late 2017. The project has an expected economic life of 30 years from the time of start-up. Proved reserves have been recognized for this project.
In the Flemish Pass Basin offshore Newfoundland, Chevron holds a 40 percent nonoperated working interest in two exploration blocks, EL1125 and EL1126. A 3-D seismic survey has been completed on these blocks. In addition, the company holds a 35 percent-owned and operated interest in Flemish Pass Basin Block EL1138.
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

9





synthetic oil. Carbon dioxide emissions from the upgrade process are reduced by the colocated Quest carbon capture and storage facilities.
The company holds approximately 228,000 net acres in the Duvernay Shale in Alberta and approximately 200,000 overlying acres in the Montney tight rock formation. Chevron has a 70 percent-owned and operated interest in most of the Duvernay acreage. Drilling continued during 2016 on an appraisal and land retention program. A total of 53 wells have been tied into production facilities by early 2017.
Chevron holds a 50 percent-owned and operated interest in the proposed Kitimat LNG and Pacific Trail Pipeline projects and a 50 percent interest in 300,000 net acres in the Horn River and Liard shale gas basins in British Columbia. The horizontal appraisal drilling program progressed during 2016. 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 2016, proved reserves had not been recognized for this project.
In April 2016, the company sold its 93.8 percent operated interest in the Aitken Creek and a 42.9 percent nonoperated interest in the Alberta Hub natural gas storage facilities.
Greenland Chevron holds a 29.2 percent-owned and operated interest in Blocks 9 and 14 located in the Kanumas Area, offshore the northeast coast of Greenland. Additional 2-D seismic data was acquired in 2016 and evaluation of the acreage is ongoing.
Mexico In December 2016, Chevron led a consortium that was the successful bidder on an exploration license for Block 3 in the deepwater Perdido area of the Gulf of Mexico. Following license execution, expected by March 2017, the company will operate and hold a 33.3 percent working interest in Block 3, which covers 139,000 net acres.
Argentina In the Vaca Muerta Shale formation, Chevron holds a 50 percent nonoperated interest in two concessions covering 73,000 net acres. Chevron also holds an 85 percent-owned and operated interest in a concession covering 94,000 net acres with both conventional production and Vaca Muerta Shale potential. In addition, the company holds operated interests in three concessions covering 73,000 net acres in the Neuquen Basin, with interests ranging from 18.8 percent to 100 percent. Net oil-equivalent production in 2016 averaged 26,000 barrels per day, composed of 20,000 barrels of crude oil and 32 million cubic feet of natural gas.
Nonoperated development activities continued in 2016 at the Loma Campana concession in the Vaca Muerta Shale. During 2016, 58 horizontal wells were drilled, and the drilling program is expected to continue in 2017.
In 2016, an exploration program, which included one horizontal and three vertical wells, was completed in the nonoperated Narambuena Block. Results are under evaluation.
Brazil Chevron holds interests in the Frade (51.7 percent-owned and operated) and Papa-Terra (37.5 percent, nonoperated) deepwater fields located in the Campos Basin. The concession that includes the Frade Field expires in 2025, and the concession that includes the Papa-Terra Field expires in 2032. Net oil-equivalent production in 2016 averaged 16,000 barrels per day, composed of 16,000 barrels of crude oil and 5 million cubic feet of natural gas.
Additionally, Chevron holds a 50 percent-owned and operated interest in Block CE-M715, located in the Ceara Basin offshore Brazil. During 2016, the company completed acquisition of 3-D seismic data. Processing of the seismic data was completed in early 2017.
Colombia The company operates the offshore Chuchupa and the onshore Ballena natural gas fields and receives 43 percent of the production for the remaining life of each field. The company also received a variable production volume based on prior Chuchupa capital contributions through 2016. Net production in 2016 averaged 127 million cubic feet of natural gas per day.
Suriname After a farm-down in Block 42 in second quarter 2016, Chevron holds a 33.3 percent and a 50 percent nonoperated working interest in deepwater Blocks 42 and 45 offshore Suriname, respectively.
Trinidad and Tobago The company has a 50 percent nonoperated working interest in three blocks in the East Coast Marine Area offshore Trinidad, which includes the Dolphin, Dolphin Deep and Starfish natural gas fields. Net production in 2016 averaged 74 million cubic feet of natural gas per day.
Venezuela Chevron's production activities in Venezuela are performed by two affiliates in western Venezuela and an affiliate in the Orinoco Belt. Net oil-equivalent production during 2016 averaged 59,000 barrels per day, composed of 28,000 barrels of crude oil, 19 million cubic feet of natural gas and 28,000 barrels of synthetic oil upgraded from heavy oil.

10





Chevron has a 30 percent interest in the Petropiar affiliate that operates the Hamaca heavy oil production and upgrading project located in Venezuela’s Orinoco Belt under an agreement expiring in 2033. Petropiar drilled 67 development wells in 2016. 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 33 development wells in 2016.
Chevron also holds a 34 percent interest in the Petroindependencia affiliate, which includes the Carabobo 3 heavy oil project located within the Orinoco Belt.
Africa
In Africa, the company is engaged in upstream activities in Angola, Democratic Republic of the Congo, Liberia, Morocco, Nigeria and Republic of Congo. Net oil-equivalent production averaged 389,000 barrels per day during 2016.
Angola The company operates and holds a 39.2 percent interest in Block 0, a concession adjacent to the Cabinda coastline, and a 31 percent interest in a production-sharing contract (PSC) for deepwater Block 14. The concession for Block 0 extends through 2030 and the development and production rights for the various producing fields in Block 14 expire between 2023 and 2028. During 2016, net production averaged 108,000 barrels of liquids and 114 million cubic feet of natural gas per day.
Mafumeira Sul, the second development stage for the Mafumeira Field in Block 0, has a design capacity of 150,000 barrels of liquids and 350 million cubic feet of natural gas per day. Early production from the Mafumeira Sul Field commenced in October 2016 through a temporary production system. The main production facilities are expected to be completed and brought on line in first quarter 2017, and gas export to Angola LNG and water injection support are scheduled to begin in second quarter 2017. Ramp-up to full production is expected to continue through 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, with expected average total daily sales of 670 million cubic feet of natural gas and up to 63,000 barrels of NGLs. This is the world's first LNG plant supplied with associated gas, where the natural gas is a byproduct of crude oil production. Feedstock for the plant originates from multiple fields and operators. In early 2016, work was completed on plant modifications and capacity and reliability enhancements. Production restarted and LNG cargos resumed in 2016. Total daily production in 2016 averaged 171 million cubic feet of natural gas (62 million net) and 7,000 barrels of NGLs (3,000 barrels net).
The company also holds a 38.1 percent interest in the Congo River Canyon Crossing Pipeline project that is designed to transport up to 250 million cubic feet of natural gas per day from Block 0 and Block 14 to the Angola LNG Plant. Gas flow to the Angola LNG Plant commenced in September 2016.
Angola-Republic of Congo Joint Development Area Chevron operates and holds a 31.3 percent interest in the Lianzi Unitization Zone, located in an area shared equally by Angola and Republic of Congo. Development drilling was completed at Lianzi in January 2016.
Democratic Republic of the Congo Chevron has a 17.7 percent nonoperated working interest in an offshore concession. Net production in 2016 averaged 2,000 barrels of crude oil per day.
Republic of Congo Chevron has a 31.5 percent nonoperated working interest in the offshore Haute Mer permit areas (Nkossa, Nsoko and Moho-Bilondo). The licenses for Nsoko, Nkossa, and Moho-Bilondo expire in 2018, 2027 and 2030, respectively. Net production averaged 23,000 barrels of liquids per day in 2016.
In 2016, installation of a tension leg platform and a new FPU was completed and development drilling continued on the Moho Nord Project, located in the Moho-Bilondo development area. Total daily production in 2016 averaged 17,000 barrels of crude oil (5,000 barrels net).
Drilling on an exploration well in the Moho-Bilondo area was completed in January 2016, resulting in a crude oil discovery.
Liberia Chevron operates and holds a 45 percent interest in Block LB-14 off the coast of Liberia. Blocks LB-11 and LB-12 were relinquished in second quarter 2016.
Mauritania In June 2016, the company reassigned its interest in the C8, C12 and C13 contract areas offshore Mauritania to its partner.

11





Morocco After a farm-down in April 2016, the company holds a 45 percent interest in three operated deepwater areas offshore Morocco. The acquisition of 3-D seismic data in the Cap Cantin and Cap Walidia blocks was completed in 2016. The focus for 2017 is the evaluation of 3-D seismic data.
Nigeria Chevron holds a 40 percent interest in eight operated concessions in the onshore and near-offshore regions of the Niger Delta. The company also holds acreage positions in three operated and six nonoperated deepwater blocks, with working interests ranging from 20 percent to 100 percent. In 2016, the company’s net oil-equivalent production in Nigeria averaged 235,000 barrels per day, composed of 204,000 barrels of crude oil, 159 million cubic feet of natural gas and 4,000 barrels of liquefied petroleum gas.
Chevron operates and holds a 67.3 percent interest in the Agbami Field, located in deepwater Oil Mining Lease (OML) 127 and OML 128. The first two phases of infill drilling, Agbami 2 and Agbami 3, are nearly completed, with the last of the 15 wells expected to come on line in second-half 2017. More locations for infill drilling have been identified, and an ongoing program is underway to further offset field decline. The leases that contain the Agbami Field expire in 2023 and 2024.
Also in the deepwater area, the Aparo Field in OML 132 and OML 140 and the third-party-owned Bonga SW Field in OML 118 share a common geologic structure and are planned to be jointly developed. Chevron holds a 16.6 percent nonoperated working interest in the unitized area. The development plan involves subsea wells tied back to a floating production, storage and offloading vessel (FPSO). Spending is being paced until market conditions and reductions in project costs are sufficient to support the development of this project. At the end of 2016, 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. The company plans to continue evaluating development options for the discoveries in the Nsiko area. 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 Oil Prospecting License (OPL) 223. In 2016, one exploratory well was drilled in OML 139 resulting in a crude oil discovery at the Owowo prospect. In 2017, the company plans to continue evaluating developments options for the multiple discoveries in the Usan area.
In the Niger Delta region, 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 an 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. Optimization of these facilities continued during 2016. Construction activities also progressed during 2016 on the 40 percent-owned and operated Sonam Field Development Project, which is designed to process natural gas through the EGP facilities and is expected to deliver 215 million cubic feet of natural gas per day to the domestic market and produce a total of 30,000 barrels of liquids per day. Construction of offshore facilities continued in 2016. First production is expected in second-half 2017. Proved reserves have been recognized for the project.
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.
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 2016, net oil-equivalent production averaged 1,078,000 barrels per day.
Azerbaijan Chevron holds an 11.3 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 2024. Net oil-equivalent production in 2016 averaged 32,000 barrels per day, composed of 30,000 barrels of crude oil and 13 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 2016, WREP transported approximately 90,000 barrels per day from Baku, Azerbaijan, to a marine terminal at Supsa, Georgia.
Kazakhstan Chevron has a 50 percent interest in the Tengizchevroil (TCO) affiliate and an 18 percent nonoperated working interest in the Karachaganak Field. Net oil-equivalent production in 2016 averaged 410,000 barrels per day, composed of 322,000 barrels of liquids and 529 million cubic feet of natural gas.

