CVX-12.31.14-10K DOC

 
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, 2014
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 — $247,905,549,754 (As of June 30, 2014)
 Number of Shares of Common Stock outstanding as of February 9, 2015 — 1,880,180,422
 
DOCUMENTS INCORPORATED BY REFERENCE
(To The Extent Indicated Herein)
Notice of the 2015 Annual Meeting and 2015 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, in connection with the company’s 2015 Annual Meeting of Stockholders (in Part III)
 































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TABLE OF CONTENTS
ITEM
 
PAGE
3
 
3
 
4
 
           Upstream
4
 
           Downstream 
19
 
           Other Businesses 
21
22
24
24
24
25
25
25
25
25
25
25
26
26
26
27
27
27
27
28
 
28
 
29

EX-10.5
EX-24.9
EX-10.7
EX-24.10
EX-10.8
EX-24.11
EX-10.9
EX-24.12
EX-10.10
EX-31.1
EX-12.1
EX-31.2
EX-21.1
EX-32.1
EX-23.1
EX-32.2
EX-24.1
EX-95
EX-24.2
EX-99.1
EX-24.3
EX-101 INSTANCE DOCUMENT
EX-24.4
EX-101 SCHEMA DOCUMENT
EX-24.5
EX-101 CALCULATION LINKBASE DOCUMENT
EX-24.6
EX-101 LABELS LINKBASE DOCUMENT
EX-24.7
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-24.8
EX-101 DEFINITION LINKBASE DOCUMENT
 
 


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 such as “anticipates,” “expects,” “intends,” “plans,” “targets,” “forecasts,” “projects,” “believes,” “seeks,” “schedules,” “estimates,” “may,” “could,” “budgets,” “outlook” and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, many of which are beyond the company’s control and are difficult to predict. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements. The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this report. Unless legally required, Chevron undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.
Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are: changing crude oil and natural gas prices; changing refining, marketing and chemicals margins; actions of competitors or regulators; timing of exploration expenses; timing of crude oil liftings; the competitiveness of alternate-energy sources or product substitutes; technological developments; the results of operations and financial condition of equity affiliates; the inability or failure of the company’s joint-venture partners to fund their share of operations and development activities; the potential failure to achieve expected net production from existing and future crude oil and natural gas development projects; potential delays in the development, construction or start-up of planned projects; the potential disruption or interruption of the company’s production or manufacturing facilities or delivery/transportation networks due to war, accidents, political events, civil unrest, severe weather, other natural or human factors, or crude oil production quotas that might be imposed by the Organization of Petroleum Exporting Countries; the potential liability for remedial actions or assessments under existing or future environmental regulations and litigation; significant investment or product changes required by existing or future environmental statutes, regulations and litigation; the potential liability resulting from other pending or future litigation; the company’s future acquisition or disposition of assets and gains and losses from asset dispositions or impairments; government-mandated sales, divestitures, recapitalizations, industry-specific taxes, changes in fiscal terms or restrictions on scope of company operations; foreign currency movements compared with the U.S. dollar; the effects of changed accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; and the factors set forth under the heading “Risk Factors” on pages 22 through 24 in this report. In addition, such results could be affected by general domestic and international economic and political conditions. Other unpredictable or unknown factors not discussed in this report could also have material adverse effects on forward-looking statements.

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 fully integrated petroleum operations, chemicals operations, and power and energy services. Upstream operations consist primarily of exploring for, developing and producing crude oil and natural gas; processing, liquefaction, transportation and regasification associated with liquefied natural gas; transporting crude oil by major international oil export pipelines; transporting, storage and marketing of natural gas; and a gas-to-liquids 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-4. As of December 31, 2014, Chevron had approximately 64,700 employees (including about 3,300 service station employees). Approximately 31,800 employees (including about 3,100 service station employees), or 49 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 and other independent refining, marketing, transportation and chemicals entities and national petroleum companies in the sale or acquisition of various goods or services in many national and international markets.
Operating Environment
Refer to pages FS-2 through FS-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 create shareholder value and achieve sustained financial returns from its operations that will enable it to outperform its competitors. In the upstream, the company’s strategies are to grow profitably in core areas and build new legacy positions. In the downstream, the strategies are to deliver competitive returns and grow earnings across the value chain. The company also continues to apply commercial excellence in supply, trading and transportation to enable the success of the upstream and downstream strategies, and to utilize technology across all its businesses to differentiate performance.
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, 2014, and assets as of the end of 2014 and 2013 — for the United States and the company’s international geographic areas — are in Note 12 to the Consolidated Financial Statements beginning on page FS-37. Similar comparative data for the company’s investments in and income from equity affiliates and property, plant and equipment are in Notes 13 and 14 on pages FS-40 through FS-41. Refer to page FS-13 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-65 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 2012 and each year-end from 2012 through 2014. 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, 2014, 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, 2014, 20 percent of the company's net proved reserves were located in Kazakhstan and 19 percent were located in the United States.
The net proved reserve balances at the end of each of the three years 2012 through 2014 are shown in the following table:
 
At December 31
 
 
 
2014

 
2013

 
2012

 
Liquids — Millions of barrels
 
 
 
 
 
 
  Consolidated Companies
4,285

 
4,303

 
4,353

 
  Affiliated Companies
1,964

 
2,042

 
2,128

 
Total Liquids
6,249

 
6,345

 
6,481

 
Natural Gas — Billions of cubic feet
 
 
 
 
 
 
  Consolidated Companies
25,707

 
25,670

 
25,654

 
  Affiliated Companies
3,409

 
3,476

 
3,541

 
Total Natural Gas
29,116

 
29,146

 
29,195

 
Oil-Equivalent — Millions of barrels*
 
 
 
 
 
 
  Consolidated Companies
8,570

 
8,582

 
8,629

 
  Affiliated Companies
2,532

 
2,621

 
2,718

 
Total Oil-Equivalent
11,102

 
11,203

 
11,347

 
* Oil-equivalent conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of 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 2014 and 2013 by the company and its affiliates. Worldwide oil-equivalent production of 2.571 million barrels per day in 2014 was down 1 percent from 2013. Production increases in the Permian Basin in Texas and New Mexico and the Marcellus Shale in western Pennsylvania, and project ramp-ups in Nigeria, Argentina and Brazil, were more than offset by normal field declines, production entitlement effects in several locations and the effect of asset sales. Refer to the “Results of Operations” section beginning on page FS-7 for a detailed discussion of the factors explaining the 2012 through 2014 changes in production for crude oil and natural gas liquids, and natural gas, and refer to Table V on pages FS-68 and FS-69 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)
2014

2013

 
2014

2013

 
2014

2013

 
United States
664

657

 
456

449

 
1,250

1,246

 
Other Americas
 
 
 
 
 
 
 
 
 
  Argentina
25

19

 
21

18

 
23

6

 
  Brazil
21

6

 
20

5

 
6

2

 
  Canada2
69

71

 
67

70

 
10

9

 
  Colombia
31

36

 


 
186

216

 
  Trinidad and Tobago
19

29

 


 
112

173

 
Total Other Americas
165

161

 
108

93

 
337

406

 
Africa
 
 
 
 
 
 
 
 
 
  Angola
121

127

 
113

118

 
51

52

 
  Chad3
8

19

 
8

18

 
2

4

 
  Democratic Republic of the Congo
3

3

 
2

2

 
1

1

 
  Nigeria
286

268

 
246

238

 
236

182

 
  Republic of the Congo
16

14

 
14

13

 
11

10

 
Total Africa
434

431

 
383

389

 
301

249

 
Asia
 
 
 
 
 
 
 
 
 
  Azerbaijan
28

28

 
26

26

 
12

10

 
  Bangladesh
109

113

 
2

2

 
643

663

 
  China
16

20

 
16

19

 

6

 
  Indonesia
185

193

 
149

156

 
214

225

 
  Kazakhstan
53

57

 
31

34

 
126

135

 
  Myanmar
16

16

 


 
99

96

 
  Partitioned Zone4
81

87

 
78

84

 
18

19

 
  Philippines
23

23

 
3

3

 
118

119

 
  Thailand
238

229

 
63

62

 
1,046

1,003

 
Total Asia
749

766

 
368

386

 
2,276

2,276

 
Australia/Oceania
 
 
 
 
 
 
 
 
 
  Australia
97

96

 
23

26

 
442

421

 
Total Australia/Oceania
97

96

 
23

26

 
442

421

 
Europe
 
 
 
 
 
 
 
 
 
  Denmark
25

28

 
17

19

 
51

55

 
  Netherlands3
7

9

 
2

2

 
34

41

 
  Norway3
1

2

 
1

2

 

1

 
  United Kingdom
47

55

 
32

40

 
88

94

 
Total Europe
80

94

 
52

63

 
173

191

 
Total Consolidated Companies
2,189

2,205

 
1,390

1,406

 
4,779

4,789

 
Affiliates2,5
382

392

 
319

325

 
388

403

 
Total Including Affiliates6 
2,571

2,597

 
1,709

1,731

 
5,167

5,192

 
1 Oil-equivalent conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of oil.
 
2 Includes synthetic oil: Canada, net
43

43

 
43

43

 


 
  Venezuelan affiliate, net
31

25

 
31

25

 


 
3 Producing fields in Chad, the Netherlands and Norway were sold in 2014.
 
4 Located between Saudi Arabia and Kuwait.
 
 
 
 
 
 
 
 
 
5 Volumes represent Chevron’s share of production by affiliates, including Tengizchevroil in Kazakhstan; Petroboscan, Petroindependiente and Petropiar in Venezuela; and Angola LNG in Angola.
 
6 Volumes include natural gas consumed in operations of 523 million and 530 million cubic feet per day in 2014 and 2013, respectively.(7) Total “as sold” natural gas volumes were 4,644 million and 4,662 million cubic feet per day for 2014 and 2013, respectively.(7) 
 
7 2013 conformed to 2014 presentation.

 

5





Production Outlook
The company estimates its average worldwide oil-equivalent production in 2015 will be flat to 3 percent growth compared to 2014. 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-64 for the company’s average sales price per barrel of crude oil, condensate and natural gas liquids and per thousand cubic feet of natural gas produced, and the average production cost per oil-equivalent barrel for 2014, 2013 and 2012.
Gross and Net Productive Wells
The following table summarizes gross and net productive wells at year-end 2014 for the company and its affiliates:
 
At December 31, 2014
 
 
 
Productive Oil Wells
 
Productive Gas Wells
 
 
 
Gross

 
Net

Gross

 
Net

 
United States
50,338

 
32,957

13,393

 
7,098

 
Other Americas
937

 
642

61

 
33

 
Africa
1,980

 
676

17

 
7

 
Asia
14,144

 
12,213

3,431

 
2,043

 
Australia/Oceania
744

 
417

76

 
15

 
Europe
322

 
69

161

 
34

 
Total Consolidated Companies
68,465

 
46,974

17,139

 
9,230

 
Affiliates
1,405

 
486

7

 
2

 
Total Including Affiliates
69,870

 
47,460

17,146

 
9,232

 
Multiple completion wells included above
954

 
678

412

 
382

 
Acreage
At December 31, 2014, 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:
 
Undeveloped* 
 
 
Developed
 
 
Developed and Undeveloped
 
 
Thousands of acres
Gross

 
Net

 
Gross

 
Net

 
Gross

 
Net

 
United States
5,724

 
4,718

 
7,139

 
4,726

 
12,863

 
9,444

 
Other Americas
26,834

 
15,134

 
1,403

 
390

 
28,237

 
15,524

 
Africa
14,967

 
8,766

 
3,167

 
1,333

 
18,134

 
10,099

 
Asia
28,998

 
13,864

 
1,549

 
901

 
30,547

 
14,765

 
Australia/Oceania
19,338

 
13,640

 
912

 
235

 
20,250

 
13,875

 
Europe
4,718

 
3,464

 
407

 
53

 
5,125

 
3,517

 
Total Consolidated Companies
100,579

 
59,586

 
14,577

 
7,638

 
115,156

 
67,224

 
Affiliates
534

 
230

 
269

 
105

 
803

 
335

 
Total Including Affiliates
101,113

 
59,816

 
14,846

 
7,743

 
115,959

 
67,559

 
 * 
The gross undeveloped acres that will expire in 2015, 2016 and 2017 if production is not established by certain required dates are 8,065, 3,913 and 2,110, 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 239 billion cubic feet of natural gas to third parties through 2017. The company believes it can satisfy these contracts through a combination of equity production from the company’s proved developed U.S. reserves and third-party purchases. These commitments include a variety of pricing terms, including both indexed and fixed-price contracts.

