Delaware | 94-0890210 |
6001 Bollinger Canyon Road,
San Ramon, California 94583-2324 |
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1
2
21
22
Item 1.
Business
(a)
General
Development of Business
3
Table of Contents
Upstream
grow profitably in core
areas, build new legacy positions and commercialize the
companys equity natural-gas resource base while growing a
high-impact global gas business
Downstream
improve returns and
selectively grow, with a focus on integrated value creation
Invest in people
to achieve the companys
strategies
Leverage technology
to deliver superior
performance and growth
Build organizational capability
to deliver
world-class performance in operational excellence, cost
management, capital stewardship and profitable growth
4
Table of Contents
Crude Oil & Natural Gas
Oil-Equivalent (Thousands
Liquids (Thousands of
Natural Gas (Millions of
of Barrels per Day)
Barrels per Day)
Cubic Feet per Day)
2008
2007
2008
2007
2008
2007
215
221
201
205
88
97
160
214
86
118
439
576
149
153
76
77
441
457
147
155
58
60
533
569
671
743
421
460
1,501
1,699
154
179
145
171
52
48
154
129
142
126
72
15
29
32
28
31
5
4
13
8
11
7
12
7
2
3
2
3
1
2
352
351
328
338
142
76
217
224
67
71
894
916
106
112
103
109
20
17
96
100
34
39
376
372
71
47
2
2
414
275
66
66
41
41
153
149
29
61
28
60
7
5
26
26
5
5
128
126
22
26
19
22
22
22
15
17
89
100
648
679
299
349
2,103
1,982
235
241
182
195
319
277
106
115
71
78
208
220
61
63
37
41
142
132
44
47
37
39
45
50
37
36
36
35
4
5
35
30
209
178
32
29
189
174
9
4
2
3
40
5
6
6
6
6
1
1
330
330
189
202
838
765
1,565
1,601
998
1,084
3,402
3,100
2,236
2,344
1,419
1,544
4,903
4,799
267
248
230
212
222
220
2,503
2,592
1,649
1,756
5,125
5,019
production, net:
27
27
27
27
5
Table of Contents
Productive
2
Productive
2
Oil Wells
Gas Wells
Gross
Net
Gross
Net
25,726
23,921
188
44
1,489
1,214
922
701
23,729
8,460
10,587
4,824
50,944
33,595
11,697
5,569
2,126
723
17
7
2,479
1,150
2,468
1,560
7,879
7,737
203
165
1,091
680
275
105
13,575
10,290
2,963
1,837
64,519
43,885
14,660
7,406
1,174
413
7
2
65,693
44,298
14,667
7,408
881
549
411
318
1
Includes wells producing or capable
of producing and injection wells temporarily functioning as
producing wells. Wells that produce both oil and gas are
classified as oil wells.
2
Gross wells include the total
number of wells in which the company has an interest. Net wells
include wholly owned wells and the sum of the companys
fractional interests in gross wells.
6
Table of Contents
2008
2007
2006
4,735
4,665
5,294
2,615
2,422
2,512
19,022
19,137
19,910
4,053
3,003
2,974
7,905
7,855
8,612
3,291
2,922
3,008
*
Crude oil, condensate and natural
gas liquids
(Thousands of Acres)
Developed and
Undeveloped
2
Developed
2
Undeveloped
Gross
Net
Gross
Net
Gross
Net
138
122
183
176
321
298
2,108
1,500
1,568
1,141
3,676
2,641
3,441
2,784
4,461
2,497
7,902
5,281
5,687
4,406
6,212
3,814
11,899
8,220
17,686
7,710
2,487
921
20,173
8,631
45,429
22,447
5,937
2,649
51,366
25,096
8,031
5,348
383
341
8,414
5,689
35,236
19,957
1,924
613
37,160
20,570
106,382
55,462
10,731
4,524
117,113
59,986
112,069
59,868
16,943
8,338
129,012
68,206
640
300
259
104
899
404
112,709
60,168
17,202
8,442
129,911
68,610
1
Gross acreage includes the total
number of acres in all tracts in which the company has an
interest. Net acreage includes wholly owned interests and the
sum of the companys fractional interests in gross acreage.
2
Developed acreage is spaced or
assignable to productive wells. Undeveloped acreage is acreage
on which wells have not been drilled or completed to permit
commercial production and that may contain undeveloped proved
reserves. The gross undeveloped acres that will expire in 2009,
2010 and 2011 if production is not established by certain
required dates are 5,707, 8,290 and 4,720, respectively.
7
Table of Contents
Wells Drilling
Net Wells
Completed
1
at 12/31/08
2
2008
2007
2006
Gross
Net
Prod.
Dry
Prod.
Dry
Prod.
Dry
8
1
533
620
600
44
25
26
3
30
1
34
5
9
8
287
1
225
4
317
6
61
34
846
4
875
5
951
11
13
8
33
43
45
2
13
4
203
1
223
235
1
2
2
462
374
258
7
2
41
52
43
35
16
739
1
692
581
3
96
50
1,585
5
1,567
5
1,532
14
2
1
16
3
13
98
51
1,601
5
1,570
5
1,545
14
1
Indicates the fractional number of
wells completed during the year, regardless of when drilling was
initiated. Completion refers to the installation of permanent
equipment for the production of crude oil or natural gas or, in
the case of a dry well, the reporting of abandonment to the
appropriate agency.
2
Represents wells in the process of
drilling, including wells for which drilling was not completed
and which were temporarily suspended at the end of 2008. Gross
wells include the total number of wells in which the company has
an interest. Net wells include wholly owned wells and the sum of
the companys fractional interests in gross wells.
8
Table of Contents
Wells Drilling
Net Wells
Completed
1,2
at
12/31/08
3
2008
2007
2006
Gross
Net
Prod.
Dry
Prod.
Dry
Prod.
Dry
9
3
8
1
4
7
9
8
1
1
7
9
3
8
2
4
8
16
8
8
3
2
1
6
2
1
4
2
10
1
14
9
18
7
4
1
1
2
2
39
2
41
6
6
3
14
5
55
5
62
17
27
10
23
8
63
7
66
25
43
18
1
23
8
63
7
66
25
44
18
1
2007 conformed to 2008 presentation.
2
Indicates the fractional number of
wells completed during the year, regardless of when drilling was
initiated. Completion refers to the installation of permanent
equipment for the production of crude oil or natural gas or, in
the case of a dry well, the reporting of abandonment to the
appropriate agency. Some exploratory wells are not drilled with
the intention of producing from the well bore. In such cases,
completion refers to the completion of drilling.
Further categorization of productive or dry is based on the
determination as to whether hydrocarbons in a sufficient
quantity were found to justify completion as a producing well,
whether or not the well is actually going to be completed as a
producer.
3
Represents wells that are in the
process of drilling but have been neither abandoned nor
completed as of the last day of the year, including wells for
which drilling was not completed and which were temporarily
suspended at the end of 2008. Does not include wells for which
drilling was completed at year-end 2008 and that were reported
as suspended wells in Note 20 beginning on
page FS-48.
Gross wells include the total number of wells in which the
company has an interest. Net wells include wholly owned wells
and the sum of the companys fractional interests in gross
wells.