12





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 2016 from these fields averaged 263,000 barrels of crude oil, 375 million cubic feet of natural gas and 22,000 barrels of NGLs. The majority of TCO’s crude oil production was exported through the Caspian Pipeline Consortium (CPC) pipeline that runs from Tengiz in Kazakhstan to tanker-loading facilities at Novorossiysk on the Russian coast of the Black Sea. The balance of production was exported by rail to Black Sea ports.
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 capacity and extend the production plateau from existing assets. The final investment decision for the FGP/WPMP was made in July 2016. Detailed design, fabrication, construction and mobilization activities are underway. First oil is planned for 2022. The initial recognition of proved reserves occurred in 2016 for the FGP. Proved reserves also have been recognized for the WPMP.
The Capacity and Reliability (CAR) Project is designed to reduce facility bottlenecks and increase plant capacity and reliability at Tengiz. Construction activities for the CAR Project progressed during 2016. Proved reserves have been recognized for the CAR Project.
The Karachaganak Field is located in northwest Kazakhstan, and operations are conducted under a PSC that expires in 2038. The development of the field is being conducted in phases. During 2016, net daily production averaged 37,000 barrels of liquids and 154 million cubic feet of natural gas. Most of the exported liquids were transported through the CPC pipeline. A portion was also exported via the Atyrau-Samara (Russia) Pipeline. The remaining liquids were sold into local and Russian markets. Work continues on identifying the optimal scope for the future expansion of the field. At year-end 2016, proved reserves had not been recognized for a future expansion.
Kazakhstan/Russia Chevron has a 15 percent interest in the CPC affiliate. During 2016, CPC transported an average of 959,000 barrels of crude oil per day, composed of 883,000 barrels per day from Kazakhstan and 76,000 barrels per day from Russia. In 2016, work continued on the expansion of the pipeline. By year-end 2016, capacity from Kazakhstan was increased to 1.0 million barrels per day. Additional capacity is scheduled to be added through mid-2017 to reach the design capacity of 1.4 million barrels per day. The expansion is expected to provide additional transportation capacity that accommodates a portion of the future growth in TCO production.
 Bangladesh Chevron operates and holds a 100 percent interest in Block 12 (Bibiyana Field) and Blocks 13 and 14 (Jalalabad and Moulavi Bazar fields). The rights to produce from Jalalabad expire in 2024, from Moulavi Bazar in 2028 and from Bibiyana in 2034. Net oil-equivalent production in 2016 averaged 114,000 barrels per day, composed of 658 million cubic feet of natural gas and 4,000 barrels of condensate. The company has announced its intent to divest its assets in Bangladesh.
Myanmar Chevron has a 28.3 percent nonoperated working interest in a PSC for the production of natural gas from the Yadana and Sein fields, within Blocks M5 and M6, in the Andaman Sea. The PSC expires in 2028. The company also has a 28.3 percent nonoperated interest in a pipeline company that transports most of the natural gas to the Myanmar-Thailand border for delivery to power plants in Thailand. Net natural gas production in 2016 averaged 128 million cubic feet per day.
The Badamyar-Low Compression Platform is an expansion project in Block M5 designed to maintain production from the Yadana Field by lowering wellhead pressure. Fabrication activities progressed in 2016, and first production is expected in second quarter 2017. Proved reserves have been recognized for this project.
Chevron also holds a 99 percent-owned and operated interest in Block A5. Evaluation of a 3-D seismic survey that was completed in December 2015 continued in 2016.
Thailand Chevron holds operated interests in the Pattani Basin, located in the Gulf of Thailand, with ownership ranging from 35 percent to 80 percent. Concessions for producing areas within this basin expire between 2020 and 2035. Chevron also has a 16 percent nonoperated working interest in the Arthit Field located in the Malay Basin. Concessions for the producing areas within this basin expire between 2036 and 2040. Net oil-equivalent production in 2016 averaged 245,000 barrels per day, composed of 71,000 barrels of crude oil and condensate and 1.1 billion cubic feet of natural gas.
In the Pattani Basin, the development concept of the 35 percent-owned and operated Ubon Project includes facilities and wells to develop resources in Block12/27. Discussions with key stakeholders on future development plans are ongoing. At the end of 2016, proved reserves had not been recognized for this project.

13





During 2016, the company drilled two exploration and two delineation wells in the Pattani Basin, and all wells were successful. The company also holds exploration interests in the Thailand-Cambodia overlapping claim area that are inactive, pending resolution of border issues between Thailand and Cambodia.
China Chevron has operated and nonoperated working interests in several areas in China. The company’s net daily production in 2016 averaged 18,000 barrels of crude oil and 51 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. Production commenced from the Xuanhan Gas Plant in January 2016. Total daily production in 2016 averaged 111 million cubic feet of natural gas (51 million net).
The company also has nonoperated working interests of 24.5 percent in the QHD 32-6 Field and 16.2 percent in Block 11/19 in the Bohai Bay, and 32.7 percent in Block 16/19 in the Pearl River Mouth Basin. The PSCs for these producing assets expire between 2022 and 2028.
Philippines The company holds a 45 percent nonoperated working interest in the Malampaya natural gas field, offshore Philippines. Net oil-equivalent production in 2016 averaged 26,000 barrels per day, composed of 138 million cubic feet of natural gas and 3,000 barrels of condensate.
Chevron holds a 40 percent interest in an affiliate that develops and produces onshore geothermal steam resources, which supplies steam to third-party power generation facilities with a combined operating capacity of 692 megawatts. The renewable energy service contract expires in 2038. Chevron also has an interest in the onshore Kalinga geothermal prospect area. In December 2016, the company signed an agreement to sell its geothermal interest in the Philippines. This transaction is expected to close in 2017.
Indonesia Chevron holds working interests through various PSCs in Indonesia. In Sumatra, the company holds a 100 percent-owned and operated interest in the Rokan PSC. Chevron also operates four PSCs in the Kutei Basin, located offshore eastern Kalimantan. These interests range from 62 percent to 92.5 percent. In addition, Chevron holds a 25 percent nonoperated working interest in Block B in the South Natuna Sea. Net oil-equivalent production in 2016 averaged 203,000 barrels per day, composed of 173,000 barrels of liquids and 182 million cubic feet of natural gas. In first quarter 2016, Chevron advised the government of Indonesia that it would not propose to extend the East Kalimantan PSC and intends to return the assets to the government upon PSC expiration in 2018. In December 2016, the company signed an agreement to sell its South Natuna Sea Block B assets. This transaction is expected to close in early 2017.
The largest producing field is Duri, located in the Rokan PSC. Duri has been under steamflood since 1985 and is one of the world’s largest steamflood developments. Infill drilling and workover programs continued in 2016.The Rokan PSC expires in 2021.
There are two deepwater natural gas development projects in the Kutei Basin progressing under a single plan of development. Collectively, these projects are referred to as the Indonesia Deepwater Development. One of these projects, Bangka, has a design capacity of 110 million cubic feet of natural gas and 4,000 barrels of condensate per day. The company’s interest is 62 percent. Production from Bangka commenced in August 2016 and has reached full design capacity.
The other project, Gendalo-Gehem, has a planned design capacity of 1.1 billion cubic feet of natural gas and 47,000 barrels of condensate per day. The company's interest is approximately 63 percent. The company continues to work toward a final investment decision, subject to the timing of government approvals, including extension of the associated PSCs, and securing new LNG sales contracts. At the end of 2016, proved reserves have not been recognized for this project.
In West Java, the company operates the Darajat geothermal field and holds a 95 percent interest in two power plants. The field supplies steam to a power plant with a total operating capacity of 270 megawatts. Chevron also operates and holds a 100 percent interest in the Salak geothermal field in West Java, which supplies steam to a six-unit power plant, three of which are company owned, with a total operating capacity of 377 megawatts. In December 2016, the company signed an agreement to sell its geothermal assets in Indonesia. This transaction is expected to close in 2017.
Kurdistan Region of Iraq The company operates and holds 80 percent contractor interests in the Sarta and Qara Dagh PSCs. The company completed a second exploration well in the Sarta Block in early 2016. Further evaluation of the block is planned. For the Qara Dagh PSC, the results from seismic acquisition and evaluation in 2015 improved the company's understanding of the prospects, and the company is evaluating next steps.
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