6





Outside the United States, the company is contractually committed to deliver a total of 705 billion cubic feet of natural gas to third parties from 2015 through 2017 from operations in Australia, Colombia, Denmark 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-61 for details associated with the company’s development expenditures and costs of proved property acquisitions for 2014, 2013 and 2012.
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, 2014. 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 12/31/14
 
2014
 
 
2013
 
 
2012
 
 
 
Gross

Net
 
Prod.

Dry

 
Prod.

Dry

 
Prod.

Dry

 
United States
120

76

 
1,085

8

 
1,101

4

 
941

6

 
Other Americas
65

39

 
81


 
127


 
50


 
Africa
27

8

 
9


 
20

1

 
23


 
Asia
140

70

 
1,025

4

 
535

5

 
566

6

 
Australia/Oceania
9

7

 
9


 


 


 
Europe
3


 
2


 
3


 
9


 
Total Consolidated Companies
364

200

 
2,211

12

 
1,786

10

 
1,589

12

 
Affiliates
27

12

 
25

1

 
25


 
26


 
Total Including Affiliates
391

212

 
2,236

13

 
1,811

10

 
1,615

12

 
 

Exploration Activities
Refer to Table I on page FS-61 for detail on the company’s exploration expenditures and costs of unproved property acquisitions for 2014, 2013 and 2012.
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, 2014. “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 12/31/14
 
2014
 
 
2013
 
 
2012
 
 
 
Gross

 
Net

 
Prod.

 
Dry

 
Prod.

 
Dry

 
Prod.

 
Dry

 
United States
13


7


20


12


17


2


4



 
Other Americas
8


3


3




12


2


8



 
Africa
2


1


1


2






1


2

 
Asia




7


2


13


4


12


3

 
Australia/Oceania
1


1


3




3




3



 
Europe
2




3




2


2


1


2

 
Total Consolidated Companies
26


12


37


16


47


10


29


7

 
Affiliates















 
Total Including Affiliates
26


12


37


16


47


10


29


7

 

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 2014 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-3, 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-10.
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 California, the Gulf of Mexico, Colorado, Louisiana, Michigan, New Mexico, Ohio, Oklahoma, Pennsylvania, Texas, West Virginia and Wyoming. Average net oil-equivalent production in the United States during 2014 was 664,000 barrels per day.
In California, the company has significant production in the San Joaquin Valley. In 2014, net daily production averaged 163,000 barrels of crude oil, 66 million cubic feet of natural gas and 3,000 barrels of natural gas liquids (NGLs). Approximately 86 percent of the crude oil production is considered heavy oil (typically with API gravity lower than 22 degrees).
During 2014, net daily production in the Gulf of Mexico averaged 133,000 barrels of crude oil, 320 million cubic feet of natural gas and 15,000 barrels of NGLs. Chevron was engaged in various exploration and development activities in the deepwater Gulf of Mexico during 2014.
The 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. Chevron's interest in the production host facility is 40.6 percent. The facility has a design capacity of 170,000 barrels of crude oil and 42 million cubic feet of natural gas per day to accommodate production from the Jack/St. Malo development as well as third-party tiebacks. First production was achieved in December 2014, and production from three of 10 planned wells ramped-up during first quarter 2015. In addition, front-end engineering and design (FEED) activities continued in 2014 on the second phase of the development plan for the Jack and St. Malo fields, and construction is expected to commence on Stage 2 in 2016. 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 94,000 barrels of crude oil and 21 million cubic feet of natural gas. The Jack and St. Malo fields have an estimated production life of 30 years from the time of start-up.
Construction and commissioning activities for the 60 percent-owned and operated Big Foot Project progressed during 2014, reaching 93 percent complete by year end. The project facilities have a design capacity of 75,000 barrels of crude oil and 25 million cubic feet of natural gas per day. First production is anticipated in late 2015. The field has an estimated production life of 35 years from the time of start-up. Proved reserves have been recognized for this project.
At the 58 percent-owned and operated Tahiti Field, work continued during 2014 on Tahiti 2 – a project that is designed to increase recovery from the main producing interval. The last injection well is expected to be completed in first quarter 2015. Additional infill drilling is scheduled for the Tahiti Field through 2016, with production from the first well expected in second-half 2015. The initial recognition of proved reserves occurred in 2014 for the infill drilling. The Tahiti Field has an estimated remaining production life of at least 20 years.
The company has a 42.9 percent nonoperated working interest in the Tubular Bells Field. First production was achieved in November 2014. Total production is expected to average 58,000 to 67,000 barrels of oil-equivalent per day in 2015. The field has an estimated production life of 25 years from the time of start-up.
The company has a 15.6 percent nonoperated working interest in the Mad Dog Field. The next development phase, the Mad Dog 2 Project, is planned to develop the southern portion of the field. The development plan was re-evaluated in 2013, and FEED was re-entered on a new development concept in third quarter 2014. At the end of 2014, proved reserves had not been recognized for this project.
Chevron holds a 25 percent nonoperated working interest in the Stampede Project, which includes the joint development of the Knotty Head and Pony fields. The planned facilities have a design capacity of 80,000 barrels of crude oil and 40 million cubic feet of natural gas per day. A final investment decision was reached in third quarter 2014. Drilling is planned to commence in fourth quarter 2015 with first oil expected in 2018. The fields have an estimated production life of 30 years from the time of start-up. The initial recognition of proved reserves occurred in 2014 for this project.

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FEED activities commenced in early 2015 on a project to jointly develop the 55 percent-owned and operated Buckskin Field and the 87.5 percent-owned and operated Moccasin Field, which are located 12 miles apart. The development plan includes a subsea tieback to a third-party production facility with 30,000 barrels of crude oil and 15 million cubic feet of natural gas per day of firm capacity and rights to additional available capacity. A final investment decision is expected in 2016. At the end of 2014, proved reserves had not been recognized for this project.
In early 2015, the company announced a joint venture to explore and appraise 24 jointly held offshore leases in the northwest portion of Keathley Canyon. Chevron will be the operator. The joint venture includes the Tiber and Gila discoveries and the Gibson exploratory prospect, located between Gila and Tiber. The company acquired a 36 percent interest in the Gila leases and a 31 percent interest in the Tiber leases and also holds a 36 percent interest in the Gibson prospect. The scope of the joint venture includes further exploration and appraisal of the leases and evaluation of the potential for a centralized production facility. Separately, during 2014, the company exchanged its interest in the Coronado prospect for interests in other prospective deepwater exploration opportunities.
During 2014 and early 2015, the company participated in four appraisal wells and eight exploration wells in the deepwater Gulf of Mexico. An appraisal well and a sidetrack were completed at the Buckskin Field in 2014, and results are under evaluation. In October 2014, the company completed drilling an exploration well at the 42.5 percent-owned and operated Guadalupe prospect, which resulted in a significant crude oil discovery in the Lower Tertiary Wilcox Sands, adjacent to Keathley Canyon. Drilling at the 55 percent-owned and operated Anchor prospect was completed in December 2014, resulting in a significant crude oil discovery, also in the Lower Tertiary Wilcox Sands. In late 2014, drilling commenced on an appraisal well of the Tiber discovery as well as on a sidetrack of the Gila discovery well, and drilling is expected to continue until mid-2015. In January 2015, drilling commenced at the 40 percent-owned and operated Sweetwater and the 50 percent-owned and operated Sicily exploration wells, and both wells are expected to be completed in second quarter 2015.
In addition, Chevron added eleven leases to its deepwater portfolio as a result of awards from Gulf of Mexico lease sales held in 2014.
The company produces crude oil and natural gas in the midcontinent region of the United States, primarily in Colorado, New Mexico, Oklahoma, Texas and Wyoming. During 2014, the company’s net daily production in these areas averaged 110,000 barrels of crude oil, 595 million cubic feet of natural gas and 31,000 barrels of NGLs.
In the Permian Basin of West Texas and southeast New Mexico, the company continued to ramp-up development of shale and tight resources with drilling activities focused in the Midland and Delaware basins where the company holds approximately 500,000 and 1,000,000 net acres, respectively. The company drilled 550 wells in the Midland and Delaware basins in 2014.
The company holds leases in the Marcellus Shale and the Utica Shale, primarily located in southwestern Pennsylvania, eastern Ohio, and the West Virginia panhandle, and in the Antrim Shale and Collingwood/Utica Shale in Michigan. During 2014, the company's net daily production in these areas averaged 269 million cubic feet of natural gas. In 2014, development of the Marcellus Shale continued at a measured pace, focused on improving execution capability and reservoir understanding. Activities in the Utica Shale during 2014 focused on exploration drilling to acquire data necessary for potential future development.
Other Americas
“Other Americas” includes Argentina, Brazil, Canada, Colombia, Greenland, Suriname, Trinidad and Tobago, and Venezuela. Net oil-equivalent production from these countries averaged 228,000 barrels per day during 2014.
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. Average net oil-equivalent production during 2014 was 69,000 barrels per day, composed of 24,000 barrels of crude oil, 10 million cubic feet of natural gas and 43,000 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 23.6 nonoperated working interest in the unitized Hibernia Southern Extension (HSE) areas offshore Atlantic Canada. In 2014, work continued on HSE development, and full production start-up is planned for 2015. Proved reserves have been recognized for this project. In addition, FEED activities progressed on the Hibernia SW BNA project. At the end of 2014, proved reserves had not been recognized for this project.

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The company holds a 26.6 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. Construction activities progressed in 2014. The project has an expected economic life of 30 years from the time of start-up, and first oil is expected in 2017. Proved reserves have been recognized for this project.
The company holds a 20 percent nonoperated working interest in the Athabasca Oil Sands Project (AOSP) in Alberta. Oil sands are mined from both the Muskeg River and the Jackpine mines, and bitumen is extracted from the oil sands and upgraded into synthetic oil. Construction work progressed during 2014 on the Quest Project, which is designed to capture and store more than one million tons of carbon dioxide produced annually by AOSP bitumen processing. Project start-up is expected in 2016.
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 after completing a 30 percent farm-down in 2014. Production from the initial multiwell program in the Duvernay continued during 2014, and drilling activities began on an expanded 16-well appraisal program. A total of twelve wells had been tied into production facilities by early 2015.
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 322,000 net acres in the Horn River and Liard shale gas basins in British Colombia. 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 2014, proved reserves had not been recognized for this project.
The company holds a 40 percent nonoperated working interest in exploration rights for two blocks in the Flemish Pass Basin offshore Newfoundland.
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. The acquisition of 2-D seismic data commenced in third quarter 2014 and is expected to continue over the next few years.
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 one 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 2014 averaged 25,000 barrels per day, composed of 21,000 barrels of crude oil and 23 million cubic feet of natural gas.
Development activities continued at the Loma Campana concession in the Vaca Muerta Shale where 166 wells were drilled in 2014, and the 2015 drilling plan includes approximately 150 wells. In 2014, the company also continued production testing of four previously completed exploratory wells in the El Trapial concession, targeting oil and gas in the Vaca Muerta Shale. The El Trapial concession expires in 2032.
During 2014, the company signed agreements for exploration of shale oil and gas resources in the Narambuena area in the Chihuido de la Sierra Negra concession, also in the Vaca Muerta Shale. The exploration plan for Narambuena includes nine wells to be drilled in two phases.
Brazil: Chevron holds interests in three deepwater fields in the Campos Basin: Frade (51.7 percent-owned and operated), Papa-Terra and Maromba (37.5 percent and 30 percent nonoperated working interests, respectively). The concession that includes the Frade Field expires in 2025 and the concession that includes the Papa-Terra and Maromba fields expires in 2032. Net oil-equivalent production in 2014 averaged 21,000 barrels per day, composed of 20,000 barrels of crude oil and 6 million cubic feet of natural gas.
Following the resumption of production from four wells at the Frade Field during 2013, production resumed at the remaining six wells in second quarter 2014. At Papa-Terra, production is expected to ramp up through 2017 with additional development drilling until 2021.
Additionally, Chevron holds a 50 percent-owned and operated interest in Block CE-M715, located in the Ceara Basin offshore equatorial Brazil. Acquisition of 3-D seismic data is planned to commence in second quarter 2015.