9
Table of Contents
Chevron has production and exploration activities in most of the worlds major hydrocarbon basins. The companys upstream strategy is to grow profitably in core areas, build new legacy positions and commercialize the companys equity natural-gas resource base while growing a high-impact global gas business. The map at left indicates Chevrons primary areas of production and exploration.
a)
United
States
California:
The company has significant production
in the San Joaquin Valley. In 2008, average net
oil-equivalent production was 215,000 barrels per day,
composed of 196,000 barrels of crude oil, 88 million
cubic feet of natural gas and 5,000 barrels of natural gas
liquids. Approximately 84 percent of the crude-oil
production is considered heavy oil (typically with API gravity
lower than 22 degrees).
Gulf of Mexico:
Average net oil-equivalent
production during 2008 for the companys combined interests
in the Gulf of Mexico shelf and deepwater areas, and the onshore
fields in the region was 160,000 barrels per day. The daily
oil-equivalent production comprised 76,000 barrels of crude
oil, 439 million cubic feet of natural gas and
10,000 barrels of natural gas liquids.
Production levels in 2008 were adversely affected by damage to
facilities caused by hurricanes Gustav and Ike in September. At
the end of 2008, approximately 50,000 barrels per day of
oil-equivalent production remained offline, with restoration of
the volumes to occur as repairs to third-party pipelines and
producing facilities are completed.
10
Table of Contents
Big Foot 60 percent-owned and operated. A
successful appraisal well was completed in first quarter 2008. A
final appraisal well began drilling in November 2008, and was
completed in January 2009. As of late February 2009, evaluation
of the drilling results was under way.
Buckskin 55 percent-owned and operated. A
successful wildcat well was completed in early 2009.
Jack & St. Malo 50 percent- and
41 percent-owned and operated interests, respectively. The
prospects are being evaluated together due to their relative
proximity. Successful appraisal wells were drilled during 2008
at both Jack and St. Malo, bringing the total wells drilled to
three at Jack and four at St. Malo.
Knotty Head 25 percent-owned and nonoperated
working interest. Subsurface studies continued during 2008 at
this 2005 discovery, with an appraisal well planned for third
quarter 2009.
Puma 22 percent-owned and nonoperated working
interest. An appraisal well began drilling in late 2008 and was
scheduled for completion in second quarter 2009.
Tubular Bells 30 percent-owned and nonoperated
working interest. An appraisal well was completed in 2008.
11
Table of Contents
The company operates in areas A and B of the 39 percent-owned Block 0, which averaged 109,000 barrels per day of net liquids production in 2008. The Block 0 concession extends through 2030.
Start-up
of the Mafumeira Field in Area A of Block 0 is expected in third quarter 2009, with crude-oil production ramping up to the expected maximum total of 35,000 barrels per day in 2011.
Two delineation wells were drilled in Area A. One well found commercial quantities of hydrocarbons and was placed into production during the year. The acquisition of seismic data started in late 2008 and is expected to be finalized in 2010.
Also in Area A are three gas management projects that are expected to eliminate routine flaring of natural gas by injecting excess natural gas into various reservoirs.
12
Table of Contents
In deepwater offshore, initial production occurred in July 2008 at the 68 percent-owned and operated Agbami Field in OML 127 and OML 128. The project is a subsea design, with wells tied back to a floating production, storage and offloading (FPSO) vessel. By year-end 2008, total crude-oil production was averaging approximately 130,000 barrels per day. Maximum total production of crude oil and natural gas liquids of 250,000 barrels per day is expected to be achieved by year-end 2009. The company initially recognized proved undeveloped reserves for Agbami in 2002. A portion of the proved undeveloped reserves was reclassified to proved developed in 2008 at production
start-up.
The total cost for the first phase of
13
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14
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Chevron has a 17 percent nonoperated working interest in the North West Shelf (NWS) Venture offshore Western Australia. Daily net production from the project during 2008 averaged 25,000 barrels of crude oil and condensate, 374 million cubic feet of natural gas, and 4,000 barrels of LPG. Approximately 70 percent of the natural gas was sold in the form of LNG to major utilities in Japan, South Korea and China, primarily under long-term contracts. The remaining natural gas was sold to the Western Australia domestic market.
In September 2008, a fifth LNG train increased processing and export capacity from approximately 12 million metric tons per year to more than 16 million. Part of the natural gas for these expanded facilities is being supplied from the Angel natural-gas field, which started production in October 2008. Additional supply will be provided by the North Rankin 2 project, for which an investment decision was made in March 2008. The project is scheduled to start production in 2013.Proved undeveloped reserves were booked in prior years and will be reclassified to proved developed upon completion of the project.
15
Table of Contents
In 2008, the companys daily net production from AIOC averaged 29,000 barrels of oil-equivalent. First oil from Phase III of ACG development occurred during the second quarter 2008. Reserves were reclassified to proved developed shortly before
start-up.
In early 2009, total production was averaging about 670,000 barrels per day. The AIOC operations are conducted under a
30-year
production-sharing contract (PSC) that expires in 2024.
Kazakhstan:
Chevron holds a 20 percent nonoperated working interest in the Karachaganak project, which is being developed in phases. During 2008, Karachaganak net oil-equivalent production averaged 66,000 barrels per day, composed of 41,000 barrels of liquids and 153 million cubic feet of natural gas. In 2008, access to the Caspian Pipeline Consortium (CPC) and Atyrau-Samara (Russia) pipelines enabled Karachaganak sales of
16
Table of Contents
Operated interests are in Pattani and other fields with ownership interests ranging from 35 percent to 80 percent in Blocks 10 through 13, B12/27, B8/32, 9A, G4/43 and G4/48. Blocks B8/32 and 9A produce crude oil and natural gas from six operating areas, and Blocks 10 through 13 and B12/27 produce crude oil, condensate and natural gas from 16 operating areas. First production from Block G4/43 occurred in first quarter 2008.
17
Table of Contents
The company holds a 49 percent operated interest in the Chuandongbei area in the onshore Sichuan Basin, where the company entered into a
30-year
PSC effective February 2008 to develop natural gas resources. Project plans included two sour-gas purification plants with an aggregate design capacity of 740 million cubic feet per day. A final investment decision was made for the first stage of the project in December 2008, and proved undeveloped reserves were recognized at that time.
In the South China Sea, the company has nonoperated working interests of 33 percent in Blocks 16/08 and 16/19 located in the Pearl River Delta Mouth Basin, 25 percent in the QHD-32-6 Field in Bohai Bay and 16 percent in the unitized and producing BZ
25-1
Field in Bohai Bay Block 11/19. Chevron also holds a 50 percent nonoperated working interest in one prospective onshore natural-gas block in the Ordos Basin.
18
Table of Contents
Chevrons operated interests in Indonesia are managed by
several wholly owned subsidiaries, including PT. Chevron Pacific
Indonesia (CPI). CPI holds operated interests of
100 percent in the Rokan and Siak PSCs. Other subsidiaries
operate four PSCs in the Kutei Basin, located offshore East
Kalimantan, and one PSC in the East Ambalat Block, located
offshore northeast Kalimantan. These interests range from
80 percent to 100 percent. Chevron also has
nonoperated working interests in a joint venture in Block B in
the South Natuna Sea and in the NE Madura III Block in the
East Java Sea Basin. Chevrons interests in these PSCs
range from 25 percent to 40 percent.