14





and equipment permits. As of early 2017, production remains shut-in, and the exact timing of a production restart is uncertain and dependent on dispute resolution between Saudi Arabia and Kuwait.
The shut-in also impacted plans for both the Wafra Steamflood Stage 1 Project, a full-field steamflood application in the Wafra Field First Eocene carbonate reservoir with a planned design capacity of 100,000 barrels of crude oil per day, and the Central Gas Utilization Project, a facility construction project intended to increase natural gas utilization while eliminating natural gas flaring at the Wafra Field. Both projects have been deferred pending dispute resolution between Saudi Arabia and Kuwait. At the end of 2016, proved reserves had not been recognized for these two projects.
In 2016, the company completed acquisition of a 3-D seismic survey covering the entire onshore Partitioned Zone. Processing of the newly acquired data is targeted to be completed in first-half 2017.
Australia/Oceania
In Australia/Oceania, the company is engaged in upstream activities in Australia and New Zealand. During 2016, net oil-equivalent production averaged 124,000 barrels per day, all from Australia.
Australia Upstream activities in Australia are concentrated offshore Western Australia, where the company is the operator of two major LNG projects, Gorgon and Wheatstone, and has a nonoperated working interest in the North West Shelf (NWS) Venture and exploration acreage in the Browse Basin and the Carnarvon Basin. The company also holds exploration acreage in the Bight Basin offshore South Australia. During 2016, the company's production averaged 21,000 barrels of liquids and 615 million cubic feet of natural gas per day.
Chevron holds a 47.3 percent interest in and is the operator of the Gorgon Project, which includes the development of the Gorgon and Jansz-Io fields. The project includes a three-train, 15.6 million-metric-ton-per-year LNG facility, a carbon dioxide injection facility and a domestic gas plant, which are located on Barrow Island, off Western Australia. The total production capacity for the project is approximately 2.6 billion cubic feet of natural gas and 20,000 barrels of condensate per day. LNG Train 1 start-up and first cargo shipment were achieved in March 2016, and Train 2 start-up was achieved in October 2016. Total daily production in 2016 from the Gorgon Project averaged 348 million cubic feet of natural gas (165 million net) and 3,000 barrels of condensate (1,000 barrels net). Train 3 commissioning activities are progressing, and start-up is expected in second quarter 2017. 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 offshore portion of the project includes subsea infrastructure, an offshore platform and pipelines. 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. Drilling, completion and initial testing of all nine production wells is complete. All modules for LNG Trains 1 and 2 have been delivered to site and installed on their foundations. Commissioning of subsea, platform and plant facilities is underway in preparation for LNG Train 1 start-up in mid-2017. Start-up of Train 2 is expected approximately six to eight months after Train 1. Proved reserves have been recognized for this project. The project's estimated economic life exceeds 30 years from the time of start-up.
Chevron has a 16.7 percent nonoperated working interest in the North West Shelf (NWS) Venture in Western Australia. The concession for the NWS Venture expires in 2034.
Chevron monetizes its Australia natural gas resources on a portfolio basis. Most of the company’s LNG production from Australia is committed under binding long-term agreements with major utilities in Asia, with the remainder sold on the Asian spot LNG market. Chevron continues to leverage its global portfolio supply position to target additional short-to-medium term agreements to reduce its exposure to the Asian spot LNG market. Chevron also has binding long-term agreements for delivery of natural gas to customers in Western Australia and continues to market additional pipeline natural gas quantities from the projects.
During 2016, Chevron continued to evaluate future exploration potential in the Carnarvon Basin.
The company holds nonoperated working interests ranging from 24.8 percent to 50 percent in three exploration blocks in the Browse Basin.
The company operates and holds a 100 percent interest in offshore Blocks EPP44 and EPP45 in the Bight Basin. Processing and interpretation of the 3-D seismic data acquired in 2015 continued through 2016.

15





New Zealand Chevron holds a 50 percent interest and operates three deepwater exploration permits in the offshore Pegasus and East Coast basins. Acquisition of 2-D and 3-D seismic data commenced in late 2016 and is expected to be completed in second quarter 2017.
Europe
In Europe, the company is engaged in upstream activities in Denmark, Norway and the United Kingdom. Net oil-equivalent production averaged 86,000 barrels per day during 2016.
Denmark Chevron holds a 12 percent nonoperated working interest in the Danish Underground Consortium (DUC), which produces crude oil and natural gas from 13 North Sea fields. The concession expires in 2042. Net oil-equivalent production in 2016 averaged 22,000 barrels per day, composed of 14,000 barrels of crude oil and 48 million cubic feet of natural gas.
United Kingdom The company’s net oil-equivalent production in 2016 averaged 64,000 barrels per day, composed of 43,000 barrels of liquids and 122 million cubic feet of natural gas. Most of the company's production was from three fields: the 85 percent-owned and operated Captain Field, the 23.4 percent-owned and operated Alba Field, and the 32.4 percent-owned and nonoperated Britannia Field.
The 73.7 percent-owned and operated Alder Project was developed as a tieback to the existing Britannia platform, and has a design capacity of 14,000 barrels of condensate and 110 million cubic feet of natural gas per day. First gas was achieved in November 2016, and production reached design capacity by year-end.
The Captain Enhanced Oil Recovery Project is the next development phase of the Captain Field and is designed to increase field recovery by injecting a polymer/water mixture. Front-end engineering and design (FEED) activities continued to progress in 2016 and included a polymer injection pilot. The company also began an expansion of the existing polymer injection system on the wellhead production platform. The scope includes six new polymer injection wells and modifications to the platform facilities. At the end of 2016, proved reserves had not been recognized for this project.
During 2016, installation and hook-up activities progressed for the Clair Ridge Project, located west of the Shetland Islands, in which the company has a 19.4 percent nonoperated working interest. The project is the second development phase of the Clair Field. The design capacity of the project is 120,000 barrels of crude oil and 100 million cubic feet of natural gas per day. First production is expected in 2018. The Clair Field has an estimated production life until 2050. Proved reserves have been recognized for the Clair Ridge Project.
At the 40 percent-owned and operated Rosebank Project northwest of the Shetland Islands, the company continued to progress FEED activities for a 17-well subsea development tied back to an FPSO with natural gas exported via pipeline. The design capacity of the project is 100,000 barrels of crude oil and 80 million cubic feet of natural gas per day. At the end of 2016, proved reserves had not been recognized for this project.
Norway In May 2016, the company acquired a 20 percent nonoperated working interest in exploration Block PL 859, located in the Barents Sea. Evaluation of the acreage is ongoing.
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 2016, U.S. and international sales of natural gas averaged 3 billion and 4.5 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 145,000 and 85,000 barrels per day, respectively, in 2016. 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 FS-12 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.

16






Downstream
Refining Operations
At the end of 2016, the company had a refining network capable of processing nearly 1.8 million barrels of crude oil per day. Operable capacity at December 31, 2016, and daily refinery inputs for 2014 through 2016 for the company and affiliate refineries are summarized in the table below.
Average crude oil distillation capacity utilization during 2016 was 92 percent, compared with 90 percent in 2015. At the U.S. refineries, crude oil distillation capacity utilization averaged 93 percent in 2016, compared with 96 percent in 2015. Chevron processes both imported and domestic crude oil in its U.S. refining operations. Imported crude oil accounted for about 76 percent and 74 percent of Chevron’s U.S. refinery inputs in 2016 and 2015, respectively.
In the United States, the company continued work on projects to improve refinery flexibility and reliability. At the Richmond, California refinery, the modernization project progressed with field construction activity restarted in 2016. At the Salt Lake City refinery, the company achieved a final investment decision on the alkylation retrofit project in September 2016, with construction expected to start in third quarter 2017. In November 2016, the company completed the sale of the Hawaii Refinery and related assets.
Outside the United States, the Singapore Refining Company, Chevron's 50 percent-owned joint venture, progressed construction of a gasoline desulfurization facility and a cogeneration plant. The utility systems and control center were fully commissioned in first quarter 2017, and Train 1 of the cogeneration plant is expected to be commissioned in second quarter 2017. This investment is expected to increase the refinery's capability to produce higher-value gasoline and improve energy efficiency. In addition, the company is evaluating sales of its refinery in British Columbia, Canada and its interests in the Cape Town Refinery in South Africa.
Petroleum Refineries: Locations, Capacities and Inputs
 
Capacities and inputs in thousands of barrels per day
December 31, 2016
 
Refinery Inputs
 
 
Locations
Number

Operable Capacity

2016

2015

2014

 
Pascagoula
Mississippi
1

330

355

322

329

 
El Segundo
California
1

291

267

258

221

 
Richmond
California
1

257

188

245

229

 
Kapolei1
Hawaii


37

47

47

 
Salt Lake City
Utah
1

53

53

52

45

 
Total Consolidated Companies — United States
4

931

900

924

871

 
Map Ta Phut2
Thailand
1

165

162

164

141

 
Cape Town3
South Africa
1

100

78

69

72

 
Burnaby, B.C.
Canada
1

55

51

46

49

 
Total Consolidated Companies — International
3

320

291

279

262

 
Affiliates
Various Locations
3

542

497

499

557

 
Total Including Affiliates — International
6

862

788

778

819

 
Total Including Affiliates — Worldwide
10

1,793

1,688

1,702

1,690

 
 
1 
In November 2016, the company sold the Hawaii Refinery.
2 
Chevron holds a 60.6 percent controlling interest in the Star Petroleum Refining Public Company Limited.
3 
Chevron holds a 75 percent controlling interest in the shares issued by Chevron South Africa (Pty) Limited, which owns the Cape Town Refinery. A consortium of South African partners, along with the employees of Chevron South Africa (Pty) Limited, own the remaining 25 percent.