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Colombia: The company operates the offshore Chuchupa and the onshore Ballena and Riohacha natural gas fields and receives 43 percent of the production for the remaining life of each field and a variable production volume based on prior Chuchupa capital contributions. Daily net production averaged 186 million cubic feet of natural gas in 2014.
Suriname: Chevron holds a 50 percent nonoperated working interest in Blocks 42 and 45 offshore Suriname. In 2014, 2-D and 3-D seismic data for both blocks were processed. Farm-down opportunities are being pursued for the two blocks.
Trinidad and Tobago: The company has a 50 percent nonoperated working interest in three blocks in the East Coast Marine Area offshore Trinidad, which includes the Dolphin and Dolphin Deep producing natural gas fields and the Starfish development. Net production in 2014 averaged 112 million cubic feet of natural gas per day.
At the Starfish development, first gas was achieved in December 2014, and two additional wells are planned to be brought online in second quarter 2015. Natural gas from the project is planned to supply existing contractual commitments. Chevron also operates and holds a 50 percent interest in the Manatee Area of Block 6(d), where the Manatee discovery comprises a single cross-border field with Venezuela's Loran Field in Block 2. Work continued in 2014 on maturing commercial development concepts.
Venezuela: Chevron's production activities are performed by two affiliates in western Venezuela and one affiliate in the Orinoco Belt. 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. 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. The company’s share of net oil-equivalent production during 2014 from these operations averaged 63,000 barrels per day, composed of 59,000 barrels of liquids and 27 million cubic feet of natural gas.
Chevron holds a 34 percent interest in the Petroindependencia affiliate that is working toward commercialization of Carabobo 3, a heavy oil project located within the Carabobo Area of the Orinoco Belt. The company also operates and holds a 60 percent interest in Block 2 and a 100 percent interest in Block 3 in the Plataforma Deltana area offshore eastern Venezuela. The Loran Field in Block 2 and the Manatee Field in Trinidad and Tobago form a single, cross-border field that lies along the maritime border of Venezuela and Trinidad and Tobago. Work continued in 2014 on maturing commercial development concepts.
Africa
In Africa, the company is engaged in upstream activities in Angola, Democratic Republic of the Congo, Liberia, Mauritania, Morocco, Nigeria, Republic of the Congo, Sierra Leone and South Africa. Net oil-equivalent production in this region averaged 439,000 barrels per day during 2014.
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. The company also has a 16.3 percent nonoperated working interest in the onshore Fina Sonangol Texaco concession area. Chevron's interest in Block 2 expired in July 2014. In addition, Chevron has a 36.4 percent interest in Angola LNG Limited. During 2014, net production from these operations averaged 114,000 barrels of liquids and 78 million cubic feet of natural gas per day.
Construction activities on Mafumeira Sul, the second development stage for the Mafumeira Field in Block 0, progressed in 2014. The facility has a design capacity of 150,000 barrels of liquids and 350 million cubic feet of natural gas per day. First production is planned for 2016, and ramp-up to full production is expected to continue through 2017. Proved reserves have been recognized for this project.
Work continued in 2014 on the Nemba Enhanced Secondary Recovery Stage 1 & 2 Project in Block 0. Installation of the platform was completed in early 2014, and start-up of the project is expected in early 2015. Total daily production is expected to be 9,000 barrels of crude oil. Proved reserves have been recognized for this project.
Also in Block 0, the company drilled one post-salt appraisal well in Area B and one pre-salt exploration well in Area A, which completed drilling in early 2015. As of early 2015, the results of both wells were under evaluation. One additional exploration well in Area A is planned to commence drilling in fourth quarter 2015.
In addition to the exploration and production activities, Angola LNG Limited 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

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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 by-product of crude oil production. Feedstock for the plant originates from multiple fields and operators. In April 2014, the plant experienced a failure in the flare blowdown piping system, resulting in an extended plant shutdown. Following a thorough review, a number of design issues have been identified that require modifications. Capacity and reliability enhancements are also planned to be completed during the shutdown. The plant will be restarted following completion of these modifications and repairs, and LNG production is expected to resume in late 2015. The remaining economic life of the project is anticipated to be in excess of 20 years.
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. Construction on the project continued in 2014, with commissioning and start-up targeted for second-half 2015.
Angola-Republic of the 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 the Congo. The Lianzi Project has a design capacity of 46,000 barrels of crude oil per day. Construction and drilling activities progressed during 2014, and first production is planned for fourth quarter 2015. Proved reserves have been recognized for this project.
Democratic Republic of the Congo: Chevron has a 17.7 percent nonoperated working interest in an offshore concession. Daily net production in 2014 averaged 2,000 barrels of crude oil.
Republic of the Congo: Chevron has a 31.5 percent nonoperated working interest in the offshore Haute Mer permit areas (Nkossa, Nsoko and Moho-Bilondo). The licenses for Nsoko, Nkossa, and Moho-Bilondo expire in 2018, 2027 and 2030, respectively. Net production averaged 14,000 barrels of liquids per day in 2014.
During 2014, work continued on the Moho Nord Project, located in the Moho-Bilondo development area. First production to the existing Moho-Bilondo FPU is expected in 2015, and total daily production of 140,000 barrels of crude oil is expected in 2017. Proved reserves have been recognized for this project.
In 2014, the company acquired a 20.4 percent nonoperated working interest in the Haute Mer B permit area, which covers more than 20,000 net acres offshore Republic of the Congo.
Chad/Cameroon: In June 2014, the company sold its 25 percent interest in seven crude oil fields in southern Chad and an approximate 21 percent interest in two affiliates that own the related crude oil export pipeline to the coast of Cameroon. Average daily net crude oil production from the Chad fields in 2014 was 8,000 barrels.
Liberia: Chevron operates and holds a 45 percent interest in three deepwater blocks off the coast of Liberia. In 2014, Chevron requested, and the government of Liberia granted, a one-year extension of the LB-11 and LB-12 blocks.
Sierra Leone: The company is the operator of and holds a 55 percent interest in a concession off the coast of Sierra Leone that contains two deepwater blocks. In 2014, 2-D seismic processing was completed to identify drilling prospects.
Mauritania: In early 2015, the company reached an agreement to acquire a 30 percent nonoperated working interest in the C8, C12 and C13 contract areas offshore Mauritania. The blocks cover 2 million net acres and have a water depth between 5,000 and 10,000 feet. The acquisition is pending government approval.
Morocco: The company operates and holds a 75 percent interest in three deepwater areas offshore Morocco. The acquisition of 2-D seismic data was completed in 2014, and a 3-D seismic survey is planned for 2015. Chevron is pursuing a farm-down of its interest.
Nigeria: Chevron holds a 40 percent interest in nine operated concessions, predominantly 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. The company is pursuing selected opportunities for divestment and farm-down in Nigeria. In 2014, the company’s net oil-equivalent production in Nigeria averaged 286,000 barrels per day, composed of 240,000 barrels of crude oil, 236 million cubic feet of natural gas and 6,000 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. During 2014, drilling continued on a second phase development program, Agbami 2, that is expected to offset field declines and maintain a total daily liquids production rate of 250,000 barrels. The third development phase, Agbami 3, is also expected to offset field declines. The project entered FEED in early 2014, and drilling for this phase commenced in early 2015. The drilling programs for Agbami 2 and Agbami 3 are scheduled to end in 2015 and 2017, respectively. The first Phase 3 development well is scheduled to commence production in 2016. The leases that contain the Agbami Field expire in 2023 and 2024. Proved reserves have been recognized for the Agbami 3 Project.

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Also in the deepwater area, the Aparo Field in OML 132 and OML 140 and the third-party-owned Bonga SW Field in OML 118 share a common geologic structure and are planned to be jointly developed. Chevron holds a 19.6 percent nonoperated working interest in the unitized area. The planned facilities have a design capacity of 225,000 barrels of crude oil per day. A final investment decision is expected in 2015 or 2016. At the end of 2014, no proved reserves were recognized for this project.
In the Niger Delta region, ramp-up activity continued at the Escravos Gas Plant (EGP). During 2014, construction continued on Phase 3B of the EGP project, which is designed to gather 120 million cubic feet of natural gas per day from eight near-shore fields and to compress and transport the natural gas to onshore facilities. The Phase 3B project is expected to be completed in 2016. Proved reserves associated with this project have been recognized.
Construction activities progressed during 2014 on the 40 percent-owned and operated Sonam Field Development Project, which is designed to process natural gas through EGP, deliver 215 million cubic feet of natural gas per day to the domestic market and produce a total of 30,000 barrels of liquids per day. First production is expected in 2017. Proved reserves have been recognized for the project.
Chevron is the operator of a 33,000-barrel-per-day gas-to-liquids facility at Escravos. The facility is designed to process 325 million cubic feet per day of natural gas. The facility achieved initial production of product in mid-2014.
In deepwater exploration, Chevron operates and holds a 95 percent interest in the deepwater Nsiko discovery in OML 140, where drilling commenced on an exploration well at the Nsiko North prospect in fourth quarter 2014. Additional exploration activities are planned for 2015. In addition, Chevron holds a 30 percent nonoperated working interest in OML 138. In 2014, two exploration wells were drilled in the Usan area that resulted in crude oil discoveries. In 2015, the company plans to evaluate development options.
Shallow-water exploration activities to identify and evaluate potential deep hydrocarbon targets are ongoing. Reprocessing of 3-D seismic data over OML 49 and regional mapping activities over the western Niger Delta continued in 2014. Acquisition of 3-D seismic data over the Meren and Okan fields is planned for 2015.
With a 36.7 percent interest, Chevron is the largest shareholder in the West African Gas Pipeline Company Limited affiliate, which owns and operates the 421-mile West African Gas Pipeline. The pipeline supplies Nigerian natural gas to customers in Benin, Ghana and Togo for industrial applications and power generation and has the capacity to transport 170 million cubic feet per day.
South Africa: In 2014, the company continued evaluating shale gas exploration opportunities in the Karoo Basin in South Africa under an agreement that allows Chevron and its partner to work together to obtain exploration permits in the 151 million-acre basin.
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, Thailand, and Vietnam. During 2014, net oil-equivalent production averaged 1,063,000 barrels per day.
Azerbaijan: Chevron holds an 11.3 percent nonoperated working interest in the Azerbaijan International Operating Company (AIOC) and the crude oil production from the Azeri-Chirag-Gunashli (ACG) fields. The company’s daily net production in 2014 averaged 28,000 barrels of oil-equivalent, composed of 26,000 barrels of crude oil and 12 million cubic feet of natural gas. AIOC operations are conducted under a PSC that expires in 2024.
The Chirag Oil Project is further developing the Chirag and Gunashli fields. The project has an incremental design capacity of 183,000 barrels of crude oil and 285 million cubic feet of natural gas per day. Production commenced in January 2014 and reached 84,000 barrels of crude oil and 87 million cubic feet of natural gas per day by year-end 2014.
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, which is operated by AIOC, with capacity to transport 100,000 barrels per day from Baku, Azerbaijan, to a marine terminal at Supsa, Georgia.
Kazakhstan: Chevron 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 2014 averaged 367,000 barrels per day, composed of 290,000 barrels of liquids and 460 million cubic feet of natural gas.