19
Table of Contents
e)
Other
International Areas
Brazil:
Chevron holds working interests ranging from 30 percent to 52 percent in three deepwater blocks in the Campos Basin. Chevron also holds a 20 percent nonoperated working interest in one block in the Santos Basin. None of these blocks had production in 2008.
In Block BC-4, located in the Campos Basin, the company is the operator and has a 52 percent interest in the Frade Field, which is under development as a subsea production design. Proved undeveloped reserves were recorded for the first time in 2005. Partial reclassification to the proved-developed category is scheduled upon production
start-up
in 2009. Estimated maximum total production of 87,000 oil-equivalent barrels per day is anticipated in 2011. The concession that includes the Frade project expires in 2025.
In the partner-operated Campos Basin Block BC-20, two areas 38 percent-owned Papa-Terra and 30 percent-owned Maromba were retained for development following the end of the exploration phase of this block. Evaluation of design options continued into
20
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Faroe Islands:
Chevron operates and holds a 40 percent interest in five offshore exploratory blocks. During 2008, the company acquired additional
2-D
seismic data for an area located near the Rosebank/Lochnagar discovery offshore the United Kingdom. Engineering and geological evaluation of the seismic data continued into early 2009. As of the end of 2008, proved reserves had not been recognized.
Netherlands:
Chevron is the operator and holds interests ranging from 34 percent to 80 percent in nine blocks in the Dutch sector of the North Sea. In 2008, the companys net oil-equivalent production from the five producing blocks was 9,000 barrels per day, composed of 2,000 barrels of crude oil and 40 million cubic feet of natural gas.
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23
Table of Contents
December 31, 2008
Operable
Refinery Inputs
Locations
Number
Capacity
2008
2007
2006
Mississippi
1
330
299
285
337
California
1
265
263
222
258
California
1
243
237
192
224
Hawaii
1
54
46
51
50
Utah
1
45
38
42
39
1
80
8
20
31
6
1,017
891
812
939
United Kingdom
1
210
203
212
165
South Africa
1
110
75
72
71
Canada
1
55
36
49
49
3
375
314
333
285
Various Locations
9
747
653
688
765
12
1,122
967
1,021
1,050
18
2,139
1,858
1,833
1,989
1
Asphalt plant in Perth Amboy, New
Jersey. Plant was idled during 2008.
2
Chevron holds 100 percent of
the common stock issued by Chevron South Africa (Pty) Limited,
which owns the Cape Town Refinery. A consortium of South African
partners owns preferred shares ultimately convertible to a
25 percent equity interest in Chevron South Africa (Pty)
Limited. None of the preferred shares had been converted as of
February 2009.
3
Chevron sold its 31 percent
interest in the Nerefco Refinery in the Netherlands in March
2007. During 2008, the company sold its 4 percent ownership
interest in a refinery in Abidjan, Côte dIvoire, and
its 8 percent ownership interest in a refinery in Cameroon,
decreasing the companys combined share of operable
capacity by about 5,000 barrels per day.
24
Table of Contents
2008
2007
2006
692
728
712
274
271
280
229
221
252
127
138
128
91
99
122
1,413
1,457
1,494
589
581
595
278
274
266
710
730
776
257
271
324
182
171
166
2,016
2,027
2,127
3,429
3,484
3,621
Includes buy/sell arrangements. Refer to Note 14 on page FS-43.
50
Principally naphtha, lubricants, asphalt and coke.
Includes share of equity affiliates sales:
512
492
492
25
Table of Contents
Net
Mileage
1
2,886
2,263
6,030
11,179
700
576
433
1,709
12,888
Partially owned pipelines are included at the companys
equity percentage.
Includes gathering lines related to the transportation function.
Excludes gathering lines related to U.S. and international
production activities.
Includes refined products, chemicals and natural gas liquids.
26
Table of Contents
U.S. Flag
Foreign Flag
Cargo Capacity
Cargo Capacity
Number
(Millions of Barrels)
Number
(Millions of Barrels)
3
0.8
1
1.1
2
0.7
18
27.1
17
14.6
5
1.5
36
42.8
*
One year or more.
27
Table of Contents
28
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29
Table of Contents
Item 1A.
Risk
Factors
30
Table of Contents
Item 1B.
Unresolved
Staff Comments
Item 2.
Properties
Item 3.
Legal
Proceedings
31
Table of Contents
Item 4.
Submission
of Matters to a Vote of Security Holders
32
Table of Contents
Item 5.
Market
for the Registrants Common Equity, Related Stockholder
Matters and Issuer Purchases of Equity Securities
Maximum
Total Number of
Number of Shares
Total Number
Average
Shares Purchased as
that May Yet be
of Shares
Price Paid
Part of Publicly
Purchased Under
Purchased
(1)(2)
per Share
Announced Program
the Program
14,185,681
67.71
14,184,858
7,687,933
72.46
7,665,000
6,373,015
76.05
6,367,989
28,246,629
70.88
28,217,847
(2
)
(1)
Includes 14,339 common shares repurchased during the three-month
period ended December 31, 2008, from company employees for
required personal income tax withholdings on the exercise of the
stock options issued to management and employees under the
companys broad-based employee stock options, long-term
incentive plans and former Texaco Inc. stock option plans. Also
includes 14,443 shares delivered or attested to in
satisfaction of the exercise price by holders of certain former
Texaco Inc. employee stock options exercised during the
three-month period ended December 31, 2008. The October
purchases also include approximately 14.2 million shares
acquired in an exchange transaction for a U.S. upstream property
and cash.
(2)
In September 2007, the company authorized stock repurchases of
up to $15 billion that may be made from time to time at
prevailing prices as permitted by securities laws and other
requirements and subject to market conditions and other factors.
The program will occur over a period of up to three years and
may be discontinued at any time. As of December 31, 2008,
118,996,749 shares had been acquired under this program for
$10.1 billion.
Item 6.
Selected
Financial Data
Item 7.
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
Item 7A.
Quantitative
and Qualitative Disclosures About Market Risk
Item 8.
Financial
Statements and Supplementary Data
33
Table of Contents
Item 9.
Changes
in and Disagreements With Accountants on Accounting and
Financial Disclosure
Item 9A.
Controls
and Procedures
(a)
Evaluation
of Disclosure Controls and Procedures
(b)
Managements
Report on Internal Control Over Financial Reporting
(c)
Changes
in Internal Control Over Financial Reporting
Item 9B.
Other
Information
34
Table of Contents
Name and Age
Current and Prior Positions (up to five years)
Current Areas of Responsibility
62
Chief Executive Officer
62
Vice Chairman of the Board (since 2002)
Policy, Government and Public Affairs; Human Resources
57
Executive Vice President (since 2003)
Technology; Chemicals; Mining; Health, Environment and Safety
58
Executive Vice President (since 2005) President of Chevron
Overseas
Petroleum Inc. (2002 to 2004)
Worldwide Exploration and Production Activities and Global Gas
Activities, including Natural Gas Trading
52
Executive Vice President (since 2008)
Vice President and President of Chevron
International Exploration and Production Company
(2005 through 2007)
Vice President and Chief Financial
Officer (2000 through 2004)
Business Development, Mergers and Acquisitions, Strategic
Planning, Project Resources Company, Procurement
48
Executive Vice President (since 2006) President of Global Supply
and Trading
(2004 to 2006)
President of Marketing, Asia, Middle East and Africa
Marketing
Business Unit (2001 to 2004)
Global Refining, Marketing, Lubricants, and Supply and Trading,
excluding Natural Gas Trading
52
Vice President and Chief Financial
Officer (since 2009)
Vice President and Treasurer
(2007 through 2008)
Vice President, Policy, Government and
Public Affairs (2002 to 2007)
Finance
54
Vice President and General Counsel
(since 2002)
Law
35
Table of Contents
36
Item 15.