17





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, 2016.
Refined Products Sales Volumes
Thousands of barrels per day
2016

2015

2014

 
United States
 
 
 
 
   Gasoline
631

621

615

 
   Jet Fuel
242

232

222

 
   Gas Oil and Kerosene
182

215

217

 
   Residual Fuel Oil
59

59

63

 
   Other Petroleum Products1
99

101

93

 
Total United States
1,213

1,228

1,210

 
International2
 
 
 
 
   Gasoline
382

389

403

 
   Jet Fuel
261

271

249

 
   Gas Oil and Kerosene
468

478

498

 
   Residual Fuel Oil
144

159

162

 
   Other Petroleum Products1 
207

210

189

 
Total International
1,462

1,507

1,501

 
Total Worldwide2 
2,675

2,735

2,711

 
1 Principally naphtha, lubricants, asphalt and coke.
 
 
2 Includes share of affiliates’ sales:
377

420

475

 
 In the United States, the company markets under the Chevron and Texaco brands. At year-end 2016, the company supplied directly or through retailers and marketers approximately 7,800 Chevron- and Texaco-branded motor vehicle service stations, primarily in the southern and western states. Approximately 325 of these outlets are company-owned or -leased stations.
Outside the United States, Chevron supplied directly or through retailers and marketers approximately 6,000 branded service stations, including affiliates. In British Columbia, Canada, the company markets under the Chevron brand. The company markets in Latin America using the Texaco brand. In the Asia-Pacific region, southern Africa and the Middle East, the company uses the Caltex brand. The company also operates through affiliates under various brand names. In South Korea, the company operates through its 50 percent-owned affiliate, GS Caltex. The company completed the sale of its New Zealand marketing and lubricants operations in June 2016. The company is evaluating the sale of its marketing and lubricants businesses in southern Africa. In addition, the company is evaluating the sale of its marketing assets in British Columbia and Alberta, Canada.
Chevron markets commercial aviation fuel at approximately 100 airports worldwide. The company also markets an extensive line of lubricant and coolant products under the product names Havoline, Delo, Ursa, Meropa, Rando, Clarity and Taro in the United States and worldwide under the three brands: Chevron, Texaco and Caltex.
Chemicals Operations
Chevron 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 2016, the company manufactured, blended or conducted research at 11 locations around the world. In 2016, the company progressed construction on a carboxylate plant in Singapore, which is scheduled to be completed in fourth quarter 2017. In 2016, design work continued for a planned manufacturing plant in Ningbo, China, with a final investment decision expected in 2018.
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 2016, CPChem owned or had joint-venture interests in 32 manufacturing facilities and two research and development centers around the world.
During 2016, construction activities continued on the U.S. Gulf Coast Petrochemicals Project, which is expected to capitalize on advantaged feedstock sourced from shale resource development in North America. The project includes an ethane cracker with an annual design capacity of 1.5 million metric tons of ethylene to be located at the Cedar Bayou facility and two polyethylene units to be located in Old Ocean, Texas, with a combined annual design capacity of one million metric tons. The polyethylene units are expected to start up mid-2017, and the ethane cracker in late 2017.

18





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.
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 12 and 13 in the Upstream section for information on the West African Gas Pipeline, the Baku-Tbilisi-Ceyhan Pipeline, the Western Route Export Pipeline and the Caspian Pipeline Consortium.
Shipping The company's marine fleet includes both U.S.- and foreign-flagged vessels. The U.S.-flagged vessels are engaged primarily in transporting refined products in the coastal waters of the United States. The foreign-flagged vessels transport crude oil, LNG, refined products and feedstocks in support of the company's global Upstream and Downstream businesses.
Four of the scheduled six new LNG carriers in support of the developing LNG portfolio are in service, with the final two scheduled for delivery in 2017.
Other Businesses
Research and Technology Chevron's energy technology organization supports upstream and downstream businesses. The company conducts research, develops and qualifies technology, and provides technical services and competency development. The disciplines cover earth sciences, reservoir and production engineering, drilling and completions, facilities engineering, manufacturing, process technology, catalysis, technical computing and health, environment and safety.
Chevron's information technology organization integrates computing, telecommunications, data management, cybersecurity and network technology to provide a digital infrastructure to enable Chevron’s global operations and business processes.
Chevron's technology ventures company supports Chevron's upstream and downstream businesses by bridging the gap between business unit needs and emerging technology solutions developed externally in areas of emerging materials, water management, information technology, power systems and production enhancement.
Some of the investments the company makes in the areas described above are in new or unproven technologies and business processes, and ultimate technical or commercial successes are not certain. Refer to Note 28 beginning on page FS-63 for a summary of the company's research and development expenses.
Environmental Protection The company designs, operates and maintains its facilities to avoid potential spills or leaks and to minimize the impact of those that may occur. Chevron requires its facilities and operations to have operating standards and processes and emergency response plans that address all credible and significant risks identified through site-specific risk and impact assessments. Chevron also requires that sufficient resources be available to execute these plans. In the unlikely event that a major spill or leak occurs, Chevron also maintains a Worldwide Emergency Response Team comprised of employees who are trained in various aspects of emergency response, including post-incident remediation.
To complement the company’s capabilities, Chevron maintains active membership in international oil spill response cooperatives, including the Marine Spill Response Corporation, which operates in U.S. territorial waters, and Oil Spill Response, Ltd., which operates globally. The company is a founding member of the Marine Well Containment Company, whose primary mission is to expediently deploy containment equipment and systems to capture and contain crude oil in the unlikely event of a future loss of control of a deepwater well in the Gulf of Mexico. In addition, the company is a member of the Subsea Well Response Project, 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 20 through 22 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 FS-18 for additional information on environmental matters and their impact on Chevron, and on the company's 2016 environmental expenditures. Refer to page FS-18 and Note 25 on page FS-61 for a discussion of environmental remediation provisions and year-end reserves.

19





Item 1A. Risk Factors
Chevron is a global energy company and its operating and financial results are subject to a variety of risks inherent in the global oil, gas, and petrochemical businesses. Many of these risks are not within the company's control and could materially impact the company’s results of operations and financial condition.
Chevron is exposed to the effects of changing commodity prices Chevron is primarily in a commodities business that has a history of price volatility. The single largest variable that affects the company’s results of operations is the price of crude oil, which can be influenced by general economic conditions, industry inventory levels, technology advancements, production quotas or other actions that might be imposed by the Organization of Petroleum Exporting Countries (OPEC), weather-related damage and disruptions, competing fuel prices, and geopolitical risks. Chevron evaluates the risk of changing commodity prices as part of its business planning process. An investment in the company carries significant exposure to fluctuations in global crude oil prices.
Extended periods of low prices for crude oil can have a material adverse impact on the company's results of operations, financial condition and liquidity. Among other things, the company’s upstream earnings, cash flows, and capital and exploratory expenditure programs could be negatively affected, as could its production and proved reserves. Upstream assets may also become impaired. Downstream earnings could be negatively affected because they depend upon the supply and demand for refined products and the associated margins on refined product sales. A significant or sustained decline in liquidity could adversely affect the company’s credit ratings, potentially increase financing costs and reduce access to debt markets. The company may be unable to realize anticipated cost savings, expenditure reductions and asset sales that are intended to compensate for such downturns. In some cases, liabilities associated with divested assets may return to the company when an acquirer of those assets subsequently declares bankruptcy. In addition, extended periods of low commodity prices can have a material adverse impact on the results of operations, financial condition and liquidity of the company’s suppliers, vendors, partners and equity affiliates upon which the company’s own results of operations and financial condition depends.
The scope of Chevron’s business will decline if the company does not successfully develop resources The company is in an extractive business; therefore, if it is not successful in replacing the crude oil and natural gas it produces with good prospects for future production or through acquisitions, the company’s business will decline. Creating and maintaining an inventory of projects depends on many factors, including obtaining and renewing rights to explore, develop and produce hydrocarbons; drilling success; ability to bring long-lead-time, capital-intensive projects to completion on budget and on schedule; and efficient and profitable operation of mature properties.
The company’s operations could be disrupted by natural or human causes beyond its control Chevron operates in both urban areas and remote and sometimes inhospitable regions. The company’s operations are therefore subject to disruption from natural or human causes beyond its control, including physical risks from hurricanes, severe storms, floods and other forms of severe weather, war, accidents, civil unrest, political events, fires, earthquakes, system failures, cyber threats and terrorist acts, any of which could result in suspension of operations or harm to people or the natural environment.
Chevron's risk management systems are designed to assess potential physical and other risks to its operations and assets and to plan for their resiliency. While capital investment reviews and decisions 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 cybersecurity and privacy from cyber threat actors, including criminal hackers, state-sponsored intrusions, industrial espionage and employee malfeasance. Although Chevron devotes significant resources to prevent unwanted intrusions and to protect its systems and data, 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 assets, access to its financial reporting systems, or loss, misuse or corruption of critical data and proprietary information, including intellectual property, business information and that of its employees, customers, partners and other third parties. 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

20





industry. The company seeks to minimize these operational risks by carefully designing and building its facilities and conducting its operations in a safe and reliable manner. However, failure to manage these risks effectively could impair our ability to operate and result in unexpected incidents, including releases, explosions or mechanical failures resulting in personal injury, loss of life, environmental damage, loss of revenues, legal liability and/or disruption to operations. Chevron has implemented and maintains a system of corporate policies, processes and systems, behaviors and compliance mechanisms to manage safety, health, environmental, reliability and efficiency risks; to verify compliance with applicable laws and policies; and to respond to and learn from unexpected incidents. In certain situations where Chevron is not the operator, the company may have limited influence and control over third parties, which may limit its ability to manage and control such risks.
Chevron’s business subjects the company to liability risks from litigation or government action The company produces, transports, refines and markets materials with potential toxicity, and it purchases, handles and disposes of other potentially toxic materials in the course of its business. Chevron's operations also produce byproducts, which may be considered pollutants. Often these operations are conducted through joint ventures over which the company may have limited influence and control. Any of these activities could result in liability or significant delays in operations arising from private litigation or government action, either as a result of an accidental, unlawful discharge or as a result of new conclusions about the effects of the company’s operations on human health or the environment. In addition, to the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to the company’s causation of or contribution to the asserted damage, or to other mitigating factors.
For information concerning some of the litigation in which the company is involved, including information relating to Ecuador matters, see Note 18 to the Consolidated Financial Statements, beginning on page FS-45.
The company does not insure against all potential losses, which could result in significant financial exposure The company does not have commercial insurance or third-party indemnities to fully cover all operational risks or potential liability in the event of a significant incident or series of incidents causing catastrophic loss. As a result, the company is, to a substantial extent, self-insured for such events. The company relies on existing liquidity, financial resources and borrowing capacity to meet short-term obligations that would arise from such an event or series of events. The occurrence of a significant incident or unforeseen liability for which the company is not fully insured or for which insurance recovery is significantly delayed could have a material adverse effect on the company’s results of operations or financial condition.
Political instability and significant changes in the regulatory environment could harm Chevron’s business The company’s operations, particularly exploration and production, can be affected by changing economic, regulatory and political environments in the various countries in which it operates. As has occurred in the past, actions could be taken by governments to increase public ownership of the company’s partially or wholly owned businesses or to impose additional taxes or royalties. In certain locations, governments have proposed or imposed restrictions on the company’s operations, export and exchange controls, burdensome taxes, and public disclosure requirements that might harm the company’s competitiveness or relations with other governments or third parties. In other countries, political conditions have existed that may threaten the safety of employees and the company’s continued presence in those countries, and internal unrest, acts of violence or strained relations between a government and the company or other governments may adversely affect the company’s operations. Those developments have, at times, significantly affected the company’s operations and results and are carefully considered by management when evaluating the level of current and future activity in such countries. In addition, changes in national, 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.  Such 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 global demand for oil to continue increasing until 2040, and even GHG-constrained scenarios (such as the IEA’s 450 case) anticipate significant demand for petroleum and natural gas 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 (e.g., the Paris Agreement and the Kyoto Protocol) and national (e.g., carbon tax, cap-and-trade or efficiency standards), regional and state legislation (e.g., California AB32 and SB32; low carbon fuel standards) and regulatory measures (e.g., the U.S. Environmental Protection Agency's methane performance standards) that aim to limit or reduce GHG