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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 2014 from these fields averaged 239,000 barrels of crude oil, 334 million cubic feet of natural gas and 20,000 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 and via the BTC pipeline to the Mediterranean.
In 2014, work progressed on three projects. The Wellhead Pressure Management Project (WPMP) is designed to maintain production capacity and extend the production plateau from existing assets. The Capacity and Reliability (CAR) Project is designed to reduce facility bottlenecks and increase plant efficiency and reliability. The Future Growth Project (FGP) is designed to increase total daily production by 250,000 to 300,000 barrels of oil-equivalent and to increase ultimate recovery from the reservoir. The FGP is planned to expand the utilization of sour gas injection technology proven in existing operations. The final investment decision for the CAR Project was reached in February 2014. The final investment decisions for the FGP and the WPMP are anticipated in 2015. Proved reserves have been recognized for the WPMP and the CAR Project.
The Karachaganak Field is located in northwest Kazakhstan, and operations are conducted under a PSC that expires in 2038. During 2014, net daily production averaged 31,000 barrels of liquids and 126 million cubic feet of natural gas. Access to the CPC and Atyrau-Samara (Russia) pipelines enabled most of the Karachaganak liquids to be exported and sold at world-market prices during 2014. The remaining liquids were sold into local and Russian markets.
Kazakhstan/Russia: Chevron has a 15 percent interest in the CPC affiliate. During 2014, CPC transported an average of 865,000 barrels of crude oil per day, composed of 763,000 barrels per day from Kazakhstan and 102,000 barrels per day from Russia. In 2014, work continued on the 670,000-barrel-per-day expansion of the pipeline capacity. The project is being implemented in phases, with capacity increasing progressively until reaching a design capacity of 1.4 million barrels per day in 2016. By the end of 2014, capacity from Kazakhstan had been increased by a maximum of 230,000 barrels per day, and in December, nearly 90 percent of TCO's total production was exported via CPC. Additional capacity is expected to progressively come on line in 2015 and 2016. 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 from these operations in 2014 averaged 109,000 barrels per day, composed of 643 million cubic feet of natural gas and 2,000 barrels of condensate.
First production was achieved in late 2014 at the Bibiyana Expansion Project, which has an incremental design capacity of 300 million cubic feet of natural gas and 4,000 barrels of condensate per day. The expected economic life of the project is the duration of the PSC. FEED activities continued on the Bibiyana Compression Project during 2014. The project is expected to provide incremental production to offset field declines. A final investment decision is pending commercial negotiations. At the end of 2014, proved reserves had not been recognized for this project.
Cambodia: In October 2014, Chevron completed the sale of its 30 percent interest in Block A, located in the Gulf of Thailand.
China: Chevron has operated and nonoperated working interests in several areas in China. The company’s net production in 2014 averaged 16,000 barrels of crude oil per day.
The company operates and holds a 49 percent interest in the Chuandongbei Project, located onshore in the Sichuan Basin. The full development includes two sour gas processing plants connected by a natural gas gathering system to five fields. In 2014, the company continued construction on the first natural gas processing plant and development of the Luojiazhai and Gunziping natural gas fields. The first plant's initial three trains have a design outlet capacity of 258 million cubic feet per day. The first train reached mechanical completion in late 2014, and commissioning activities were initiated. Start-up is expected in 2015. The total design outlet capacity for the project is 558 million cubic feet per day. Proved reserves have been recognized for the natural gas fields supplying the first sour gas processing plant. The project's estimated economic life exceeds 20 years from start-up. The PSC for Chuandongbei expires in 2038.
Chevron has a 100 percent-owned and operated interest in shallow-water Blocks 15/10 and 15/28 in the South China Sea. In 2014, the company completed processing of two 3-D seismic surveys and plans to drill one exploration well in Block 15/10 in 2015. In May 2014, the company relinquished its interest in deepwater exploration Block 42/05.

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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 Block16/19 in the Pearl River Mouth Basin. The PSCs for these producing assets expire between 2022 and 2028.
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. The company’s net oil-equivalent production in 2014 from its interests in Indonesia averaged 185,000 barrels per day, composed of 149,000 barrels of liquids and 214 million cubic feet of natural gas.
The largest producing field is Duri, located in the Rokan PSC. Duri has been under steamflood since 1985 and is one of the world’s largest steamflood developments. The company continues to implement projects designed to sustain production from existing reservoirs. Production ramp-up continued and first steam injection was achieved in 2014 at the steamflood expansion project in Area 13 of the Duri Field. 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 115 million cubic feet of natural gas and 4,000 barrels of condensate per day. The company’s interest is 62 percent. A final investment decision was reached in 2014, following government approvals. Project execution began with the drilling of two development wells in second-half 2014. First gas is planned for 2016. The initial recognition of proved reserves occurred in 2014 for this project.
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, rebidding of the engineering and construction contracts, extension of the associated PSCs, and securing new LNG sales contracts. At the end of 2014, proved reserves had not been recognized for this project.
Chevron relinquished its 51 percent-owned and operated interest in the West Papua I and West Papua III PSCs. Government approval for the relinquishment is anticipated in 2015.
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. The company relinquished its 95 percent interest in the Suoh-Sekincau prospect area of South Sumatra. In 2014, Chevron secured the preliminary survey assignment for the adjacent South Sekincau prospect and is in the early phases of geological and geophysical assessment.
Myanmar: Chevron has a 28.3 percent nonoperated working interest in a PSC for the production of natural gas from the Yadana and Sein fields, within Blocks M5 and M6, in the Andaman Sea. The PSC expires in 2028. The company also has a 28.3 percent nonoperated interest in a pipeline company that transports most of the natural gas to the Myanmar-Thailand border for delivery to power plants in Thailand. The company’s average net natural gas production in 2014 was 99 million cubic feet per day.
In March 2014, Chevron was granted a 99 percent interest in and operatorship of Block A5. The exploration block covers 2.6 million net acres. As of early 2015, PSC terms were being finalized.
Philippines: The company holds a 45 percent nonoperated working interest in the Malampaya natural gas field, offshore Palawan. Net oil-equivalent production in 2014 averaged 23,000 barrels per day, composed of 118 million cubic feet of natural gas and 3,000 barrels of condensate. The Malampaya Phase 2 Project is designed to maintain capacity at the offshore platform. First production from the infill wells commenced in 2013, with first production from the compression facilities expected in second-half 2015. Proved reserves have been recognized for this project.
Chevron holds a 40 percent interest in an affiliate that develops and produces steam resources in southern Luzon, 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 Kalinga geothermal prospect area in northern Luzon. The company continues to assess the prospect area.
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. The company's net oil-equivalent production in 2014 averaged 238,000 barrels per day, composed of 63,000 barrels of crude oil and condensate and 1 billion cubic feet of natural gas.

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In the Pattani Basin, FEED activities continued for the 35 percent-owned and operated Ubon Project in Block 12/27. The development concept includes facilities with a planned design capacity of 35,000 barrels of liquids and 115 million cubic feet of natural gas per day. At the end of 2014, proved reserves had not been recognized for this project.
During 2014, the company drilled six exploration wells in the Pattani Basin, and four 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.
Vietnam: Chevron is the operator of two PSCs in the Malay Basin off the southwest coast of Vietnam. The company has a 42.4 percent interest in a PSC that includes Blocks B and 48/95 and a 43.4 percent interest in a PSC for Block 52/97.
The Block B Gas Development Project facilities have a planned design capacity of 640 million cubic feet of natural gas and 21,000 barrels of liquids per day. A final investment decision for the development is pending resolution of commercial terms. Concurrent with the commercial negotiations, the company is also evaluating these assets for possible divestment. At the end of 2014, proved reserves had not been recognized for the development project.
Kurdistan Region of Iraq: The company operates and holds 80 percent contractor interests in three PSCs covering the Rovi, Sarta and Qara Dagh blocks. Initial drilling operations in the Rovi and Sarta blocks continued to progress in 2014, and the results are under evaluation. The company also commenced 3-D and 2-D seismic acquisition programs in the Sarta and Qara Dagh blocks, respectively. In August 2014, all activities were temporarily suspended as a result of ongoing regional instability. In early 2015, mobilization of personnel back to the region commenced in preparation to restart operations in first quarter. Farm-down opportunities are being pursued for the three blocks.
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. During 2014, the company's average net oil-equivalent production was 81,000 barrels per day, composed of 78,000 barrels of crude oil and 18 million cubic feet of natural gas. Current difficulties in securing work and equipment permits may impact the company’s ability to continue production at current levels.
During 2014, the company continued a steam injection pilot project in the First Eocene carbonate reservoir. Proved reserves have been recognized for this project.
FEED activities continued on a project to expand the steam injection pilot to the Second Eocene reservoir, and a final investment decision is planned for 2016. Development planning also continued on a full-field steamflood application in the Wafra Field. The Wafra Steamflood Stage 1 Project has a planned design capacity of 80,000 barrels of crude oil per day and is expected to enter FEED in third quarter 2015. At the end of 2014, proved reserves had not been recognized for these steamflood developments.
The Central Gas Utilization Project is intended to increase natural gas utilization and eliminate routine flaring at the Wafra Field. As of early, 2015, the development plan is being re-evaluated. At year-end 2014, proved reserves had not been recognized for this project.
In June 2014, the company began a 3-D seismic survey covering the entire onshore Partitioned Zone.
Australia/Oceania
In Australia/Oceania, the company is engaged in upstream activities in Australia and New Zealand. During 2014, net oil-equivalent production averaged 97,000 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 Nappamerri Trough in central Australia and the Bight Basin offshore South Australia. During 2014, the company's production averaged 23,000 barrels of crude oil and 442 million cubic feet of natural gas per day. Most of this production was from the NWS Venture.
Chevron holds a 47.3 percent interest and is the operator of the Gorgon Project, which includes the development of the Gorgon and nearby 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 natural gas plant, which are located on Barrow Island, off Western Australia. The total production capacity for the project is expected to be approximately 2.6 billion cubic feet of natural gas and 20,000 barrels of condensate per day. Work continued during 2014 with 88 percent of the overall project complete at year-end. LNG Train 1 start-up is planned for third quarter 2015, with first cargo anticipated in fourth quarter 2015. Start-up of Trains 2 and 3 is expected in 2016. Total estimated project costs for the first phase of development are $54 billion. Proved reserves have been recognized for this project. The project's estimated economic life exceeds 40 years from the time of start-up.

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In January 2015, the company announced an additional binding sales agreement for delivery of LNG from the Gorgon Project for a five-year period starting in 2017. During the time of this agreement, more than 75 percent of Chevron's equity LNG offtake from the project is committed under binding sales agreements with customers in Asia. Chevron also has binding, long-term agreements for delivery of about 65 million cubic feet per day of natural gas to Western Australian natural gas consumers, and the company continues to market additional pipeline natural gas quantities from the project.
The evaluation of options to increase the production capacity of Gorgon is planned to continue in 2015.
Chevron is the operator of the Wheatstone Project, which includes a two-train, 8.9 million-metric-ton-per-year LNG facility and a domestic gas plant, both located at Ashburton North, on the coast of Western Australia. The company plans to supply natural gas to the facilities from the Wheatstone and Iago fields. Chevron holds an 80.2 percent interest in the offshore licenses and a 64.1 percent interest in the LNG facilities. 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. The project was 53 percent complete at year-end. Start-up of the first train is expected in late 2016, with the second train start-up planned for 2017. Total estimated costs for the foundation phase are $29 billion. Proved reserves have been recognized for this project. The project's estimated economic life exceeds 30 years from the time of start-up.
As of year-end 2014, Chevron had binding, long-term sales agreements with four customers in Japan for 85 percent of the company's equity LNG offtake from this project. In addition, the company continues to market its equity share of pipeline natural gas to Western Australia customers.
During 2014, the company made five natural gas discoveries in the Carnarvon Basin. These discoveries contribute to the resources available to extend and expand Chevron's LNG projects in the region.
Chevron has a 16.7 percent nonoperated working interest in the North West Shelf (NWS) Venture in Western Australia. Approximately 80 percent of the natural gas sales were in the form of LNG to major utilities in Asia, primarily under long-term contracts. The remaining natural gas was sold to the Western Australia domestic market. The concession for the NWS Venture expires in 2034.
The company holds nonoperated working interests ranging from 24.8 percent to 50 percent in three blocks in the Browse Basin. Drilling in third quarter 2014 resulted in a natural gas discovery at the Lasseter prospect in Block WA-274-P.
In the Nappamerri Trough, the company holds a 30 percent nonoperated working interest in the Permian section of PRL 33-49 in South Australia and an 18 percent nonoperated working interest in ATP 855 in Queensland. During 2014, exploration drilling and flow testing continued in order to evaluate the commerciality of the resource base. Pending favorable results, Chevron could earn a 60 percent nonoperated working interest in PRL 33-49 and a 36 percent nonoperated working interest in ATP 855.
The company operates and holds a 100 percent working interest in offshore Blocks EPP44 and EPP45 in the Bight Basin off the South Australian coast. In 2014, the company completed the initial survey to acquire 3-D seismic data, and an additional survey and data processing are planned to continue through 2016.
New Zealand: In late 2014, Chevron was granted three exploration permits in the offshore Pegasus and East Coast basins. The deepwater permits cover 3.1 million net acres and are located approximately 100 miles east of Wellington. Chevron will be the operator with a 50 percent interest. The exploration permits are granted for a term of 15 years, commencing April 2015. Acquisition of 2-D and 3-D seismic data is scheduled to commence in 2016.
Europe
In Europe, the company is engaged in upstream activities in Denmark, Norway, Poland, Romania, and the United Kingdom. Net oil-equivalent production in the region averaged 80,000 barrels per day during 2014.
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. Net oil-equivalent production in 2014 from the DUC averaged 25,000 barrels per day, composed of 17,000 barrels of crude oil and 51 million cubic feet of natural gas. The concession expires in 2042.
Lithuania: Chevron divested its 50 percent interest in an exploration and production company in mid-2014.