Exhibits,
Financial Statement Schedules
Page(s)
FS-26
FS-27
FS-28
FS-29
FS-30
FS-31
FS-32 to FS-59
Included on page 38 is Schedule II
Valuation and Qualifying Accounts.
The Exhibit Index on pages
E-1
and
E-2
lists
the exhibits that are filed as part of this report.
37
Table of Contents
Millions of Dollars
Year Ended December 31
2008
2007
2006
$
117
$
28
$
91
(13
)
106
(21
)
(60
)
(17
)
(42
)
$
44
$
117
$
28
$
200
$
217
$
198
105
29
61
(30
)
(46
)
(42
)
$
275
$
200
$
217
$
5,949
$
4,391
$
3,249
2,599
1,894
1,700
(77
)
(1,013
)
(336
)
(481
)
$
7,535
$
5,949
$
4,391
*
See also Note 16 to the
Consolidated Financial Statements beginning on
page FS-45.
38
Table of Contents
Financial
Table of Contents
FS-2
FS-25
FS-32
FS-1
Key Financial Results
Income by Major Operating Area
Business Environment and Outlook
ments. Earnings for the company in any period
may also be influenced by events or transactions that
are infrequent and/ or unusual in nature.
FS-2
The company has been closely monitoring the ongoing uncertainty in financial and credit
markets, the rapid decline in crude-oil prices that began in the second half of 2008, and the
general contraction of worldwide economic activity. Management is taking these developments into
account in the conduct of daily operations and for business planning. The company remains confident of its underlying financial strength to deal with potential problems presented in this
environment.
Upstream
Earnings for the upstream segment are closely aligned with industry price levels 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 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. Moreover, any of these factors could also inhibit the companys
production capacity in an affected region. The company monitors developments closely in the
countries in which it operates and holds investments, and attempts to manage risks in operating its
facilities and business.
Industry price levels for crude oil were volatile during 2008. The spot price for West Texas
Intermediate (WTI) crude oil, a benchmark crude, started 2008 at $96 per barrel and peaked at $147
in early July. At the end of the year, the WTI price had fallen to $45 per barrel. As of
mid-February 2009, the WTI price was $38 per barrel. The collapse in price during the second half
of 2008 was largely driven by a decline in the demand for crude oil that was associated with a
significant weakening in world economies. The WTI price averaged $100 per barrel for the full-year
2008, compared with $72 in 2007.
FS-3
the Henry Hub price was about $5.60 and $4.70 per MCF, respectively. Fluctuations in the price
for natural gas in the United States are closely associated with the volumes produced in North
America and the inventory in underground storage relative to customer demand. U.S. natural gas
prices are also typically higher during the winter period when demand for heating is greatest.
The company estimates that oil-equivalent production in 2009 will average approximately 2.63
million barrels per day. This estimate is subject to many uncertainties, including quotas that may
be imposed by OPEC, price effects on production volumes calculated under cost-recovery and
variable-royalty provisions of certain contracts, changes in fiscal terms or restrictions on the
scope of company operations, delays in project startups, fluctuations in demand for natural gas in
various markets, weather conditions that may shut in production, civil unrest, changing
geopolitics, or other disruptions to operations. Future production levels also are 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. Most of Chevrons upstream
investment is currently being made outside the United States. Investments in upstream projects
generally are made well in advance of the start of the associated production of crude oil and
natural gas.
Downstream
Earnings for the downstream segment are closely tied to margins on the refining
and marketing of products that include gasoline, diesel, jet fuel, lubricants, fuel oil and
feedstocks for chemical manufacturing. Industry margins are sometimes volatile and can be affected
by the global and regional supply-and-demand balance for refined products and by changes in the
price of crude oil used for refinery feedstock. Industry margins can also be influenced by refined-product inventory levels, geopolitical events, refinery maintenance programs and disruptions
at refineries resulting from unplanned outages that may be due to severe weather or other
operational events.
FS-4
the crude-oil and product-supply functions and the economic returns on invested capital. Profitability can also
be affected by the volatility of tanker-charter rates for the companys shipping operations, which
are driven by the industrys demand for crude oil and product tankers. Other factors beyond the
companys control include the general level of inflation and energy costs to operate the companys
refinery and distribution network.
Chemicals
Earnings in the petrochemicals business are closely tied to global chemical demand,
industry inventory levels and plant capacity utilization. Feedstock and fuel costs, which tend to
follow crude oil and natural gas price movements, also influence earnings in this segment.
Operating Developments
Upstream
Indonesia
Achieved first oil at North Duri Field Area 12, which Chevron operates with a 100
percent interest. Maximum total crude-oil production of 34,000 barrels per day is expected in 2012.
Downstream
FS-5
Other
Results of Operations
U.S. Upstream Exploration and Production
U.S upstream income of $7.1 billion in 2008 increased $2.6 billion from 2007. Higher average prices
for crude oil and natural gas increased earnings by $3.1 billion between periods. Also contributing
to the higher earnings were gains of approximately $1 billion on asset sales, including a $600
million gain on an asset-exchange transaction. Partially offsetting these benefits were adverse
effects of about $1.6 billion associated with lower oil-equivalent production and higher operating
expenses, which included approximately $400 million of expenses resulting from damage to facilities
in the Gulf of Mexico caused by hurricanes Gustav and Ike in September.
Net oil-equivalent production in 2008 averaged 671,000 barrels per day, down 9.7 percent and
12.1 percent from 2007 and 2006, respectively. The decrease between 2007 and 2008 was mainly due to
normal field declines and the adverse impact of the hurricanes. The decline in 2007 from 2006 was
due primarily to normal field declines. The net liquids component of oil-equivalent production for
2008 averaged 421,000 barrels per day, down approximately 8 percent from 2007 and down 9 percent
compared with 2006. Net natural gas production averaged 1.5 billion cubic feet per day in 2008,
down 12 percent from 2007 and down 17 percent from 2006.
International Upstream Exploration and Production
International upstream income of $14.6 billion in 2008 increased $4.3 billion from 2007.
Higher prices for crude oil and natural gas increased earnings by $4.9 billion. Partially
offsetting the benefit of higher prices was an impact of about $1.8 billion associated with a
reduction of crude-oil sales volumes due to
timing of certain cargo liftings and higher depreciation and operating expenses. Foreign
currency effects benefited earnings by $873 million in 2008, compared with reductions to earnings
of $417 million in 2007 and $371 million in 2006.
FS-6
Income in 2007 of $10.3 billion increased $1.4 billion from 2006. Earnings in 2007 benefited
approximately $1.6 billion from higher prices, primarily for crude oil, and $300 million from
increased liftings. Non-recurring income-tax items also benefited earnings between periods. These
benefits to income were partially offset by the impact of higher operating and depreciation
expenses.