21





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 adopting policies to meet their Paris Agreement goals. In the United States, the company has been complying with currently implemented programs such as the federal Renewable Fuel Standard program, and related volume standards, and state regulations such as California AB32, including the cap-and-trade program and related low carbon fuel standard obligations. Follow-on legislation to California AB32, known as California SB32, was signed into law in 2016, with effect in 2020, and is currently in the scoping plan phase. Separately, other states and localities have also sought to directly regulate GHG emissions through mechanisms such as, for example, a carbon tax. Many of the foregoing are still in a proposal stage and others face legal challenge or legislative efforts to be repealed or significantly reformed. Thus, even with respect to existing regulatory compliance obligations, the landscape continues to be in a state of constant re-assessment and legal challenge, making it difficult to predict with certainty the ultimate impact that such regulations will have on the company.
GHG emissions-related laws and related regulations and the effects of operating in a potentially carbon-constrained environment may result in increased and substantial capital, compliance, operating and maintenance costs and could, among other things, reduce demand for hydrocarbons and the company’s hydrocarbon-based products, make the company’s products more expensive, adversely affect the economic feasibility of the company’s resources, and adversely affect the company’s sales volumes, revenues and margins. GHG emissions (e.g., carbon dioxide and methane) that could be regulated include, among others, those associated with the company’s exploration and production of hydrocarbons such as crude oil and natural gas; the upgrading of production from oil sands into synthetic oil; power generation; the conversion of crude oil and natural gas into refined hydrocarbon products; the processing, liquefaction and regasification of natural gas; the transportation of crude oil, natural gas and related products and consumers’ or customers’ use of the company’s hydrocarbon products. Many of these activities, such as consumers’ and customers’ use of the company’s products, as well as actions taken by the company’s competitors in response to such laws and regulations, are beyond the company’s control. In addition, increasing attention to climate change risks has resulted in an increased possibility of governmental investigations and, potentially, 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 greenhouse gas emissions reductions required, the extent to which Chevron would be entitled to receive emission allowance allocations or would need to purchase compliance instruments on the open market or through auctions, the price and availability of emission allowances and credits, and the 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.

22






Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
The location and character of the company’s crude oil and natural gas properties and its refining, marketing, transportation and chemicals facilities are described on page 3 under Item 1. Business. Information required by Subpart 1200 of Regulation S-K (“Disclosure by Registrants Engaged in Oil and Gas Producing Activities”) is also contained in Item 1 and in Tables I through VII on pages FS-65 through FS-75. Note 17, “Properties, Plant and Equipment,” to the company’s financial statements is on page FS-44.
Item 3. Legal Proceedings
Governmental Proceedings As initially disclosed in the Annual Report on Form 10-K for the year ended December 31, 2013, on August 6, 2012, a piping failure and fire occurred at the Chevron refinery in Richmond, California. Various federal, state, and local agencies initiated investigations as a result of the incident. Based on a civil investigation conducted pursuant to its authority under the Clean Air Act Risk Management Plan program (RMP), the United States Environmental Protection Agency (EPA) issued alleged findings of violation to Chevron’s Richmond refinery on December 17, 2013. The California Division of Occupational Safety and Health (Cal/OSHA) also issued citations related to the incident. Following the Richmond fire, EPA conducted RMP inspections at Chevron’s El Segundo, California; Pascagoula, Mississippi; Kapolei, Hawaii; and Salt Lake City, Utah refineries. With the participation of the United States Department of Justice, Chevron and EPA are negotiating a potential combined resolution that may include all of EPA’s alleged findings of violation related to the Richmond fire and subsequent RMP inspections. Resolution of the alleged findings of violation may result in the payment of a civil penalty of $100,000 or more. Chevron and Cal/OSHA are separately negotiating a potential resolution of Cal/OSHA’s citations related to the incident.
Chevron facilities within the jurisdiction of California’s South Coast Air Quality Management District (SCAQMD) currently have multiple outstanding Notices of Violation (NOVs) issued by SCAQMD. Resolution of the alleged violations may result in the payment of a civil penalty of $100,000 or more. As initially disclosed in the Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, in April 2016, Chevron received a proposal from the SCAQMD seeking to collectively resolve certain NOVs issued in 2012 and 2013 to Chevron’s El Segundo refinery. Subsequently, the SCAQMD provided notice to Chevron that it was also seeking to resolve certain NOVs issued to the refinery in 2014. Chevron and the SCAQMD are negotiating a potential combined resolution of the 2012-2014 NOVs. Collective resolution of these NOVs may result in the payment of a civil penalty of $100,000 or more.
Chevron facilities within the jurisdiction of California’s Bay Area Air Quality Management District (BAAQMD) currently have multiple outstanding NOVs issued by BAAQMD. Resolution of the alleged violations may result in the payment of a civil penalty of $100,000 or more. On December 7, 2016, Chevron received a proposal from the BAAQMD seeking to collectively resolve certain NOVs issued in 2013-2015 to Chevron’s Richmond refinery and to Chevron’s Richmond, California and San Jose, California marketing terminals. Chevron and the BAAQMD are negotiating a potential combined resolution of the 2013-2015 NOVs. Collective resolution of these NOVs may result in the payment of a civil penalty of $100,000 or more.
On December 5, 2016, Chevron received a NOV from the California Air Resources Board (CARB) alleging that for compliance years 2011-2015, Chevron failed to deduct some exported volumes of fuel from the sales that must be reported under the state’s Low Carbon Fuel Standard (LCFS) program. The allegation is that Chevron purchased and retired more LCFS credits than were required. Chevron and CARB are negotiating a potential resolution of the alleged violation. Resolution of this NOV may result in the payment of a civil penalty of $100,000 or more.
Other Proceedings Information related to other legal proceedings, including Ecuador, is included beginning on page FS-45 in Note 18 to the Consolidated Financial Statements.
Item 4. Mine Safety Disclosures
Not applicable.






23





PART II
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
The information on Chevron’s common stock market prices, dividends, principal exchanges on which the stock is traded and number of stockholders of record is contained in the Quarterly Results and Stock Market Data tabulations, on page FS-22.
Chevron Corporation Issuer Purchases of Equity Securities for Quarter Ended December 31, 2016
 
 
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, 2016
169


$102.44



Nov. 1 – Nov. 30, 2016




Dec. 1 – Dec. 31, 2016
2,840


$113.29



Total Oct. 1 – Dec. 31, 2016
3,009


$112.68



1 
Includes common shares repurchased from company employees and directors for required personal income tax withholdings on the exercise of the stock options and shares delivered or attested to in satisfaction of the exercise price by holders of the employee and director stock options. The options were issued to and exercised by management under Chevron long-term incentive plans.
2 
In July 2010, the Board of Directors approved an ongoing share repurchase program with no set term or monetary limits, under which common shares would be acquired by the company through open market purchases or in negotiated transactions at prevailing prices, as permitted by securities laws and other legal requirements and subject to market conditions and other factors. From inception of the program through 2014, the company had purchased 180,886,291 shares under this program (some pursuant to a Rule 10b5-1 plan and some pursuant to accelerated share repurchase plans) for $20 billion at an average price of approximately $111 per share. The company did not acquire any shares under the program in 2015 or 2016.
Item 6. Selected Financial Data
The selected financial data for years 2012 through 2016 are presented on page FS-64.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The index to Management’s Discussion and Analysis of Financial Condition and Results of Operations, Consolidated Financial Statements and Supplementary Data is presented on page FS-1.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The company’s discussion of interest rate, foreign currency and commodity price market risk is contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations — “Financial and Derivative Instrument Market Risk,” on page FS-16 and in Note 11 to the Consolidated Financial Statements, “Financial and Derivative Instruments,” beginning on page FS-38.
Item 8. Financial Statements and Supplementary Data
The index to Management’s Discussion and Analysis, Consolidated Financial Statements and Supplementary Data is presented on page FS-1.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.

24





Item 9A. Controls and Procedures
(a) Evaluation of Disclosure Controls and Procedures The company’s management has evaluated, with the participation of the Chief Executive Officer and the Chief Financial Officer, the effectiveness of the company’s disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)) as of the end of the period covered by this report. Based on this evaluation, management concluded that the company’s disclosure controls and procedures were effective as of December 31, 2016.
(b) Management’s Report on Internal Control Over Financial Reporting The company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f) and 15d-15(f). The company’s management, including the Chief Executive Officer and the Chief Financial Officer, conducted an evaluation of the effectiveness of the company’s internal control over financial reporting based on the Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on the results of this evaluation, the company’s management concluded that internal control over financial reporting was effective as of December 31, 2016.
The effectiveness of the company’s internal control over financial reporting as of December 31, 2016, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report included on page FS-24.
(c) Changes in Internal Control Over Financial Reporting During the quarter ended December 31, 2016, 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
Rule 10b5-1 Plan Elections
R. Hewitt Pate, Vice President and General Counsel, entered into a pre-arranged stock trading plan in November 2016. Mr. Pate’s plan provides for the potential exercise of vested stock options and the associated sale of up to 51,000 shares of Chevron common stock between February 2017 and November 2017.
This trading plan was entered into during an open insider trading window and is intended to satisfy Rule 10b5-1(c) of the Securities Exchange Act of 1934, as amended, and Chevron’s policies regarding transactions in Chevron securities.