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Netherlands: In November 2014, Chevron divested its upstream interests in the Dutch sector of the North Sea. Net oil-equivalent production in 2014 was 7,000 barrels per day, composed of 2,000 barrels of crude oil and 34 million cubic feet of natural gas.
Norway: In August 2014, the company completed the sale of its interest in the Draugen Field. Net production averaged 1,000 barrels of oil-equivalent per day during 2014. Chevron is the operator and has a 40 percent interest in exploration licenses PL 527 and PL 598. Both licenses are in the deepwater portion of the Norwegian Sea.
Poland: In first-half 2014, Chevron completed a 3-D seismic survey on the Grabowiec concession. The company also entered into a joint exploration agreement covering Chevron's Grabowiec and Zwierzyniec licenses and two adjacent licenses in early 2014. In fourth quarter 2014, Chevron relinquished two shale concessions (Frampol and Krasnik) in southeastern Poland. In early 2015, Chevron announced the discontinuation of exploration activities in Poland.
Romania: In 2014, drilling of the first exploration well in the Barlad Shale concession in northeast Romania was completed, as was a 2-D seismic survey across two of the three concessions in southeast Romania. Chevron intends to pursue relinquishment of its interest in these concessions in 2015.
Ukraine: In 2013, Chevron signed a PSC with the government of Ukraine for a 50 percent interest and operatorship of the Oleska Shale block in western Ukraine. In fourth quarter 2014, Chevron terminated the agreement.
United Kingdom: The company’s average net oil-equivalent production in 2014 from nine offshore fields was 47,000 barrels per day, composed of 32,000 barrels of liquids and 88 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 jointly operated Britannia Field.
The 73.7 percent-owned and operated Alder Project is being developed as a tie-back to the existing Britannia platform, and has a design capacity of 14,000 barrels of condensate and 110 million cubic feet of natural gas per day. Fabrication of topside and subsea equipment progressed in 2014, and first production is expected in 2016. Proved reserves have been recognized for this project.
The Captain Enhanced Oil Recovery Project is the next development phase of the Captain Field and is designed to increase field recovery. The project entered FEED in fourth quarter 2014, and a final investment decision is scheduled for 2016. At the end of 2014, proved reserves had not been recognized for this project.
During 2014, procurement and fabrication activities continued 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. Production is scheduled to begin in 2017. 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 assess alternatives for the optimum development of the Rosebank Field and made significant progress in optimizing the Rosebank development plan. 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 2014, proved reserves had not been recognized for this project.
West of the Shetland Islands, exploration activities included acquisition and interpretation of 3-D seismic data. In the central North Sea, an exploration well previously drilled to delineate the southern extension of the Jade Field was successfully tied back and first production was achieved.
Sales of Natural Gas and Natural Gas Liquids
 The company sells natural gas and natural gas liquids from its producing operations under a variety of contractual arrangements. In addition, the company also makes third-party purchases and sales of natural gas and natural gas liquids in connection with its supply and trading activities.
During 2014, U.S. and international sales of natural gas were 4.0 billion and 4.3 billion cubic feet per day, respectively, which includes the company’s share of equity affiliates’ sales. Outside the United States, substantially all of the natural gas sales from the company’s producing interests are from operations in Australia, Bangladesh, Canada, Europe, Kazakhstan, Indonesia, Latin America, Myanmar, Nigeria, the Philippines and Thailand.

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U.S. and international sales of natural gas liquids were 141,000 and 86,000 barrels per day, respectively, in 2014. Substantially all of the international sales of natural gas liquids from the company's producing interests are from operations in Africa, Canada, Indonesia and the United Kingdom.
Refer to “Selected Operating Data,” on page FS-11 in Management’s Discussion and Analysis of Financial Condition and Results of Operations, for further information on the company’s sales volumes of natural gas and natural gas liquids. Refer also to “Delivery Commitments” beginning on page 6 for information related to the company’s delivery commitments for the sale of crude oil and natural gas.
Downstream
Refining Operations
At the end of 2014, the company had a refining network capable of processing nearly 2 million barrels of crude oil per day. Operable capacity at December 31, 2014, and daily refinery inputs for 2012 through 2014 for the company and affiliate refineries are summarized in the table below.
Average crude oil distillation capacity utilization during 2014 was 87 percent, compared with 84 percent in 2013. At the U.S. refineries, crude oil distillation capacity utilization averaged 91 percent in 2014, compared with 81 percent in 2013. Chevron processes both imported and domestic crude oil in its U.S. refining operations. Imported crude oil accounted for about 73 percent and 76 percent of Chevron’s U.S. refinery inputs in 2014 and 2013, respectively.
At the Pascagoula Refinery, the 25,000 barrels-per-day premium base oil plant began commercial production in third quarter 2014. Elsewhere, work continued during 2014 on projects to improve refinery flexibility, reliability and capability to process lower cost feedstocks. A project to replace the atmospheric distillation column and other related equipment at the Salt Lake City Refinery was completed in mid-2014, resulting in improved plant reliability and feedstock flexibility. At the El Segundo Refinery, a project to replace six end-of-life coke drums was also completed during the year. At the Richmond, California refinery, a modernization project progressed, with certification of the Environmental Impact Report and approval of a conditional use permit by the Richmond City Council in July 2014. The company is now seeking to secure the further necessary approvals to resume construction. In addition, Chevron is evaluating the Hawaii refinery and related assets for possible divestment.
Outside the United States, Caltex Australia Ltd., a 50 percent-owned affiliate, completed the conversion of the Kurnell, Australia, refinery to an import terminal in fourth quarter 2014. During 2014, Singapore Refining Company, Chevron's 50 percent-owned joint venture, initiated construction of a gasoline desulfurization facility and a cogeneration plant. The investment is expected to increase the refinery's capability to produce higher value gasoline and to improve energy efficiency.
Petroleum Refineries: Locations, Capacities and Inputs
 
Capacities and inputs in thousands of barrels per day
December 31, 2014
 
Refinery Inputs
 
 
Locations
Number
Operable Capacity

2014

2013

2012

 
Pascagoula
Mississippi
1

330

329

304

335

 
El Segundo
California
1

269

221

235

265

 
Richmond
California
1

257

229

153

142

 
Kapolei
Hawaii
1

54

47

39

46

 
Salt Lake City
Utah
1

50

45

43

45

 
Total Consolidated Companies — United States
5

960

871

774

833

 
Map Ta Phut1
Thailand
1

165

141

161

95

 
Cape Town2
South Africa
1

110

72

78

79

 
Burnaby, B.C.
Canada
1

55

49

42

49

 
Total Consolidated Companies — International
3

330

262

281

223

 
Affiliates1,3
Various Locations
5

610

557

583

646

 
Total Including Affiliates — International
8

940

819

864

869

 
Total Including Affiliates — Worldwide
13

1,900

1,690

1,638

1,702

 
 
1 
As of June 2012, Star Petroleum Refining Company crude input volumes are reported on a consolidated basis. Prior to June 2012, crude volumes reflect a 64 percent equity interest and are reported in affiliates.
2 
Chevron holds a 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 preferred shares ultimately convertible to 25 percent equity interest in Chevron South Africa (Pty) Limited.
3 
In fourth quarter 2014, Caltex Australia Ltd. completed the conversion of the 68,000-barrel-per-day Kurnell refinery into an import terminal.

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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, 2014.
Refined Products Sales Volumes
 
Thousands of barrels per day
2014

2013

2012

 
United States
 
 
 
 
   Gasoline
615

613

624

 
   Jet Fuel
222

215

212

 
   Gas Oil and Kerosene
217

195

213

 
   Residual Fuel Oil
63

69

68

 
   Other Petroleum Products1
93

90

94

 
Total United States
1,210

1,182

1,211

 
International2
 
 
 
 
   Gasoline
403

398

412

 
   Jet Fuel
249

245

243

 
   Gas Oil and Kerosene
498

510

496

 
   Residual Fuel Oil
162

179

210

 
   Other Petroleum Products1 
189

197

193

 
Total International
1,501

1,529

1,554

 
Total Worldwide2 
2,711

2,711

2,765

 
1 Principally naphtha, lubricants, asphalt and coke.
 
 
2 Includes share of affiliates’ sales:
475

471

522

 
 In the United States, the company markets under the Chevron and Texaco brands. At year-end 2014, the company supplied directly or through retailers and marketers approximately 7,930 Chevron- and Texaco-branded motor vehicle service stations, primarily in the southern and western states. Approximately 380 of these outlets are company-owned or -leased stations.
Outside the United States, Chevron supplied directly or through retailers and marketers approximately 8,450 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 Pakistan, the company uses the Caltex brand. The company also operates through affiliates under various brand names. In South Korea, the company operates through its 50 percent-owned affiliate, GS Caltex, and in Australia through its 50 percent-owned affiliate, Caltex Australia Limited.
Chevron markets commercial aviation fuel at approximately 113 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 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 2014, CPChem owned or had joint-venture interests in 34 manufacturing facilities and two research and development centers around the world.
In second quarter 2014, CPChem completed commissioning and started commercial operation of a 1-hexene plant with a design capacity of 250,000 metric tons per year at the Cedar Bayou Plant in Baytown, Texas and, in fourth quarter 2014, CPChem began commercial operations of a 90,000 metric-ton-per-year expansion of ethylene production at its Sweeny complex located in Old Ocean, Texas. In early 2014, construction commenced on the U.S. Gulf Coast Petrochemicals Project, which is expected to capitalize on advantaged feedstock sourced from shale gas 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. Start-up is expected in 2017.
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 2014, the company manufactured, blended or conducted research at 10 locations around the world. In 2014, the company completed expansion projects at its manufacturing facilities in Singapore and Gonfreville, France. In addition, a final investment decision was reached in fourth quarter 2014 to build a carboxylate plant in Singapore, which is expected to be completed in 2017.

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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 are base chemicals used to produce a range of products, including adhesives, plastics and textile fibers. GS Caltex also produces polypropylene, which is used to make food packaging, laboratory equipment and textiles.
Transportation
Pipelines: Chevron owns and operates a network of crude oil, natural gas, natural gas liquid, refined product and chemical 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.
During 2014, the company continued to optimize its portfolio of pipeline and infrastructure assets. Net pipeline mileage at the end of 2014 was 5,548, a reduction of 4,524 miles from 2013, mainly due to asset sales. Also in 2014, Chevron completed construction of a 136-mile, 24-inch crude oil pipeline from the Jack/St. Malo deepwater production facility to a platform in Green Canyon Block 19 on the U.S. Gulf of Mexico shelf, where there is an interconnect to pipelines delivering crude oil into Texas and Louisiana. Pipeline operations began with start-up of the production facilities in late 2014.
Refer to pages 13 and 14 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, primarily in the coastal waters of the United States. The foreign-flagged vessels are engaged primarily in transporting crude oil from the Middle East, Southeast Asia, the Black Sea, South America, Mexico and West Africa to ports in the United States, Europe, Australia and Asia, as well as refined products and feedstocks to and from various locations worldwide. In 2014, the company took delivery of three bareboat charter VLCCs and two Pacific Area Lightering vessels.
The company also owns a 16.7 percent interest in each of seven LNG carriers transporting cargoes for the North West Shelf Venture in Australia. In 2014, the company took delivery of two new LNG carriers in support of its developing LNG portfolio.
Other Businesses
Power and Energy Management: The company's power and energy management operation delivers comprehensive commercial, engineering and operational support services to improve power reliability and energy efficiency for Chevron's operations worldwide. The business operates a variety of power assets, including gas-fired cogeneration facilities within Chevron's San Joaquin Valley operations in California, and renewable power facilities in California, New Mexico and Wyoming. The business also manages Chevron's investments in six renewable power projects in California, Arizona and Texas.
Chevron also has major geothermal operations in Indonesia and the Philippines. For additional information on the company's geothermal operations refer to page 15 in the Upstream section.
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, security and network technology to provide a standardized digital infrastructure to enable Chevron’s global operations and business processes.
Chevron's technology ventures company supports Chevron's upstream and downstream businesses by sourcing and demonstrating emerging technologies and championing their integration into Chevron’s operations. As of the end of 2014, the company continued to source technologies in emerging materials, power systems, production enhancements, renewables, water management, information technologies and advanced biofuels, and to develop options for efficient management of Chevron's carbon footprint. Additionally, in 2014, the company made investments in start-up companies with technologies for pipeline integrity, efficient carbon dioxide capture from flue gas and big data management.