U.S. Downstream Refining, Marketing and Transportation
U.S downstream earnings of $1.4 billion in 2008
increased about $400 million from 2007 due mainly to
improved margins on the sale of refined products and
gains on derivative commodity instruments. Operating
expenses were higher between periods. Income of $966
million in 2007 decreased nearly $1 billion from 2006.
The decline was associated mainly with lower refined-product margins and higher planned and unplanned
refinery downtime than a year earlier. Operating
expenses were also higher in 2007 than in 2006.
International Downstream Refining, Marketing and Transportation
International downstream income of $2.1 billion in
2008 decreased nearly $500 million from 2007. Earnings
in 2007 included gains of approximately $1 billion on
the sale of assets, which included an interest in a
refinery and marketing assets in the Benelux region of
Europe. The $500 million improvement otherwise between
years was associated primarily with a benefit from
gains on derivative commodity instruments that was only
partially offset by the impact of lower margins on the
sale of refined products. Foreign currency effects
increased earnings by $193 million in 2008, compared
with $62 million in 2007. Income in 2007 of $2.5
billion increased $500 million from 2006, largely due
to the gains on asset sales. Margins on the sale of
refined products in 2007 were up slightly from 2006.
Operating expenses were higher, and earnings from the
companys shipping operations were lower.
FS-7
Refined-product
sales volumes were 2.02
million barrels per day
in 2008, about 1 percent
lower than 2007 due
mainly to reduced sales
of gas oil and fuel oil.
Refined product sales
volumes were 2.03 million
barrels per day in 2007,
about 5 percent lower
than 2006. The decline in
2007 was largely due to
the impact of asset sales
and the accounting-standard
change for buy/sell
contracts. Excluding the
accounting change, sales
decreased about 4
percent.
Chemicals
The chemicals segment includes the companys
Oronite subsidiary and the 50 percent-owned Chevron
Phillips Chemical Company LLC (CPChem). In 2008,
earnings were $182 million, compared with $396 million
and $539 million in 2007 and 2006, respectively.
Earnings declined in 2008 due to lower sales volumes of
commodity chemicals by CPChem. Higher expenses for
planned maintenance activities also contributed to the
earnings decline. Earnings also declined for the
companys Oronite subsidiary due to lower volumes and
higher operating expenses. In 2007, earnings of $396
million decreased $143 million from 2006 due to the impact
of lower margins on the sale of commodity chemicals by
CPChem that were only partially offset by improved
margins on Oronites sales of additives for lubricants
and fuel.
All Other
All Other includes mining operations, power generation businesses,
worldwide cash management and debt financing activities, corporate
administrative functions, insurance operations, real estate activities,
alternative fuels and technology companies, and the companys interest in
Dynegy prior to its sale in May 2007.
Consolidated Statement of Income
Sales and other operating revenues increased in
the comparative periods due mainly to higher prices
for crude oil, natural gas and refined products.
FS-8
Other income of $2.7 billion in 2008 included gains of approximately $1.3 billion on asset
sales. Other income of $2.7 billion in 2007 included net gains of $1.7 billion from asset sales and
a loss of $245 million on the early redemption of debt. Interest income was approximately $340
million in 2008 and $600 million in both 2007 and 2006. Foreign currency effects benefited other
income by $355 million in 2008 while reducing other income by $352 million and $260 million in 2007
and 2006, respectively.
Crude oil and product purchases in 2008 increased $38.1 billion from 2007 due to higher prices
for crude oil, natural gas and refined products. Crude oil and product purchases in 2007 increased
more than $5 billion from 2006 due to these same factors.
Operating, selling, general and administrative expenses in 2008 increased approximately $3.7
billion from 2007 primarily due to $1.2 billion of higher costs for employee and contract labor;
$800 million of increased costs for materials, services and equipment; $700 million of uninsured
losses associated with hurricanes in the Gulf of Mexico in 2008; and an increase of about $300
million for environmental remediation activities. Total expenses were about $3.1 billion higher in
2007 than in 2006. Increases were recorded in a number of categories, including $1.5 billion of
higher costs for employee and contract labor.
Exploration expenses in 2008 declined from 2007 due mainly to lower amounts for well
write-offs for operations in the United States. Expenses in 2007 were essentially unchanged from
2006.
Depreciation, depletion and amortization expenses increased in 2008 from 2007 largely due to
higher depreciation rates for certain crude oil and natural gas producing fields, reflecting
completion of higher-cost development projects and asset-retirement obligations. The increase
between 2006 and 2007 reflects an increase in charges related to asset write-downs and higher
depreciation rates for certain crude oil and natural gas producing fields worldwide.
Taxes other than on income decreased between 2007 and 2008 periods mainly due to lower import
duties as a result of the effects of the 2007 sales of the companys Benelux refining and
marketing businesses and a decline in import volumes in the United Kingdom. Taxes other than on
income increased between 2006 and 2007 due to higher import duties in the companys U.K. downstream
operations in 2007.
Interest and debt expense decreased significantly in 2008 because all interest-related
amounts were being capitalized. Interest and debt expense in 2007 decreased from 2006 primarily due
to lower average debt balances and higher amounts of interest capitalized.
Effective income tax rates were 44 percent in 2008, 42 percent in 2007 and 46 percent in 2006.
Rates were higher between 2007 and 2008 primarily due to a greater proportion of income earned in
tax jurisdictions with higher income tax rates. In addition, the 2007 period included a relatively
low effective tax rate on the sale of the companys investment in Dynegy common stock and the sale
of downstream assets in Europe. Rates were lower in 2007 compared with 2006 due mainly to the
impact of nonrecurring items in 2007 mentioned above and the absence of 2006 charges related to a
tax-law change that increased tax rates on upstream operations in the U.K. North Sea and the
settlement of a tax claim in Venezuela. Refer also to the discussion of income taxes in Note 16
beginning on page FS-45.
FS-9
Selected Operating Data
1,2
Liquidity and Capital Resources
FS-10
unsecured indebtedness at interest rates based on London Interbank Offered Rate or an average of
base lending rates published by specified banks and on terms reflecting the companys strong
credit rating. No borrowings were outstanding under these facilities at December 31, 2008. In
addition, the company has an automatic shelf registration statement that expires in March 2010 for
an unspecified amount of nonconvertible debt securities issued or guaranteed by the company. In
January 2009, the companys Board of Directors authorized the issuance of one or more series of
notes or debentures in an aggregate amount up to $5 billion for a term not to exceed ten years.
FS-11
Capital and Exploratory Expenditures
Worldwide downstream spending in 2009 is
estimated at $4.3 billion, with about $2.0 billion
for projects in the United States. Capital projects
include upgrades to refineries in the United States
and South Korea and construction of a gas-to-liquids
facility in support of associated upstream projects.
Financial Ratios
Financial Ratios
Current Ratio
current assets divided by current
liabilities. The current ratio in all periods was
adversely affected by the fact that Chevrons
inventories are valued on a Last-In, First-Out basis.
At year-end 2008, the book value of inventory was lower
than replacement costs, based on average acquisition
costs during the year, by approximately $9 billion.