25





PART III
Item 10. Directors, Executive Officers and Corporate Governance
Executive Officers of the Registrant at February 23, 2017
Members of the Corporation's Executive Committee are the Executive Officers of the Corporation:
Name
Age
Current and Prior Positions (up to five years)
Current Areas of Responsibility
J.S. Watson
60
Chairman of the Board and Chief Executive Officer (since 2010)
Chairman of the Board and
Chief Executive Officer
M.K. Wirth
56
Vice Chairman of the Board and Executive Vice President (since February 2017)
Executive Vice President, Midstream and Development (February 2016 through January 2017)
Executive Vice President, Downstream (2006 through 2015)
Corporate Strategy; Corporate Business Development; Policy, Government and Public Affairs; Supply and Trading Activities; Shipping; Pipeline; Power and Energy Management
J.W. Johnson
57
Executive Vice President, Upstream (since 2015)
Senior Vice President, Upstream (2014)
President, Europe, Eurasia and Middle East Exploration and
Production (2011 through 2013)
Managing Director, Eurasia Business Unit (2008 to 2011)
Worldwide Exploration and Production Activities
P.R. Breber
52
Executive Vice President, Downstream (since 2016)
Corporate Vice President and President, Gas and Midstream
   (2014 through 2015)
Managing Director, Asia South Business Unit (2012 through 2013)
Deputy Managing Director, Asia South Business Unit (2011)
Vice President and Treasurer (2009 to 2011)
Worldwide Refining, Marketing and Lubricants; Chemicals

J.C. Geagea
57
Executive Vice President, Technology, Projects and Services
   (since 2015)
Senior Vice President, Technology, Projects and Services (2014)
Corporate Vice President and President, Gas and Midstream
(2012 through 2013)
Managing Director, Asia South Business Unit (2008 through 2011)
Technology; Health, Environment and Safety; Project Resources Company; Procurement
P.E. Yarrington
60
Vice President and Chief Financial Officer (since 2009)
Finance
R.H. Pate
54
Vice President and General Counsel (since 2009)
Law, Governance and Compliance
 
The information about directors required by Item 401 (a), (d), (e) and (f) of Regulation S-K and contained under the heading “Election of Directors” in the Notice of the 2017 Annual Meeting of Stockholders and 2017 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 2017 Annual Meeting (the “2017 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 2017 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 2017 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 2017 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

26





Item 11. Executive Compensation
The information required by Item 402 of Regulation S-K and contained under the headings “Executive Compensation” and “Director Compensation” in the 2017 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 2017 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 2017 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 2017 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 2017 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 2017 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 2017 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 2017 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 2017" in the 2017 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

27





PART IV
Item 15. Exhibits, Financial Statement Schedules
(a)
The following documents are filed as part of this report:
(1) Financial Statements:
 

(2) Financial Statement Schedules:
Included below is Schedule II - Valuation and Qualifying Accounts.
(3) Exhibits:
The Exhibit Index on pages E-1 through E-2 lists the exhibits that are filed as part of this report.
Schedule II — Valuation and Qualifying Accounts
 
Year ended December 31
 
Millions of Dollars
2016

2015

2014

Employee Termination Benefits
 
 
 
Balance at January 1
$
308

$
49

$
14

Additions (reductions) charged to expense
160

342

53

Payments
(357
)
(83
)
(18
)
Balance at December 31
$
111

$
308

$
49

Allowance for Doubtful Accounts
 
 
 
Balance at January 1
$
429

$
194

$
95

Additions to expense
76

251

119

Bad debt write-offs
(18
)
(16
)
(20
)
Balance at December 31
$
487

$
429

$
194

Deferred Income Tax Valuation Allowance* 
 
 
 
Balance at January 1
$
15,412

$
16,292

$
17,171

Additions to deferred income tax expense
1,810

1,440

1,192

Reduction of deferred income tax expense
(1,153
)
(2,320
)
(2,071
)
Balance at December 31
$
16,069

$
15,412

$
16,292

 * See also Note 19 to the Consolidated Financial Statements, beginning on page FS-49.

Item 16. Form 10-K Summary
Not applicable.

28






Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 23rd day of February, 2017.
 
 Chevron Corporation
 
By
/s/ JOHN S. WATSON
 
John S. Watson, Chairman of the Board
and Chief Executive Officer

 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on the 23rd day of February, 2017.
 
Principal Executive Officer
(and Director)
 
/s/ JOHN S. WATSON 
John S. Watson, Chairman of the
Board and Chief Executive Officer
 
 
Principal Financial Officer
 
/s/ PATRICIA E. YARRINGTON 
Patricia E. Yarrington, Vice President
and Chief Financial Officer
 
Principal Accounting Officer
 
/s/ JEANETTE L. OURADA 
Jeanette L. Ourada, Vice President
and Comptroller
 
*By: /s/ MARY A. FRANCIS 
Mary A. Francis,
Attorney-in-Fact










 
Directors
 
WANDA M. AUSTIN* 
Wanda M. Austin
 
LINNET F. DEILY* 
Linnet F. Deily
 
ROBERT E. DENHAM* 
Robert E. Denham
 
ALICE P. GAST* 
Alice P. Gast
 
ENRIQUE HERNANDEZ, JR.* 
Enrique Hernandez, Jr.
 
JON M. HUNTSMAN JR.* 
Jon M. Huntsman Jr.
 
CHARLES W. MOORMAN IV* 
Charles W. Moorman IV
 
DAMBISA F. MOYO*
Dambisa F. Moyo
 
RONALD D. SUGAR*
Ronald D. Sugar
 
INGE G. THULIN* 
Inge G. Thulin

 
/s/ MICHAEL K. WIRTH
Michael K. Wirth, Vice Chairman
of the Board and
 Executive Vice President
 
 



29
































THIS PAGE INTENTIONALLY LEFT BLANK


30


Financial Table of Contents


 
 
 
 
FS-2
 
 
 
 
 
 
 
FS--2
 
FS--2
 
FS--2
 
FS--6
 
FS--6
 
FS--9
 
FS--12
 
FS--13
 
FS--15
 
Off-Balance-Sheet Arrangements, Contractual Obligations,
    Guarantees and Other Contingencies
FS--15
 
FS--16
 
FS--17
 
FS--17
 
FS--18
 
FS--18
 
FS--21
 
FS--22
 
 
 
 
 
 
 
FS-21
 
 
 
 
 
 
 
Consolidated Financial Statements
 
 
FS--23
 
FS--24
 
FS--25
 
FS--26
 
FS--27
 
FS--28
 
FS--29
 
 
 
 
 
 
 
FS-28
 
 
 
 
 
FS--30
Changes in Accumulated Other
    Comprehensive Losses
FS--32
FS--33
 
 
FS--33
FS--34
FS--35
FS--36
FS--36
Summarized Financial Data - Chevron Phillips
Chemical Company LLC
FS--36
FS--37
FS--38
Assets Held for Sale
FS--39
FS--39
Note 14
FS--39
Note 15
FS--40
Note 16
FS--43
Note 17
FS--44
Note 18
FS--45
Note 19
FS--49
Note 20
FS--52
Note 21
FS--53
Note 22
FS--54
Note 23
FS--55
Note 24
FS--56
Note 25
FS--61
Note 26
FS--62
Note 27
Restructuring and Reorganization Costs
FS--63
Note 28
FS--63
 
 
 
FS--64
FS--65
 
 


FS--1


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

Key Financial Results
Millions of dollars, except per-share amounts
2016

 
2015

 
2014

Net Income (Loss) Attributable to Chevron Corporation
$
(497
)
 
$
4,587

 
$
19,241

Per Share Amounts:


 

 

Net Income (Loss) Attributable to Chevron Corporation


 

 

– Basic
$
(0.27
)
 
$
2.46

 
$
10.21

– Diluted
$
(0.27
)
 
$
2.45

 
$
10.14

Dividends
$
4.29

 
$
4.28

 
$
4.21

Sales and Other Operating Revenues
$
110,215

 
$
129,925

 
$
200,494

Return on:


 

 

Capital Employed
(0.1
)%
 
2.5
%
 
10.9
%
Stockholders’ Equity
(0.3
)%
 
3.0
%
 
12.7
%
Earnings by Major Operating Area
Millions of dollars
2016

 
2015

 
2014

Upstream
 
 
 
 
 
United States
$
(2,054
)
 
$
(4,055
)
 
$
3,327

International
(483
)
 
2,094

 
13,566

Total Upstream
(2,537
)
 
(1,961
)
 
16,893

Downstream
 
 
 
 
 
United States
1,307

 
3,182

 
2,637

International
2,128

 
4,419

 
1,699

Total Downstream
3,435

 
7,601

 
4,336

All Other
(1,395
)
 
(1,053
)
 
(1,988
)
Net Income (Loss) Attributable to Chevron Corporation1,2
$
(497
)
 
$
4,587

 
$
19,241

1  Includes foreign currency effects:
$
58

 
$
769

 
$
487

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 FS-6 for a discussion of financial results by major operating area for the three years ended December 31, 2016.