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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 25 beginning on FS-59 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 (SWRP). SWRP’s objective is to further develop the industry’s capability to contain and shut in subsea well control incidents in different regions of the world.
Refer to Management's Discussion and Analysis of Financial Condition and Results of Operations on page FS-16 for additional information on environmental matters and their impact on Chevron, and on the company's 2014 environmental expenditures. Refer to page FS-16 and Note 23 on page FS-58 for a discussion of environmental remediation provisions and year-end reserves. Refer also to Item 1A. Risk Factors on pages 22 through 24 for a discussion of greenhouse gas regulation and climate change.
Item 1A. Risk Factors
Chevron is a global energy company with a diversified business portfolio, a strong balance sheet, and a history of generating sufficient cash to pay dividends and fund capital and exploratory expenditures. Nevertheless, some inherent risks could materially impact the company’s results of operations or financial condition.
Chevron is exposed to the effects of changing commodity prices: Chevron is primarily in a commodities business that has a history of price volatility. The single largest variable that affects the company’s results of operations is the price of crude oil, which can be influenced by general economic conditions, industry inventory levels, production quotas or other actions imposed by the Organization of Petroleum Exporting Countries (OPEC), weather-related damage and disruptions, competing fuel prices, and geopolitical risks. Chevron accepts the risk of changing commodity prices as part of its business planning process. As such, an investment in the company carries significant exposure to fluctuations in global crude oil prices.
During extended periods of historically low prices for crude oil, the company’s upstream earnings, cash flows, and capital and exploratory expenditure programs will be negatively affected, as will its production and proved reserves. Upstream assets may also become impaired. The impact on downstream earnings is dependent upon the supply and demand for refined products and the associated margins on refined product sales.
The scope of Chevron’s business will decline if the company does not successfully develop resources: The company is in an extractive business; therefore, if Chevron is not successful in replacing the crude oil and natural gas it produces with good prospects for future production or through acquisitions, the company’s business will decline. Creating and maintaining an inventory of projects depends on many factors, including obtaining and renewing rights to explore, develop and produce hydrocarbons; drilling success; ability to bring long-lead-time, capital-intensive projects to completion on budget and on schedule; and efficient and profitable operation of mature properties.
The company’s operations could be disrupted by natural or human factors: Chevron operates in both urban areas and remote and sometimes inhospitable regions. The company’s operations and facilities are therefore subject to disruption from either natural or human causes beyond its control, including hurricanes, floods and other forms of severe weather, war, civil unrest and other political events, fires, earthquakes, system failures, cyber threats and terrorist acts, any of which could result in suspension of operations or harm to people or the natural environment.
Chevron utilizes comprehensive risk management systems to assess potential physical and other risks to its assets and to plan for their resiliency. While capital investment reviews and decisions involve uncertainty analysis, which incorporates 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, Chevron cannot predict 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.

22





The company’s operations have inherent risks and hazards that require significant and continuous oversight: Chevron’s results depend on its ability to identify and mitigate the risks and hazards inherent to operating in the crude oil and natural gas industry. The company seeks to minimize these operational risks by carefully designing and building its facilities and conducting its operations in a safe and reliable manner. However, failure to manage these risks effectively could result in unexpected incidents, including releases, explosions or mechanical failures resulting in personal injury, loss of life, environmental damage, loss of revenues, legal liability and/or disruption to operations. Chevron has implemented and maintains a system of corporate policies, behaviors and compliance mechanisms to manage safety, health, environmental, reliability and efficiency risks; to verify compliance with applicable laws and policies; and to respond to and learn from unexpected incidents. 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 15 to the Consolidated Financial Statements, beginning on page FS-42.
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 related 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 or state environmental regulations, including those related to the use of hydraulic fracturing, could adversely affect the company's current or anticipated future operations and profitability.
Regulation of greenhouse gas emissions could increase Chevron’s operational costs and reduce demand for Chevron’s products: Continued political attention to issues concerning climate change, the role of human activity in it, and potential mitigation through regulation could have a material impact on the company’s operations and financial results.
International agreements and national or regional legislation and regulatory measures to limit greenhouse emissions are currently in various stages of discussion or implementation. These and other greenhouse gas emissions-related laws, policies and regulations may result in substantial capital, compliance, operating and maintenance costs. The level of expenditure required to comply with these laws and regulations is uncertain and is expected to vary depending on the laws enacted in each jurisdiction, the company’s activities in it and market conditions. Greenhouse gas emissions that could be regulated include those arising from the company’s exploration and production of crude oil and natural gas; the upgrading of production from oil sands into synthetic oil; power generation; the conversion of crude oil and natural gas into refined products; the processing, liquefaction and regasification of natural gas; the transportation of crude oil, natural gas and related products and consumers’ or customers’ use of the company’s products. Some of these activities, such as consumers’ and customers’ use of the company’s products, as well as actions taken by the company’s competitors in response to such laws and regulations, are beyond the company’s control.

23





The effect of regulation on the company’s financial performance will depend on a number of factors including, among others, the sectors covered, the greenhouse gas emissions reductions required by law, the extent to which Chevron would be entitled to receive emission allowance allocations or would need to purchase compliance instruments on the open market or through auctions, the price and availability of emission allowances and credits, and the impact of legislation or other regulation on the company’s ability to recover the costs incurred through the pricing of the company’s products. Material price increases or incentives to conserve or use alternative energy sources could reduce demand for products the company currently sells and adversely affect the company’s sales volumes, revenues and margins.
Changes in management’s estimates and assumptions may have a material impact on the company’s consolidated financial statements and financial or operational performance in any given period: In preparing the company’s periodic reports under the Securities Exchange Act of 1934, including its financial statements, Chevron’s management is required under applicable rules and regulations to make estimates and assumptions as of a specified date. These estimates and assumptions are based on management’s best estimates and experience as of that date and are subject to substantial risk and uncertainty. Materially different results may occur as circumstances change and additional information becomes known. Areas requiring significant estimates and assumptions by management include measurement of benefit obligations for pension and other postretirement benefit plans; estimates of crude oil and natural gas recoverable reserves; accruals for estimated liabilities, including litigation reserves; and impairments to property, plant and equipment. Changes in estimates or assumptions or the information underlying the assumptions, such as changes in the company’s business plans, general market conditions or changes in commodity prices, could affect reported amounts of assets, liabilities or expenses.
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-61 through FS-71. Note 14, “Properties, Plant and Equipment,” to the company’s financial statements is on page FS-41.
Item 3. Legal Proceedings
Ecuador: Information related to Ecuador matters is included in Note 15 to the Consolidated Financial Statements under the heading Ecuador, beginning on page FS-42.
Certain Governmental Proceedings: As previously disclosed in the Annual Report on Form 10-K for the year ended December 31, 2013, filed on February 21, 2014, on August 6, 2012, a piping failure and fire occurred at the Chevron U.S.A. Inc. refinery in Richmond, California. Various federal, state, and local agencies initiated investigations as a result of the incident. Based on its civil investigation, the United States Environmental Protection Agency (EPA) issued a Finding of Violations (FOV) to Chevron on December 17, 2013, which includes 62 findings of alleged noncompliance at the refinery. The majority of these findings relate to the August 2012 fire and alleged violations of chemical-accident-prevention laws, but the FOV also addresses a number of release-reporting issues, some of which are unrelated to the fire. Resolution of the alleged violations may result in the payment of a civil penalty of $100,000 or more.
As previously disclosed in the Annual Report on Form 10-K for the year ended December 31, 2013, filed on February 21, 2014, in July 2009, the Hawaii Department of Health (DOH) alleged that Chevron is obligated to pay stipulated civil penalties in conjunction with commitments Chevron undertook to install and operate certain air emission control equipment at its Hawaii Refinery pursuant to a Clean Air Act settlement with the United States EPA and the DOH. The company has disputed many of the allegations. Resolution of the alleged violations may result in the payment of a civil penalty of $100,000 or more.
As initially disclosed in the Annual Report on Form 10-K for the year ended December 31, 2013, filed on February 21, 2014, the State of New Mexico provided to Chevron a Notice of Violation on December 11, 2013, alleging that the flaring of fuel gas that occurred during periodic compressor purging events at the Chevron Buckeye CO2 plant resulted in hourly air emissions during these events in excess of the plant permit limits and alleging that the company had failed to timely report these excess emissions. The company has reached a settlement agreement with the State of New Mexico and paid a civil penalty of less than $100,000 to resolve the alleged violation.

24





As initially disclosed in the Quarterly Report on Form 10-Q for the period ended March 31, 2014, filed May 2, 2014, a fire was reported on February 11, 2014, at Chevron Appalachia, LLC’s Lanco 7H well located in Dunkard Township, Greene County, Pennsylvania. The Pennsylvania Department of Environmental Protection (PA DEP) and the Occupational Safety and Health Administration of the United States (OSHA) initiated investigations as a result of the incident. Based on its civil investigation to date, the PA DEP has issued Chevron a Notice of Violation alleging nine separate incidents of noncompliance. Resolution of the alleged violations may result in the payment of a civil penalty of $100,000 or more.
Item 4. Mine Safety Disclosures
Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 C.F.R. § 229.104) is included in Exhibit 95 of this Annual Report on Form 10-K.
PART II
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
The information on Chevron’s common stock market prices, dividends, principal exchanges on which the stock is traded and number of stockholders of record is contained in the Quarterly Results and Stock Market Data tabulations, on page FS-20.
Chevron Corporation Issuer Purchases of Equity Securities for Quarter Ended December 31, 2014
 
 
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, 2014
3,951,297

$114.97
3,951,111

Nov. 1 – Nov. 30, 2014
3,308,849

117.00
3,307,758

Dec. 1 – Dec. 31, 2014
3,733,530

109.48
3,733,530

Total Oct. 1 – Dec. 31, 2014
10,993,676

$113.72
10,992,399

1 
Includes common shares repurchased from company employees for required personal income tax withholdings on the exercise of the stock options and shares delivered or attested to in satisfaction of the exercise price by holders of the employee stock options. The options were issued to and exercised by management under Chevron long-term incentive plans and Unocal stock option plans.
2 
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. As of December 31, 2014, 180,886,291 shares had been acquired 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 does not plan to acquire any shares under the program in 2015.
Item 6. Selected Financial Data
The selected financial data for years 2010 through 2014 are presented on page FS-60.
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-15 and in Note 10 to the Consolidated Financial Statements, “Financial and Derivative Instruments,” beginning on page FS-35.
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.

25





Item 9A. Controls and Procedures
(a) Evaluation of Disclosure Controls and Procedures: The company’s management has evaluated, with the participation of the Chief Executive Officer and the Chief Financial Officer, the effectiveness of the company’s disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)) as of the end of the period covered by this report. Based on this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the company’s disclosure controls and procedures were effective as of December 31, 2014.
(b) Management’s Report on Internal Control Over Financial Reporting: The company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). The company’s management, including the Chief Executive Officer and the Chief Financial Officer, conducted an evaluation of the effectiveness of the company’s internal control over financial reporting based on the Internal Control — Integrated Framework (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, 2014.
The effectiveness of the company’s internal control over financial reporting as of December 31, 2014, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report included on page FS-22.
(c) Changes in Internal Control Over Financial Reporting: During the quarter ended December 31, 2014, there were no changes in the company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the company’s internal control over financial reporting.
On May 14, 2013, COSO published an updated Internal Control — Integrated Framework (2013) and related illustrative documents. The company adopted the new framework effective January 1, 2014.
Item 9B. Other Information
None.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Executive Officers of the Registrant at February 20, 2015
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
58
Chairman of the Board and Chief Executive Officer (since 2010)
Chairman of the Board and
Chief Executive Officer
G.L. Kirkland
64
Vice Chairman of the Board and Executive Vice President
   (since 2010)

Vice Chairman of the Board and Executive Vice President
M.K. Wirth
54
Executive Vice President (since 2006)
Worldwide Refining, Marketing and Lubricants; Chemicals
J.C. Geagea
55
Senior Vice President, Technology, Projects and Services
   (since 2014)
Corporate Vice President and President, Gas and Midstream
(2012 through 2013)
Managing Director, Asia South Business Unit (2008 through 2011)
Technology; Health, Environment and Safety; Project Resources Company; Procurement
J.W. Johnson
55
Senior Vice President, Upstream (since 2014)
President, Europe, Eurasia and Middle East Exploration and
Production (2011 through 2013)
Managing Director, Eurasia Business Unit (2008 to 2011)
Worldwide Exploration and Production Activities
P.R. Breber
50
Corporate Vice President and President, Gas and Midstream
   (since 2014)
Managing Director, Asia South Business Unit (2012 through 2013)
Deputy Managing Director, Asia South Business Unit (2011)
Vice President and Treasurer (2009 to 2011)
Worldwide Natural Gas Commercialization; Supply and Trading Activities, including Natural Gas Trading; Shipping; Pipeline; and Power and Energy Management
P.E. Yarrington
58
Vice President and Chief Financial Officer (since 2009)