Interest Coverage Ratio
income before
income tax expense, plus interest and debt expense and
amortization of capitalized interest, divided by before-tax
interest costs. The companys interest coverage ratio was higher
between 2007 and 2008 and between 2006 and 2007, primarily due to higher
before-tax income and lower average debt balances in each of the subsequent years.
Guarantees, Off-Balance-Sheet Arrangements and
Contractual Obligations, and Other Contingencies
Direct Guarantee
The companys guarantee of approximately $600
million is associated with certain payments under a
terminal-use agreement entered into by a company affiliate. The terminal is expected to be operational by
2012. Over the approximate 16-year term of the
guarantee, the maximum guarantee amount will be reduced
as certain fees are paid by the affiliate.
FS-12
There are numerous cross-indemnity agreements with the
affiliate and the other partners to permit recovery of
any amounts paid under the guarantee. Chevron has
recorded no liability for its obligation under this
guarantee.
Long-Term Unconditional Purchase Obligations and
Commitments, Including Throughput and Take-or-Pay
Agreements
The company and its subsidiaries have
certain other contingent liabilities relating to
long-term unconditional purchase obligations and
commitments, including throughput and take-or-pay
agreements, some of which relate to
suppliers financing arrangements. The agreements typically
provide goods and services, such as pipeline and
storage capacity, drilling rigs, utilities, and
petroleum products, to be used or sold in the
ordinary course of the companys business. The
aggregate approximate amounts of required payments
under these various commitments are: 2009 $6.4
billion; 2010 $4.0 billion; 2011 $3.6 billion;
2012 $1.5 billion; 2013 $1.3 billion; 2014 and
after $4.3 billion. A portion of these commitments
may ultimately be shared with project partners. Total
payments under the agreements were approximately $5.1
billion in 2008, $3.7 billion in 2007 and $3.0
billion in 2006.
Contractual Obligations
1
Financial and Derivative Instruments
FS-13
Factors in Part I,
Item 1A, of the
companys 2008 Annual Report on Form 10-K.
Foreign Currency
The company enters into forward
exchange contracts, generally with terms of 180 days
or less, to manage some of its foreign currency
exposures. These exposures include revenue and
anticipated purchase transactions, including foreign
currency capital expenditures and lease commitments,
forecasted to occur within 180 days. The forward
exchange contracts are recorded at fair value on the
balance sheet with resulting gains and losses reflected in income.
FS-14
Transactions With Related Parties
Litigation and Other Contingencies
oil company, as
the majority partner; since 1990, the operations have been conducted solely by Petroecuador. At the
conclusion of the consortium and following an
independent third-party environmental audit of the concession area, Texpet entered into a
formal agreement with the Republic of Ecuador and Petroecuador for Texpet to remediate specific
sites assigned by the government in proportion to Texpets ownership share of the consortium.
Pursuant to that agreement, Texpet conducted a three-year remediation program at a cost of $40
million. After certifying that the sites were properly remediated, the government granted Texpet
and all related corporate entities a full release from any and all environmental liability arising
from the consortium operations.
FS-15
estimate a reasonable possible loss (or a range of loss).
Environmental
The company is
subject to loss contingencies pursuant to
environmental laws and regulations that in
the future may require the company to take
action to correct or ameliorate the
effects on the environment of prior release
of chemicals or petroleum substances, including MTBE, by the company
or other parties. Such
contingencies may exist for various sites, including, but not limited to, federal Superfund sites and analogous sites under
state laws, refineries, crude oil fields, service stations, terminals, land development areas, and
mining operations, whether operating, closed or divested. These future costs are not fully
determinable due to such factors as the unknown magnitude of possible contamination, the unknown
timing and extent of the corrective actions that may be required, the determination of the
companys liability in proportion to other responsible parties, and the extent to which such
costs are recoverable from third parties.
Although the company has provided for known environmental obligations that are probable and
reasonably estimable, the amount of additional future costs may be material to results of
operations in the period in which they are recognized. The company does not expect these costs will
have a material effect on its consolidated financial position or liquidity. Also, the company does
not believe its obligations to make such expenditures have had, or will have, any significant
impact on the companys competitive position relative to other U.S. or international petroleum or
chemical companies.
the company had been identified as a potentially responsible party or otherwise
involved in the remediation by the U.S. Environmental Protection Agency (EPA) or other regulatory
agencies under the provisions of the federal Superfund law or analogous state laws. The companys
remediation reserve for these sites at year-end 2008 was $120 million. The federal Superfund law and analogous state laws provide for joint
and several liability for all responsible parties. Any future actions by the EPA or other
regulatory agencies to require Chevron to assume other potentially responsible parties costs at
designated hazardous waste sites are not expected to have a material effect on the companys
consolidated financial position or liquidity.
FS-16
reasonably estimated. The liability balance of approximately $9.4 billion for asset
retirement obligations at year-end 2008 related primarily to upstream properties.
that could be classified as proved. The effect on exploration expenses
in future periods of the $2.1 billion of suspended wells at year-end 2008 is uncertain pending
future activities, including normal project evaluation and additional drilling.
Environmental Matters
FS-17
sidered
acceptable at the time but now require investigative or remedial work or both to
meet current standards.
Critical Accounting Estimates and Assumptions
Besides those meeting these critical criteria,
the company makes many other accounting estimates and
assumptions in preparing its financial statements and
related disclosures. Although not associated with
highly uncertain matters, these estimates and
assumptions are also subject to revision as
circumstances warrant, and materially different
results may sometimes occur.
FS-18
and
assumptions, including those deemed critical, and
the associated disclosures in this discussion have
been discussed by management with the Audit Committee
of the Board of Directors.
FS-19
dependent upon plan-investment results,
changes in pension obligations, regulatory requirements
and other economic factors. Additional funding may be
required if investment returns are insufficient to
offset increases in plan obligations.
proved-reserve
quantities. If the carrying value of an asset exceeds
the future undiscounted cash flows expected from the
asset, an impairment charge is recorded for the excess
of carrying value of the asset over its estimated fair
value.
FS-20
of sale of a particular asset or
asset group in any period has been deemed more likely
than not, an impairment review is performed, and if the
estimated net proceeds exceed the carrying value of the
asset or asset group, no impairment charge is required.
Such calculations are reviewed each period until the
asset or asset group is disposed of. Assets that are
not impaired on a held-and-used basis could possibly
become impaired if a decision is made to sell such
assets. That is, the assets would be impaired if they
are classified as held-for-sale and the estimated
proceeds from the sale, less costs to sell, are less
than the assets associated carrying values.
efits are recognized only
if management determines the tax position is more
likely than not (i.e., likelihood greater than 50
percent) to be allowed by the tax jurisdiction. For
additional discussion of income tax uncertainties,
refer to Note 16 beginning on page FS-45. Refer also to
the business segment discussions elsewhere in this
section for the effect on earnings from losses
associated with certain litigation, and environmental
remediation and tax matters for the three years ended
December 31, 2008.
New Accounting Standards
FS-21
equity section of the
Consolidated Balance Sheet but separate from the
parents equity. It also requires the amount of
consolidated net income attributable to the parent and
the noncontrolling interest to be clearly identified
and presented on the face of the Consolidated
Statement of Income. Certain changes in a parents
ownership interest are to be accounted for as equity
transactions and when a subsidiary is deconsolidated,
any noncontrolling equity investment in the former
subsidiary is to be initially measured at fair value.