Business Environment and Outlook
Chevron is a global energy company with substantial business activities in the following countries: Angola, Argentina, Australia, Azerbaijan, Bangladesh, Brazil, Canada, China, Colombia, Democratic Republic of the Congo, Denmark, Indonesia, Kazakhstan, Myanmar, Nigeria, the Partitioned Zone between Saudi Arabia and Kuwait, the Philippines, Republic of Congo, Singapore, South Africa, South Korea, Thailand, Trinidad and Tobago, the United Kingdom, the United States, and Venezuela.
Earnings of the company depend mostly on the profitability of its upstream business segment. The biggest factor affecting the results of operations for the upstream segment is the price of crude oil. The price of crude oil has fallen significantly since mid-year 2014, reflecting persistently high global crude oil inventories and production. The downturn in the price of crude oil has impacted, and, depending upon its duration, will continue to significantly impact the company's results of operations, cash flows, leverage, capital and exploratory investment program and production outlook. The company is responding with reductions in operating expenses, including employee reductions, pacing and re-focusing of capital and exploratory expenditures , and increased asset sales. The company anticipates that crude oil prices will increase in the future, as continued growth in demand and a slowing in supply growth should bring global markets into balance; however, the timing of any such increase is unknown. In the company's downstream business, crude oil is the largest cost component of refined products. It is the company's objective to deliver competitive results and shareholder value in any business environment.
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 19 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 20 through 22 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

FS--2


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

value growth. Refer to the “Results of Operations” section beginning on page FS-6 for discussions of net gains on asset sales during 2016. Asset dispositions and restructurings may also occur in future periods and could result in significant gains or losses.
The company closely monitors developments in the financial and credit markets, the level of worldwide economic activity, and the implications for the company of movements in prices for crude oil and natural gas. Management takes these developments into account in the conduct of daily operations and for business planning.
Comments related to earnings trends for the company’s major business areas are as follows:
Upstream Earnings for the upstream segment are closely aligned with industry prices for crude oil and natural gas. Crude oil and natural gas prices are subject to external factors over which the company has no control, including product demand connected with global economic conditions, industry inventory levels, technology advancements, production quotas or other actions imposed by the Organization of Petroleum Exporting Countries (OPEC), actions of regulators, weather-related damage and disruptions, competing fuel prices, and regional supply interruptions or fears thereof that may be caused by military conflicts, civil unrest or political uncertainty. Any of these factors could also inhibit the company’s production capacity in an affected region. The company closely monitors developments in the countries in which it operates and holds investments, and seeks to manage risks in operating its facilities and businesses. The longer-term trend in earnings for the upstream segment is also a function of other factors, including the company’s ability to find or acquire and efficiently produce crude oil and natural gas, changes in fiscal terms of contracts, and changes in tax laws and regulations.
The company continues to actively manage its schedule of work, contracting, procurement and supply-chain activities to effectively manage costs. However, price levels for capital and exploratory costs and operating expenses associated with the production of crude oil and natural gas can be subject to external factors beyond the company’s control including, among other things, the general level of inflation, commodity prices and prices charged by the industry’s material and service providers, which can be affected by the volatility of the industry’s own supply-and-demand conditions for such materials and services. As a result of the decline in prices of crude oil and other commodities since mid-2014, these costs have declined. Capital and exploratory expenditures and operating expenses can also be affected by damage to production facilities caused by severe weather or civil unrest, delays in construction, or other factors.
http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=11416866&doc=27
The chart above shows the trend in benchmark prices for Brent crude oil, West Texas Intermediate (WTI) crude oil and U.S. Henry Hub natural gas. The Brent price averaged $44 per barrel for the full-year 2016, compared to $52 in 2015. As of mid-February 2017, the Brent price was $55 per barrel. The majority of the company’s equity crude production is priced based on the Brent benchmark. Crude oil prices remained low through much of 2016, but increased modestly late in the year after OPEC announced production cuts. On November 30, 2016, OPEC agreed to cap production at 32.5 million barrels per day starting in January 2017.
The WTI price averaged $43 per barrel for the full-year 2016, compared to $49 in 2015. As of mid-February 2017, the WTI price was $53 per barrel. WTI traded at a discount to Brent for much of 2016 due to high inventories and excess crude supply in the U.S. market.

FS--3


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

A differential in crude oil prices exists between high-quality (high-gravity, low-sulfur) crudes and those of lower quality (low-gravity, high-sulfur). The amount of the differential in any period is associated with the relative supply/demand balances for each crude type, which are functions of the capacity of refineries that are able to process each as feedstock into high-value light products (motor gasoline, jet fuel, aviation gasoline and diesel fuel). In second-half 2016, the differential held generally steady in North America as robust refinery demand supported heavy crude values, while light sweet crude prices in the U.S. were supported by slowing domestic production. Outside of North America, differentials were steady to slightly wider amid well-supplied light sweet crude markets in the Atlantic Basin, while continued robust Middle East exports and rising Iranian production kept pressure on heavier, more sour crudes. Differentials widened in December as light sweet crude values benefited more from the announced OPEC deal.
Chevron produces or shares in the production of heavy crude oil in California, Indonesia, the Partitioned Zone between Saudi Arabia and Kuwait, Venezuela and in certain fields in Angola, China and the United Kingdom sector of the North Sea. (See page FS-12 for the company’s average U.S. and international crude oil realizations.)
In contrast to price movements in the global market for crude oil, price changes for natural gas in many regional markets are more closely aligned with supply-and-demand conditions in those markets. Fluctuations in the price of natural gas in the United States are closely associated with customer demand relative to the volumes produced and stored in North America. In the United States, prices at Henry Hub averaged $2.46 per thousand cubic feet (MCF) during 2016, compared with $2.62 during 2015. As of mid-February 2017, the Henry Hub spot price was $2.86 per MCF.
Outside the United States, price changes for natural gas depend on a wide range of supply, demand and regulatory circumstances. Chevron sells natural gas into the domestic pipeline market in most locations. In some locations, Chevron continues to invest in long-term projects to install infrastructure to produce and liquefy natural gas for transport by tanker to other markets. The company's long-term contract prices for liquefied natural gas (LNG) are typically linked to crude oil prices. 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 $4.02 per MCF during 2016, compared with $4.53 per MCF during 2015. (See page FS-12 for the company’s average natural gas realizations for the U.S. and international regions.)
The company’s worldwide net oil-equivalent production in 2016 averaged 2.594 million barrels per day. About one-sixth of the company’s net oil-equivalent production in 2016 occurred in the OPEC-member countries of Angola, Nigeria and Venezuela. OPEC quotas had no effect on the company’s net crude oil production in 2016 or 2015.
The company estimates that net oil-equivalent production in 2017 will grow 4 to 9 percent compared to 2016, assuming a Brent crude oil price of $50 per barrel and before the effect of anticipated asset sales.  The impact of 2017 asset sales on full-year production is expected to be in the range of 50,000 to 100,000 barrels of oil-equivalent per day, depending on the timing of the close of individual transactions. This estimate is subject to many factors and uncertainties, including the duration of the low price environment that began in second-half 2014; quotas or other actions that may be imposed by OPEC; price effects on entitlement volumes; changes in fiscal terms or restrictions on the scope of company operations; delays in construction, start-up or ramp-up of projects; fluctuations in demand for natural gas in various markets; weather conditions that may shut in production; civil unrest; changing geopolitics; delays in completion of maintenance turnarounds; greater-than-expected declines in production from mature fields; or other disruptions to operations. The outlook for future production levels is also affected by the size and number of economic investment opportunities and, for new, large-scale projects, the time lag between initial exploration and the beginning of production. Investments in upstream projects generally begin well in advance of the start of the associated crude oil and natural gas production. A significant majority of Chevron’s upstream investment is made outside the United States.


FS--4


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

http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=11416866&doc=30
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 2017, 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 2016 were not significant and are not expected to be significant in 2017.
Net proved reserves for consolidated companies and affiliated companies totaled 11.1 billion barrels of oil-equivalent at year-end 2016, down slightly from year-end 2015. The reserve replacement ratio in 2016 was 95 percent. Refer to Table V beginning on page FS-69 for a tabulation of the company’s proved net oil and gas reserves by geographic area, at the beginning of 2014 and each year-end from 2014 through 2016, and an accompanying discussion of major changes to proved reserves by geographic area for the three-year period ending December 31, 2016.
Refer to the “Results of Operations” section on pages FS-6 through FS-9 for additional discussion of the company’s upstream business.
Downstream Earnings for the downstream segment are closely tied to margins on the refining, manufacturing and marketing of products that include gasoline, diesel, jet fuel, lubricants, fuel oil, fuel and lubricant additives, and petrochemicals. Industry margins are sometimes volatile and can be affected by the global and regional supply-and-demand balance for refined products and petrochemicals, and by changes in the price of crude oil, other refinery and petrochemical feedstocks, and natural gas. Industry margins can also be influenced by inventory levels, geopolitical events, costs of materials and services, refinery or chemical plant capacity utilization, maintenance programs, and disruptions at refineries or chemical plants resulting from unplanned outages due to severe weather, fires or other operational events.
Other factors affecting profitability for downstream operations include the reliability and efficiency of the company’s refining, marketing and petrochemical assets, the effectiveness of its crude oil and product supply functions, and the volatility of tanker-charter rates for the company’s shipping operations, which are driven by the industry’s demand for crude oil and product tankers. Other factors beyond the company’s control include the general level of inflation and energy costs to operate the company’s refining, marketing and petrochemical assets.
The company’s most significant marketing areas are the West Coast of North America, the U.S. Gulf Coast, Asia and southern Africa. Chevron operates or has significant ownership interests in refineries in each of these areas.
Refer to the “Results of Operations” section on pages FS-6 through FS-9 for additional discussion of the company’s downstream operations.

FS--5


Management's Discussion and Analysis of Financial Condition and Results of 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 2016 and early 2017 included the following:
Upstream
Angola Restarted LNG production and cargo shipments at the Angola LNG plant.
Australia Achieved start-up of Trains 1 and 2 at the Gorgon Project and progressed commissioning of Train 3.
Progressed commissioning and testing of subsea and platform facilities and production wells at the Wheatstone Project. Progressed commissioning of LNG Train 1 and common facilities, and received and installed all Train 2 modules at the site.
Indonesia Commenced production at the Bangka Field, the first stage of the Indonesia Deepwater Development.
Reached agreement to sell the company's geothermal assets.
Kazakhstan Announced final investment decision on the Future Growth and Wellhead Pressure Management Project at the company's 50 percent-owned affiliate, Tengizchevroil, which is expected to increase crude oil production at the Tengiz Field by about 260,000 barrels per day and maintain production levels as reservoir pressure declines.
Philippines Reached agreement to sell the company's geothermal assets.
United Kingdom Announced first gas from the Alder Field in the Central North Sea.
Downstream
Completed the sales of the company's marketing and lubricants assets in New Zealand, and its refining and marketing assets in Hawaii.
Other
Common Stock Dividends The quarterly common stock dividend was increased by $0.01 per share in October 2016, making 2016 the 29th consecutive year that the company increased its annual dividend payout.
Results of Operations
The following section presents the results of operations and variances on an after-tax basis for the company’s business segments – Upstream and Downstream – as well as for “All Other.” Earnings are also presented for the U.S. and international geographic areas of the Upstream and Downstream business segments. Refer to Note 15, beginning on page FS-40, for a discussion of the company’s “reportable segments.” This section should also be read in conjunction with the discussion in “Business Environment and Outlook” on pages FS-2 through FS-6.