Finance
R.H. Pate
52
Vice President and General Counsel (since 2009)
Law, Governance and Compliance

 

26





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 2015 Annual Meeting and 2015 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 2015 Annual Meeting of Stockholders (the “2015 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 2015 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 2015 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 2015 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.
There were no changes to the process by which stockholders may recommend nominees to the Board of Directors during the last fiscal year.
Item 11. Executive Compensation
The information required by Item 402 of Regulation S-K and contained under the headings “Executive Compensation” and “Director Compensation” in the 2015 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 2015 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 2015 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 2015 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 2015 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 2015 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 2015 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 2015 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 the Appointment of the Independent Registered Public Accounting Firm” in the 2015 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:
 
Page(s) 
FS--22
FS--23
FS--24
FS--25
FS--26
FS--27
FS-28 to FS-60
 

(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
2014

2013

2012

Employee Termination Benefits
 
 
 
Balance at January 1
$
14

$
30

$
63

Additions (reductions) charged to expense
53

(6
)
3

Payments
(18
)
(10
)
(36
)
Balance at December 31
$
49

$
14

$
30

Allowance for Doubtful Accounts
 
 
 
Balance at January 1
$
95

$
155

$
167

Additions (reductions) to expense
119

1

(4
)
Bad debt write-offs
(20
)
(61
)
(8
)
Balance at December 31
$
194

$
95

$
155

Deferred Income Tax Valuation Allowance* 
 
 
 
Balance at January 1
$
17,171

$
15,443

$
11,096

Additions to deferred income tax expense
1,192

2,665

5,471

Reduction of deferred income tax expense
(2,071
)
(937
)
(1,124
)
Balance at December 31
$
16,292

$
17,171

$
15,443

 * See also Note 16 to the Consolidated Financial Statements, beginning on page FS-45.


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 20th day of February, 2015.
 
 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 20th day of February, 2015.
 
Principal Executive Officers
(and Directors)
 
/s/JOHN S. WATSON 
John S. Watson, Chairman of the
Board and Chief Executive Officer
 
/s/GEORGE L. KIRKLAND
George L. Kirkland, Vice Chairman
of the Board
 
Principal Financial Officer
 
/s/PATRICIA E. YARRINGTON 
Patricia E. Yarrington, Vice President
and Chief Financial Officer
 
Principal Accounting Officer
 
/s/MATTHEW J. FOEHR 
Matthew J. Foehr, Vice President
and Comptroller
 
*By: /s/LYDIA I. BEEBE 
Lydia I. Beebe,
Attorney-in-Fact










 
 
Directors
 
ALEXANDER B. CUMMINGS, JR.* 
Alexander B. Cummings, Jr.
 
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* 
Charles W. Moorman
 
KEVIN W. SHARER* 
Kevin W. Sharer
 
JOHN G. STUMPF*
John G. Stumpf

 
RONALD D. SUGAR*
Ronald D. Sugar
 
INGE G. THULIN* 
Inge G. Thulin
 
CARL WARE* 
Carl Ware




29
































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30


Financial Table of Contents


 
 
 
FS-2
 
 
 
 
 
 
 
 
 
 
 
 
 
Off-Balance-Sheet Arrangements, Contractual Obligations,
    Guarantees and Other Contingencies FS-14
 
 
 
 
 
 
 
 
 
 
 
 
FS-21
 
 
 
 
Consolidated Financial Statements
 
 
 
 
 
 
 
 
 
 
 
 
FS-28
 
 
Changes in Accumulated Other Comprehensive Losses FS-30
 
Equity FS-32
Taxes FS-45
Long-Term Debt FS-48
Short-Term Debt FS-49
 
 
 
 
 


FS--1


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

Key Financial Results
Millions of dollars, except per-share amounts
2014

 
2013

 
2012

Net Income Attributable to Chevron Corporation
$
19,241

 
$
21,423

 
$
26,179

Per Share Amounts:


 

 

Net Income Attributable to Chevron Corporation


 

 

– Basic
$
10.21

 
$
11.18

 
$
13.42

– Diluted
$
10.14

 
$
11.09

 
$
13.32

Dividends
$
4.21

 
$
3.90

 
$
3.51

Sales and Other Operating Revenues
$
200,494

 
$
220,156

 
$
230,590

Return on:


 

 

Capital Employed
10.9
%
 
13.5
%
 
18.7
%
Stockholders’ Equity
12.7
%
 
15.0
%
 
20.3
%
Earnings by Major Operating Area
Millions of dollars
2014

 
2013

 
2012

Upstream
 
 
 
 
 
United States
$
3,327

 
$
4,044

 
$
5,332

International
13,566

 
16,765

 
18,456

Total Upstream
16,893

 
20,809

 
23,788

Downstream
 
 
 
 
 
United States
2,637

 
787

 
2,048

International
1,699

 
1,450

 
2,251

Total Downstream
4,336

 
2,237

 
4,299

All Other
(1,988
)
 
(1,623
)
 
(1,908
)
Net Income Attributable to Chevron Corporation1,2

$
19,241

 
$
21,423

 
$
26,179

1  Includes foreign currency effects:
$
487

 
$
474

 
$
(454
)
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-7 for a discussion of financial results by major operating area for the three years ended December 31, 2014.

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 the Congo, Singapore, South Africa, South Korea, Thailand, Trinidad and Tobago, the United Kingdom, the United States, Venezuela, and Vietnam.
Earnings of the company depend mostly on the profitability of its upstream 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 robust non-OPEC supply growth led by expanding unconventional production in the United States, weakening growth in emerging markets, and the decision by OPEC in fourth quarter 2014 to maintain its current production ceiling. 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, capital and exploratory investment program and production outlook. If lower prices persist for an extended period of time, the company's response could include further reductions in operating expenses and capital and exploratory expenditures and additional 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 increases is unknown. In the company's downstream business, crude oil is the largest cost component of refined products.
Refer to the "Cautionary Statement Relevant to Forward-Looking Information" on page 2 and to "Risk Factors" in Part I, Item 1A, on pages 22 through 24 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 growth. Refer to the “Results of Operations” section beginning on page FS-7 for discussions of net gains on asset sales during 2014. Asset dispositions and restructurings may also occur in future periods and could result in significant gains or losses.

FS--2


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

The company closely monitors developments in the financial and credit markets, the level of worldwide economic activity, and the implications for the company of changes in prices for crude oil and natural gas. Management takes these developments into account in the conduct of ongoing 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, production quotas or other actions imposed by the Organization of Petroleum Exporting Countries (OPEC), weather-related damage and disruptions, competing fuel prices, and regional supply interruptions or fears thereof that may be caused by military conflicts, civil unrest or political uncertainty. Any of these factors could also inhibit the 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. In recent years, Chevron and the oil and gas industry generally experienced an increase in certain costs that exceeded the general trend of inflation in many areas of the world. As a result of the decline in prices of crude oil and other commodities in 2014, these cost pressures are beginning to soften. Capital and exploratory expenditures and operating expenses can also be affected by damage to production facilities caused by severe weather or civil unrest.
The chart above shows the trend in benchmark prices for Brent crude oil, West Texas Intermediate (WTI) crude oil and U.S. Henry Hub natural gas. The Brent price averaged $99 per barrel for the full-year 2014, compared to $109 in 2013. As of mid-February 2015, the Brent price was $60 per barrel. The majority of the company’s equity crude production is priced based on the Brent benchmark. While geopolitical tensions and supply disruptions supported crude prices through mid-year, crude prices have since been in decline, as signs of crude oil over-supply emerged during the second half of the year due to continued robust non-OPEC supply growth, concern over softness in the global economic recovery, and material easing of geopolitical tensions and supply disruptions. Downward pressure on crude pricing has been further magnified by OPEC’s decision in November 2014 to maintain the current production ceiling of 30 million barrels per day despite evidence of market surplus.
The WTI price averaged $93 per barrel for the full-year 2014, compared to $98 in 2013. As of mid-February 2015, the WTI price was $53 per barrel. WTI traded at a discount to Brent throughout 2014 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 supply of heavy crude versus the demand, which is a function of the capacity of refineries that are able to process this lower quality feedstock into light products (motor gasoline, jet fuel, aviation gasoline and diesel fuel). After peaking early in second quarter 2014, the differential has eased in North America as refinery crude runs remained at or above record levels. Outside of North America, easing of geopolitical tensions and continued expansion of supply of light sweet crudes has pressured light sweet crude prices relative to those for heavier, more sour crudes.
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-11 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 $4.28 per thousand cubic feet (MCF) during 2014, compared with $3.70 during 2013. As of mid-February 2015, the Henry Hub spot price was $2.73 per MCF.
Outside the United States, price changes for natural gas depend on a wide range of supply, demand, regulatory and commercial factors. In some locations, Chevron is investing in long-term projects to install infrastructure to produce and liquefy natural gas for transport by tanker to other markets. The company's contract prices for liquefied natural gas (LNG) are typically linked to crude oil prices. Chevron's international natural gas realizations averaged $5.78 per MCF during 2014, compared with $5.91 per MCF during 2013. (See page FS-11 for the company’s average natural gas realizations for the U.S. and international regions.)
The company’s worldwide net oil-equivalent production in 2014 averaged 2.571 million million barrels per day. About one-fifth of the company’s net oil-equivalent production in 2014 occurred in the OPEC-member countries of Angola, Nigeria, Venezuela and the Partitioned Zone between Saudi Arabia and Kuwait. OPEC quotas had no effect on the company’s net crude oil production in 2014 or 2013. At their November 2014 meeting, members of OPEC supported maintaining the current production quota of 30 million barrels per day, which has been in effect since December 2008.
The company estimates that oil-equivalent production in 2015 will be flat to 3 percent growth compared to 2014. This estimate is subject to many factors and uncertainties, including the duration of the low price environment that began in second-half 2014; quotas that may be imposed by OPEC; price effects on entitlement volumes; changes in fiscal terms or restrictions on the scope of company operations; delays in 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

FS--4


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

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.
Net proved reserves for consolidated companies and affiliated companies totaled 11.1 billion barrels of oil equivalent at year-end 2014, a decrease of 1 percent from year-end 2013. The reserve replacement ratio in 2014 was 89 percent. Refer to Table V beginning on page FS-65 for a tabulation of the company’s proved net oil and gas reserves by geographic area, at the beginning of 2012 and each year-end from 2012 through 2014, and an accompanying discussion of major changes to proved reserves by geographic area for the three-year period ending December 31, 2014.
On November 7, 2011, while drilling a development well in the deepwater Frade Field about 75 miles offshore Brazil, an unanticipated pressure spike caused oil to migrate from the well bore through a series of fissures to the sea floor, emitting approximately 2,400 barrels of oil. The source of the seep was substantially contained within four days and the well was plugged and abandoned. On March 14, 2012, the company identified a small, second seep in a different part of the field. No evidence of any coastal or wildlife impacts related to either of these seeps have emerged. As reported in the company’s previously filed periodic reports, it has resolved civil claims relating to these incidents brought by a Brazilian federal district prosecutor. As also reported previously, the federal district prosecutor also filed criminal charges against Chevron and eleven Chevron employees. On February 19, 2013, the trial court dismissed the criminal matter, and on appeal, on October 9, 2013, the appellate court reinstated two of the ten allegations, specifically those charges alleging environmental damage and failure to provide timely notification to authorities. On February 27, 2014, Chevron filed a motion for reconsideration. While reconsideration of the motion to dismiss is pending, there will be further proceedings on the reinstated allegations. The company’s ultimate exposure related to the incident is not currently determinable.
Refer to the “Results of Operations” section on pages FS-7 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-7 through FS-9 for additional discussion of the company’s downstream operations.
All Other consists of mining activities, power and energy services, worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, and technology companies.