Implementation of FAS 160 will not significantly
change the presentation of the companys Consolidated
Statement of Income or Consolidated Balance Sheet.
be expanded to include a tabular
representation of the location and fair value amounts
of derivative instruments on the balance sheet, fair
value gains and losses on the income statement and
gains and losses associated with cash flow hedges
recognized in earnings and other comprehensive income.
FS-22
THIS
PAGE INTENTIONALLY LEFT BLANK
FS-23
Quarterly Results and Stock Market Data
Unaudited
The companys common stock is listed on the New York Stock Exchange (trading symbol: CVX). As of
February 20, 2009, stockholders of record numbered approximately
205,000. There are no restrictions
on the companys ability to pay dividends.
FS-24
Managements Responsibility for Financial Statements
To the Stockholders of Chevron Corporation
Managements Report on Internal Control Over Financial Reporting
The companys 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 companys
management, including the Chief Executive Officer and Chief Financial Officer, conducted an
evaluation of the effectiveness of the companys internal control over financial reporting based on
the
Internal Control Integrated Framework
issued by the Committee of Sponsoring Organizations of
the Treadway Commission. Based on the results of this evaluation, the companys management
concluded that internal control over financial reporting was effective as of December 31, 2008.
February 26, 2009
FS-25
Report
of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of Chevron Corporation:
In our opinion, the accompanying consolidated balance
sheets and the related consolidated statements of income,
comprehensive income, stockholders equity and cash flows
present fairly, in all material respects, the
financial position of Chevron Corporation and its
subsidiaries at December 31, 2008 and December 31, 2007
and the results of their
operations and their cash flows for each of the three
years in the period ended December 31, 2008 in conformity
with accounting principles generally accepted in the
United States of America. In addition, in our opinion,
the financial statement schedule listed in the index
appearing under Item 15(a)(2) presents fairly, in all
material respects, the information set forth therein when
read in conjunction with the related consolidated
financial statements. Also in our opinion, the Company
maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2008
based on criteria established in
Internal Control
Integrated Framework
issued by the Committee of
Sponsoring Organizations of the Treadway Commission
(COSO). The Companys management is responsible for these
financial statements and financial statement schedule,
for maintaining effective internal control over financial
reporting and for its assessment of the effectiveness of
internal control over financial reporting, included in
the accompanying Managements Report on Internal Control
Over Financial Reporting. Our responsibility is to
express opinions on these financial statements, on the
financial statement schedule, and on the Companys
internal control over financial reporting based on our
integrated audits. We conducted our audits in accordance
with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require
that we plan and perform the audits to obtain reasonable
assurance about whether the financial statements are free
of material misstatement and whether effective internal
control over financial reporting was maintained in all
material respects. Our audits of the financial statements
included examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant
estimates made by management, and evaluating the overall
financial statement presentation. Our audit of internal
control over financial reporting included obtaining an
understanding of internal control over financial
reporting, assessing the risk that a material weakness
exists, and
testing and evaluating the design and
operating effectiveness of internal control based on the
assessed risk. Our audits also included performing such
other procedures as we considered necessary in the
circumstances. We believe that our audits provide a
reasonable basis for our opinions.
/s/PricewaterhouseCoopers LLP
San Francisco, California
FS-26
Consolidated
Statement of Income
Millions of dollars, except per-share amounts
See accompanying Notes to the Consolidated Financial Statements.
FS-27
See accompanying Notes to the Consolidated Financial Statements.
FS-28
See accompanying Notes to the Consolidated Financial Statements.
FS-29
See accompanying Notes to the Consolidated Financial Statements.
FS-30
Consolidated Statement of Stockholders Equity
FS-31
Subsidiary and Affiliated Companies
The Consolidated Financial Statements include the accounts of
controlled subsidiary companies more than 50 percent-owned and variable-interest entities in which
the company is the primary beneficiary. Undivided interests in oil and gas joint ventures and
certain other assets are consolidated on a proportionate basis. Investments in and advances to
affiliates in which the company has a substantial ownership interest of approximately 20 percent to
50 percent or for which the company exercises significant influence but not control over policy
decisions are accounted for by the equity method. As part of that accounting, the company
recognizes gains and losses that arise from the issuance of stock by an affiliate that results in
changes in the companys proportionate share of the dollar amount of the affiliates equity
currently in income.
performance, and the companys ability and intention to retain its investment for a period
that will be sufficient to allow for any anticipated recovery in the investments market value. The
new cost basis of investments in these equity investees is not changed for subsequent recoveries in
fair value.
Derivatives
The majority of the companys activity in derivative commodity instruments is intended
to manage the financial risk posed by physical transactions. For some of this derivative activity,
generally limited to large, discrete or infrequently occurring transactions, the company may elect
to apply fair value or cash flow hedge accounting. For other similar derivative instruments,
generally because of the short-term nature of the contracts or their limited use, the company does
not apply hedge accounting, and changes in the fair value of those contracts are reflected in
current income. For the companys commodity trading activity and foreign currency exposures, gains
and losses from derivative instruments are reported in current income. Interest rate swaps
hedging a portion of the companys fixed-rate debt are accounted for as fair value hedges,
whereas interest rate swaps relating to a portion of the companys floating-rate debt are recorded
at fair value on the Consolidated Balance Sheet, with resulting gains and losses reflected in
income. Where Chevron is a party to master netting arrangements, fair value receivable and payable
amounts recognized for derivative instruments executed with the same counterparty are offset on the
balance sheet.
Short-Term Investments
All short-term investments are classified as available for sale and are in
highly liquid debt securities. Those investments that are part of the companys cash management
portfolio and have original maturities of three months or less are reported as Cash equivalents.
The balance of the short-term investments is reported as Marketable securities and is
marked-to-market, with any unrealized gains or losses included in Other comprehensive income.
Inventories
Crude oil, petroleum products and chemicals are generally stated at cost, using a
Last-In, First-Out (LIFO) method. In the aggregate, these costs are below market. Materials,
supplies and other inventories generally are stated at average cost.
FS-32
legal obligation associated with the retirement of a
long-lived asset and the amount can be reasonably estimated. Refer also to Note 24, beginning on
page FS-58, relating to AROs.
Goodwill
Goodwill resulting from a business combination is not subject to amortization. As required
by FASB Statement No. 142,
Goodwill and Other Intangible Assets
, the company tests such goodwill at
the reporting unit level for impairment on an annual basis and between annual tests if an event
occurs or circumstances change that would more likely than not reduce the fair value of a reporting
unit below its carrying amount.
Environmental Expenditures
Environmental expenditures that relate to ongoing operations or to
conditions caused by past operations are expensed. Expenditures that create future benefits or
contribute to future revenue generation are capitalized.
FS-33
Currency Translation
The U.S. dollar is the functional
currency for substantially all of the companys
consolidated operations and those of its equity
affiliates. For those operations, all gains and losses
from currency translations are currently included in
income. The cumulative translation effects for those
few entities, both consolidated and affiliated, using
functional currencies other than the U.S. dollar are
included in the currency translation adjustment in
Stockholders Equity.