FS--6


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

http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=11416866&doc=28
U.S. Upstream
Millions of dollars
2016

 
 
2015

 
2014

Earnings
$
(2,054
)
 
 
$
(4,055
)
 
$
3,327

U.S. upstream operations incurred a loss of $2.05 billion in 2016 compared to a loss of $4.06 billion in 2015. The improvement was due to lower depreciation expense of $1.2 billion and lower exploration expense of $780 million primarily reflecting a decrease in impairments and project cancellations. Also contributing to the improvement were lower operating expenses of $600 million and lower tax items of $190 million. Partially offsetting these effects were lower crude oil and natural gas realizations of $920 million.
U.S. upstream operations incurred a loss of $4.06 billion in 2015 compared to earnings of $3.33 billion from 2014. The decrease was primarily due to lower crude oil and natural gas realizations of $4.86 billion and $570 million, respectively, higher depreciation expenses of $2.19 billion, and higher exploration expenses of $650 million. The increase in depreciation and exploration expenses was primarily due to impairments and project cancellations. Lower gains on asset sales also contributed to the decrease with 2015 gains of $110 million compared with $700 million in 2014. Partially offsetting these effects were higher crude oil production of $900 million and lower operating expenses of $450 million.
The company’s average realization for U.S. crude oil and natural gas liquids in 2016 was $35.00 per barrel, compared with $42.70 in 2015 and $84.13 in 2014. The average natural gas realization was $1.59 per thousand cubic feet in 2016, compared with $1.92 in 2015 and $3.90 in 2014.
Net oil-equivalent production in 2016 averaged 691,000 barrels per day, down 4 percent from 2015 and up 4 percent from 2014. Between 2016 and 2015, production increases from shale and tight properties in the Permian Basin in Texas and New Mexico, and base business were more than offset by the effect of asset sales and normal field declines. Between 2015 and 2014, production increases due to project ramp-ups in the Gulf of Mexico and the Permian Basin in Texas and New Mexico were partially offset by the effect of asset sales and normal field declines.
The net liquids component of oil-equivalent production for 2016 averaged 504,000 barrels per day, up 1 percent from 2015 and 11 percent from 2014. Net natural gas production averaged about 1.1 billion cubic feet per day in 2016, down 15 percent from 2015 and 10 percent from 2014, primarily as a result of asset sales. Refer to the “Selected Operating Data” table on page FS-12 for a three-year comparison of production volumes in the United States.






FS--7


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

International Upstream
Millions of dollars
2016

 
 
2015

 
2014

Earnings*
$
(483
)
 
 
$
2,094

 
$
13,566

 
 
 
 
*Includes foreign currency effects:
$
122

 
 
$
725

 
$
597

International upstream incurred a loss of $483 million in 2016 compared with earnings of $2.09 billion in 2015. The decrease in earnings was primarily due to lower crude oil realizations of $1.89 billion, lower natural gas realizations of $600 million, lower gains on asset sales of $450 million and higher tax items of $330 million. Partially offsetting the decrease were lower exploration and operating expenses of $640 million and $520 million, respectively, and higher natural gas sales volumes of $330 million. Foreign currency effects increased earnings by $122 million in 2016 compared with an increase of $725 million a year earlier.
International upstream earnings were $2.09 billion in 2015 compared with $13.57 billion in 2014. The decrease between periods was primarily due to lower crude oil and natural gas realizations of $10.57 billion and $880 million, respectively, and higher depreciation expenses of $1.11 billion, primarily reflecting impairments. Lower gains on asset sales also contributed to the decrease with gains of $370 million in 2015 compared with $1.10 billion in 2014. Partially offsetting the decrease were higher crude oil sales volumes of $590 million and lower operating expenses of $510 million. Foreign currency effects increased earnings by $725 million in 2015, compared with an increase of $597 million a year earlier.
The company’s average realization for international crude oil and natural gas liquids in 2016 was $38.61 per barrel, compared with $46.52 in 2015 and $90.42 in 2014. The average natural gas realization was $4.02 per thousand cubic feet in 2016, compared with $4.53 and $5.78 in 2015 and 2014, respectively.
International net oil-equivalent production was 1.90 million barrels per day in 2016, essentially unchanged from 2015 and 2014. Between 2016 and 2015, production increases from major capital projects, base business, and shale and tight properties were largely offset by normal field declines, the Partitioned Zone shut-in, the impact of civil unrest in Nigeria and planned turnaround activity. Between 2015 and 2014, production increases from entitlement effects in several locations and project ramp-ups in Bangladesh and other areas were offset by the Partitioned Zone shut-in, normal field declines and the effect of asset sales.
The net liquids component of international oil-equivalent production was 1.22 million barrels per day in 2016, down 2 percent from 2015 and 3 percent from 2014. International net natural gas production of 4.1 billion cubic feet per day in 2016 was up 4 percent from 2015 and 5 percent from 2014.
Refer to the “Selected Operating Data” table, on page FS-12, for a three-year comparison of international production volumes.

U.S. Downstream
Millions of dollars
2016

 
 
2015

 
2014

Earnings
$
1,307

 
 
$
3,182

 
$
2,637

U.S. downstream operations earned $1.31 billion in 2016, compared with $3.18 billion in 2015. The decrease was due to lower margins on refined product sales of $1.45 billion, lower earnings from the 50 percent-owned Chevron Phillips Chemicals Company LLC of $400 million and asset impairments of $110 million. Partially offsetting this decrease were lower operating expenses of $80 million and higher gains on asset sales of $110 million.
U.S. downstream operations earned $3.18 billion in 2015, compared with $2.64 billion in 2014. The increase in earnings was due to higher margins on refined product sales of $1.51 billion, partially offset by the absence of 2014 asset sale gains of $960 million.
Refined product sales of 1.21 million barrels per day in 2016 were down 1 percent, primarily due to lower gas oil sales. Sales volumes of refined products were 1.23 million barrels per day in 2015, an increase of 1 percent from 2014, mainly reflecting higher sales of jet fuel. U.S. branded gasoline sales of 532,000 barrels per day in 2016 increased 2 percent from 2015 and 3 percent from 2014.
Refer to the “Selected Operating Data” table on page FS-12 for a three-year comparison of sales volumes of gasoline and other refined products and refinery input volumes.


FS--8


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

International Downstream
Millions of dollars
2016

 
 
2015

 
2014

Earnings*
$
2,128

 
 
$
4,419

 
$
1,699

 
 
 
 
*Includes foreign currency effects:
$
(25
)
 
 
$
47

 
$
(112
)
International downstream earned $2.13 billion in 2016, compared with $4.42 billion in 2015. The decrease in earnings was primarily due to the absence of a $1.6 billion gain from the sale of the company's interest in Caltex Australia Limited in 2015, partially offset by 2016 asset sales gains of $420 million. Lower margins on refined product sales of $1.14 billion also contributed to the decline. Partially offsetting these decreases were lower operating expenses of $240 million. Foreign currency effects decreased earnings by $25 million in 2016, compared to an increase of $47 million a year earlier.
International downstream earned $4.42 billion in 2015, compared with $1.70 billion in 2014. The increase was primarily due to a $1.6 billion gain from the sale of the company's interest in Caltex Australia in second quarter 2015 and higher margins on refined product sales of $690 million. Foreign currency effects increased earnings by $47 million in 2015, compared to a decrease of $112 million a year earlier.
Total refined product sales of 1.46 million barrels per day in 2016 were down 3 percent from 2015. Excluding the effects of the Caltex Australia Limited divestment, refined product sales were down 1 percent, primarily reflecting lower fuel oil sales. Sales of 1.51 million barrels per day in 2015 were essentially unchanged from 2014.
Refer to the “Selected Operating Data” table, on page FS-12, for a three-year comparison of sales volumes of gasoline and other refined products and refinery input volumes.
All Other
Millions of dollars
2016

 
 
2015

 
2014

Net charges*
$
(1,395
)
 
 
$
(1,053
)
 
$
(1,988
)
 
 
 
 
*Includes foreign currency effects:
$
(39
)
 
 
$
(3
)
 
$
2

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 2016 increased $342 million from 2015, mainly due to higher corporate charges, interest expense and corporate tax items, partially offset by lower environmental reserve additions and lower charges related to reductions in corporate staffs. Net charges in 2015 decreased $935 million from 2014, mainly due to lower corporate tax items and the absence of 2014 charges related to mining assets, partially offset by higher charges related to reductions in corporate staffs.
Consolidated Statement of Income
Comparative amounts for certain income statement categories are shown below:
Millions of dollars
2016

 
 
2015

 
2014

Sales and other operating revenues
$
110,215

 
 
$
129,925

 
$
200,494

Sales and other operating revenues decreased in 2016 primarily due to lower refined product and crude oil prices, partially offset by higher crude oil volumes. The decrease between 2015 and 2014 was primarily due to lower refined product and crude oil prices, partially offset by higher refined product and crude oil volumes
Millions of dollars
2016

 
 
2015

 
2014

Income from equity affiliates
$
2,661

 
 
$
4,684

 
$
7,098

Income from equity affiliates decreased in 2016 from 2015 primarily due to lower upstream-related earnings from Tengizchevroil in Kazakhstan and Petroboscan in Venezuela, and lower downstream-related earnings from CPChem and GS Caltex in South Korea.
Income from equity affiliates decreased in 2015 from 2014 mainly due to lower earnings from Tengizchevroil in Kazakhstan, CPChem, Angola LNG and the effect of the sale of Caltex Australia Limited in second quarter 2015. Partially offsetting these effects were higher earnings from GS Caltex in South Korea and Petropiar in Venezuela.
Refer to Note 16, beginning on page FS-43, for a discussion of Chevron’s investments in affiliated companies.

FS--9


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

Millions of dollars
2016<