FS--5


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

Operating Developments
Key operating developments and other events during 2014 and early 2015 included the following:
Upstream
Argentina Signed additional agreements to continue the development of the Loma Campana Project in the Vaca Muerta Shale, and to begin exploration in the Narambuena area of the Neuquén Basin.
Australia Announced in January 2015 an additional binding sales agreement for delivery of LNG from the Gorgon Project for a five-year period starting in 2017. During the time of this agreement, more than 75 percent of Chevron's equity LNG offtake from the project is committed under binding sales agreements to customers in Asia.
Azerbaijan Achieved first production from the Chirag Oil Project in the Caspian Sea.
Bangladesh Announced first gas from the Bibiyana Expansion Project.
Canada Completed the sale of a 30 percent interest in the Duvernay shale play for $1.5 billion.
Chad/Cameroon Completed the sale of the company’s nonoperated interest in a producing concession in Chad and the related export pipeline interests in Chad and Cameroon for approximately $1.3 billion.
Kazakhstan/Russia Achieved a 230,000-barrel-per-day increase in capacity of the Caspian Pipeline Consortium pipeline.
Mauritania In early 2015, the company reached agreement to acquire a 30 percent nonoperated working interest in three contract areas offshore Mauritania, pending government approval.
Myanmar Announced the acquisition of offshore acreage.
New Zealand Announced the acquisition of three offshore blocks.
Nigeria Achieved initial production of product at the Escravos Gas-to-Liquids facility.
United States Announced initial crude oil and natural gas production from the Jack/St. Malo and Tubular Bells projects in the deepwater Gulf of Mexico.
Made significant crude oil discoveries at the Guadalupe and Anchor prospects in the deepwater Gulf of Mexico.
In early 2015, announced a joint venture to explore and appraise 24 jointly-held offshore leases in the northwest portion of Keathley Canyon in the deepwater Gulf of Mexico. The joint venture includes the Tiber and Gila discoveries and the Gibson prospect. The company acquired a 36 percent working interest in the Gila leases and 31 percent working interest in the Tiber leases and previously held a working interest in Gibson.
Reached a final investment decision for the Stampede Project in the deepwater Gulf of Mexico.
Completed the sale of natural gas liquids pipeline assets in Texas and southeastern New Mexico for $800 million.
Drilled 550 wells during 2014 in the Midland and Delaware basins in West Texas and southeast New Mexico.
Downstream
France Completed expansion project at the additives plant in Gonfreville, France.
Singapore Completed expansion project at the additives plant in Singapore.
United States Commenced commercial production at the new premium lubricants base oil facility in Pascagoula, Mississippi.
The company's 50 percent-owned Chevron Phillips Chemical Company, LLC (CPChem) achieved start-up of the world’s largest on-purpose 1-hexene plant, with a capacity of 250,000 metric tons per year, at its Cedar Bayou complex in Baytown, Texas.
Progressed construction of CPChem's U.S. Gulf Coast Petrochemicals Project.
Other
Common Stock Dividends The quarterly common stock dividend was increased by 7.0 percent in April 2014 to $1.07 per common share, making 2014 the 27th consecutive year that the company increased its annual dividend payout.
Common Stock Repurchase Program The company purchased $5.0 billion of its common stock in 2014 under its share repurchase program. Given the change in market conditions, the company is suspending the share repurchase program for 2015.

FS--6


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

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 12, beginning on page FS-37, 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-5.

U.S. Upstream
Millions of dollars
2014

 
 
2013

 
2012

Earnings
$
3,327

 
 
$
4,044

 
$
5,332

U.S. upstream earnings of $3.3 billion in 2014 decreased $717 million from 2013, primarily due to lower crude oil prices of $950 million. Higher depreciation expenses of $440 million and higher operating expenses of $210 million also contributed to the decline. Partially offsetting the decrease were higher gains on asset sales of $700 million in the current period compared with $60 million in 2013, higher natural gas realizations of $150 million and higher crude oil production of $100 million.
U.S. upstream earnings of $4.0 billion in 2013 decreased $1.3 billion from 2012, primarily due to higher operating, depreciation and exploration expenses of $420 million, $350 million, and $190 million, respectively, and lower crude oil production of $170 million. Higher natural gas realizations of approximately $200 million were mostly offset by lower crude oil realizations of $170 million.
The company’s average realization for U.S. crude oil and natural gas liquids in 2014 was $84.13 per barrel, compared with $93.46 in 2013 and $95.21 in 2012. The average natural gas realization was $3.90 per thousand cubic feet in 2014, compared with $3.37 and $2.64 in 2013 and 2012, respectively.
Net oil-equivalent production in 2014 averaged 664,000 barrels per day, up 1 percent from both 2013 and 2012. Between 2014 and 2013, production increases in the Permian Basin in Texas and New Mexico and the Marcellus Shale in western Pennsylvania were partially offset by normal field declines. Between 2013 and 2012, new production in the Marcellus Shale in western Pennsylvania and the Delaware Basin in New Mexico, along with the absence of weather-related downtime in the Gulf of Mexico, was largely offset by normal field declines.
The net liquids component of oil-equivalent production for 2014 averaged 456,000 barrels per day, up 2 percent from 2013 and largely unchanged from 2012. Net natural gas production averaged about 1.3 billion cubic feet per day in 2014, largely unchanged from 2013 and up 4 percent from 2012. Refer to the “Selected Operating Data” table on page FS-11 for a three-year comparative 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
2014

 
 
2013

 
2012

Earnings*
$
13,566

 
 
$
16,765

 
$
18,456

 
 
 
 
*Includes foreign currency effects:
$
597

 
 
$
559

 
$
(275
)
International upstream earnings were $13.6 billion in 2014 compared with $16.8 billion in 2013. The decrease between periods was primarily due to lower crude oil prices and sales volumes of $2.0 billion and $400 million, respectively. Also contributing to the decrease were higher depreciation expenses of $1.0 billion, mainly related to impairments and other asset writeoffs, and higher operating and tax expenses of $340 million and $310 million, respectively. Partially offsetting these items were gains on asset sales of $1.1 billion in 2014, compared with $140 million in 2013. Foreign currency effects increased earnings by $597 million in 2014, compared with an increase of $559 million a year earlier.
International upstream earnings were $16.8 billion in 2013 compared with $18.5 billion in 2012. The decrease was mainly due to the absence of 2012 gains of approximately $1.4 billion on an asset exchange in Australia and $600 million on the sale of an equity interest in the Wheatstone Project, lower crude oil prices of $500 million, and higher operating expense of $400 million. Partially offsetting these effects were lower income tax expenses of $430 million. Foreign currency effects increased earnings by $559 million in 2013, compared with a decrease of $275 million a year earlier.
The company’s average realization for international crude oil and natural gas liquids in 2014 was $90.42 per barrel, compared with $100.26 in 2013 and $101.88 in 2012. The average natural gas realization was $5.78 per thousand cubic feet in 2014, compared with $5.91 and $5.99 in 2013 and 2012, respectively.
International net oil-equivalent production was 1.91 million barrels per day in 2014, a decrease of 2 percent from 2013 and 2012. Production increases due to project ramp-ups in Nigeria, Argentina and Brazil in 2014 were more than offset by normal field declines, production entitlement effects in several locations and the effect of asset sales. The decline between 2013 and 2012 was a result of project ramp-ups in Nigeria and Angola in 2013 being more than offset by normal field declines.
The net liquids component of international oil-equivalent production was 1.25 million barrels per day in 2014, a decrease of approximately 2 percent from 2013 and a decrease of approximately 4 percent from 2012. International net natural gas production of 3.9 billion cubic feet per day in 2014 was down 1 percent from 2013 and up 1 percent from 2012.
Refer to the “Selected Operating Data” table, on page FS-11, for a three-year comparative of international production volumes.

U.S. Downstream
Millions of dollars
2014

 
 
2013

 
2012

Earnings
$
2,637

 
 
$
787

 
$
2,048

U.S. downstream operations earned $2.6 billion in 2014, compared with $787 million in 2013. Higher margins on refined product sales increased earnings $830 million. Gains from asset sales were $960 million in 2014, compared with $250 million a year earlier. Higher earnings from 50 percent-owned CPChem of $160 million and lower operating expenses of $80 million also contributed to the earnings increase.
U.S. downstream operations earned $787 million in 2013, compared with $2.0 billion in 2012. The decrease was mainly due to lower margins on refined product sales of $860 million and higher operating expenses of $600 million, reflecting repair and maintenance activities at the company's refineries. The decrease was partially offset by higher earnings of $150 million from 50 percent-owned CPChem.
Refined product sales of 1.21 million barrels per day in 2014 increased 2 percent, mainly reflecting higher gas oil sales. Sales volumes of refined products were 1.18 million barrels per day in 2013, a decrease of 2 percent from 2012, mainly reflecting lower gas oil and gasoline sales. U.S. branded gasoline sales of 516,000 barrels per day in 2014 were essentially unchanged from 2013 and 2012.
Refer to the “Selected Operating Data” table on page FS-11 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
2014

 
 
2013

 
2012

Earnings*
$
1,699

 
 
$
1,450

 
$
2,251

 
 
 
 
*Includes foreign currency effects:
$
(112
)
 
 
$
(76
)
 
$
(173
)
International downstream earned $1.7 billion in 2014, compared with $1.5 billion in 2013. The increase was mainly due to a favorable change in the effects on derivative instruments of $640 million. The increase was partially offset by the economic buyout of a legacy pension obligation of $160 million in the current period, lower margins on refined product sales of $130 million and higher tax expenses of $110 million. Foreign currency effects decreased earnings by $112 million in 2014, compared to a decrease of $76 million a year earlier.
International downstream earned $1.5 billion in 2013, compared with $2.3 billion in 2012. Earnings decreased due to lower gains on asset sales of $540 million and higher income tax expenses of $110 million. Foreign currency effects decreased earnings by $76 million in 2013, compared with a decrease of $173 million a year earlier.
Total refined product sales of 1.50 million barrels per day in 2014 declined 2 percent from 2013, mainly reflecting lower gas oil sales. Sales of 1.53 million barrels per day in 2013 declined 2 percent from 2012, mainly reflecting lower fuel oil and gasoline sales.
Refer to the “Selected Operating Data” table, on page FS-11, for a three-year comparison of sales volumes of gasoline and other refined products and refinery input volumes.

All Other
Millions of dollars
2014

 
 
2013

 
2012

Net charges*
$
(1,988
)
 
 
$
(1,623
)
 
$
(1,908
)
 
 
 
 
*Includes foreign currency effects:
$
2

 
 
$
(9
)
 
$
(6
)
All Other consists of mining activities, power and energy services, worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, and technology companies.
Net charges in 2014 increased $365 million from 2013, mainly due to environmental reserves additions, asset impairments and additional asset retirement obligations for mining assets, as well as higher corporate tax items. These increases were partially offset by the absence of 2013 impairments of power-related affiliates and lower other corporate charges. Net charges in 2013 decreased $285 million from 2012, mainly due to lower corporate tax items and other corporate charges.
 
Consolidated Statement of Income
Comparative amounts for certain income statement categories are shown below:
Millions of dollars
2014

 
 
2013

 
2012

Sales and other operating revenues
$
200,494

 
 
$
220,156

 
$
230,590

Sales and other operating revenues decreased in 2014 primarily due to lower crude oil volumes, and lower refined product and crude oil prices. The decrease between 2013 and 2012 was mainly due to lower refined product prices and lower crude oil volumes and prices.
Millions of dollars
2014

 
 
2013

 
2012

Income from equity affiliates
$
7,098

 
 
$
7,527

 
$
6,889

Income from equity affiliates decreased in 2014 from 2013 mainly due to lower upstream-related earnings from Tengizchevroil in Kazakhstan, Petropiar and Petroboscan in Venezuela, and Angola LNG. Partially offsetting these effects were higher downstream-related earnings from GS Caltex in South Korea, higher earnings from CPChem and the absence of 2013 impairments of power-related affiliates.
Income from equity affiliates increased in 2013 from 2012 mainly due to higher upstream-related earnings from Tengizchevroil in Kazakhstan and Petropiar in Venezuela, and higher earnings from CPChem, partially offset by 2013 impairments of power-related affiliates.
Refer to Note 13, beginning on page FS-40, 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
2014

 
 
2013

 
2012

Other income
$
4,378

 
 
$
1,165

 
$
4,430

Other income of $4.4 billion in 2014 included net gains from asset sales of $3.6 billion before-tax. Other income in 2013 and 2012 included net gains from asset sales of $710 million and $4.2 billion before-tax, respectively. Interest income was approximately $145 million in 2014, $136 million in 2013 and $166 million in 2012. Foreign currency effects increased other income by $277 million in 2014, while increasing other income by $103 million in 2013 and decreasing other income by $207 million in 2012.
Millions of dollars
2014

 
 
2013

 
2012

Purchased crude oil and products
$
119,671

 
 
$
134,696

 
$
140,766

Crude oil and product purchases of $119.7 billion were down in 2014 mainly due to lower crude oil and re