Revenue Recognition
Revenues associated with sales of
crude oil, natural gas, coal, petroleum and chemicals
products, and all other sources are recorded when title
passes to the customer, net of royalties, discounts and
allowances, as applicable. Revenues from natural gas
production from properties in which Chevron has an
interest with other producers are generally recognized
on the basis of the companys net working interest
(entitlement method). Excise, value-added and similar
taxes assessed by a governmental authority on a
revenue-producing transaction between a seller and a
customer are presented on a gross basis. The associated
amounts are shown as a footnote to the Consolidated
Statement of Income on page FS-27. Refer to Note 14, on
page FS-43, for a discussion of the accounting for
buy/sell arrangements.
Stock Options and Other Share-Based Compensation
The
company issues stock options and other share-based
compensation to its employees and accounts for these
transactions under the provisions of FASB Statement
No. 123R,
Share-Based Payment
(FAS 123R). For equity
awards, such as stock options, total compensation cost
is based on the grant date fair value and for
liability awards,
such as stock appreciation rights, total compensation
cost is based on the settlement
Note 2
Information Relating to the Consolidated Statement of Cash Flows
FS-34
Note 3
Note 4
FS-35
Note 5
There were no restrictions on CTCs ability to
pay dividends or make loans or advances at December
31, 2008.
Note 6
Note 7
FS-36
are reported as either Sales and other operating
revenues or Purchased crude oil and products,
whereas trading gains and losses are reported as Other
income.
Foreign Currency
The company enters into forward
exchange contracts, generally with terms of 180 days or
less, to manage some of its foreign currency exposures.
These exposures include revenue and anticipated
purchase transactions, including foreign currency
capital expenditures and lease commitments, forecasted
to occur within 180 days. The forward exchange
contracts are recorded at fair value on the balance
sheet with resulting gains and losses reflected in
income.
Interest Rates
The company enters into interest rate
swaps from time to time as part of its overall strategy
to manage the interest rate risk on its debt. Under the
terms of the swaps, net cash settlements are based on
the difference between fixed-rate and floating-rate
interest amounts calculated by reference to agreed
notional principal amounts. Interest rate swaps related
to a portion of the companys fixed-rate debt are
accounted for as fair value hedges.
Fair Value
Fair values are derived from quoted market
prices, other independent third-party quotes or, if not
available, the present value of the expected cash flows. The fair values reflect the cash that would have
been received or paid if the instruments were settled
at year-end.
Concentrations of Credit Risk
The companys financial
instruments that are exposed to concentrations of
credit risk consist primarily of its cash equivalents,
marketable securities, derivative financial instruments
and trade receivables. The companys short-term
investments are placed with a wide array of financial
institutions with high credit ratings. This diversified
investment policy limits the companys exposure both to
credit risk and to concentrations of credit risk.
Similar standards of diversity and creditworthiness are
applied to the companys counterparties in derivative
instruments.
FS-37
company uses to value an asset or a liability. The
three levels of the fair-value hierarchy are described
as follows:
The fair-value hierarchy for assets and
liabilities measured at fair value at December 31,
2008, is as follows:
Assets and Liabilities Measured at
Marketable securities
The company calculates fair
value for its marketable securities based on quoted
market prices for identical assets and liabilities.
FS-38
projects and approves major changes to the annual
capital and exploratory budgets. However,
business-unit managers within the operating segments
are directly responsible for decisions relating to
project implementation and all other matters connected
with daily operations. Company officers who are
members of the Executive Committee also have
individual management responsibilities and participate
in other committees for purposes other than acting as
the CODM.
Segment Earnings
The company evaluates the performance
of its operating segments on an after-tax basis,
without considering the effects of debt financing
interest expense or investment interest income, both of
which are managed by the company on a worldwide basis.
Corporate administrative costs and assets are not
allocated to the operating segments. However, operating
segments are billed for the direct use of corporate
services. Nonbillable costs remain at the corporate
level in All Other. After-tax segment income by
major operating area is presented in the following
table:
Segment Assets
Segment assets do not include
intercompany investments or intercompany receivables.
Segment assets at year-end 2008 and 2007 are as
follows:
Segment Sales and Other Operating Revenues
Operating
segment sales and other operating revenues, including
internal transfers, for the years 2008, 2007 and 2006
are presented in the table on the following page. Products are
transferred between operating segments at internal
product values that approximate market prices.
FS-39
Other than the United States, no single country
accounted for 10 percent or more of the companys
total sales and other operating revenues in 2008.
Segment Income Taxes
Segment income tax expense for
the years 2008, 2007 and 2006 are as follows:
Other Segment Information
Additional information for
the segmentation of major equity affiliates is
contained in Note 12, beginning on page FS-41.
Information related to properties, plant and equipment
by segment is contained in Note 13, on page FS-43.
Rental expenses incurred for operating leases
during 2008, 2007 and 2006 were as follows:
FS-40
Note 11
Note 12
FS-41
Petropiar
Chevron has a 30 percent interest in
Petropiar, a joint stock company formed in 2008 to
operate the Hamaca heavy oil production and upgrading
project. The project, located in Venezuelas Orinoco
Belt, has a 25-year contract term. Prior to the
formation of Petropiar, Chevron had a 30 percent
interest in the Hamaca project. At December 31, 2008,
the companys carrying value of its investment in
Petropiar was approximately $250 less than the amount
of underlying equity in Petropiar net assets. The
difference represents the excess of Chevrons
underlying equity in Petropiars net assets over the
net book value of the assets contributed to the
venture.
Petroboscan
Chevron has a 39 percent interest in
Petroboscan, a joint stock company formed in 2006 to
operate the Boscan Field in Venezuela until 2026.
Chevron previously operated the field under an
operating service agreement. At December 31, 2008, the
companys carrying value of its investment in
Petroboscan was approximately $290 higher than the
amount of underlying equity in Petroboscan net assets.
The difference reflects the excess of the net book
value of the assets contributed by Chevron over its
underlying equity in Petroboscans net assets.
Angola LNG Ltd.
Chevron has a 36 percent interest in
Angola LNG Ltd., which will process and liquefy natural
gas produced in Angola for delivery to international
markets.
GS Caltex Corporation
Chevron owns 50 percent of GS
Caltex Corporation, a joint venture with GS Holdings.
The joint venture imports, refines and markets
petroleum products and petrochemicals, predominantly in
South Korea.
Caspian Pipeline Consortium
Chevron has a 15 percent
interest in the Caspian Pipeline Consortium, which
provides the critical export route for crude oil from
both TCO and Karachaganak.
Star Petroleum Refining Company Ltd.
Chevron has a 64
percent equity ownership interest in Star Petroleum
Refining Company Ltd. (SPRC), which owns the Star
Refinery in Thailand. The Petroleum Authority of
Thailand owns the remaining 36 percent of SPRC.
Escravos Gas-to-Liquids
Chevron Nigeria Limited (CNL)
has a 75 percent interest in Escravos Gas-to-Liquids
(EGTL) with the other 25 percent of the joint venture
owned by Nigeria National Petroleum Company. Until
December 1, 2008, Sasol Ltd. provided 50 percent of
CNLs funding require-
Caltex Australia Ltd.
Chevron has a 50 percent equity
ownership interest in Caltex Australia Ltd. (CAL). The
remaining 50 percent of CAL is publicly owned. At
December 31, 2008, the fair value of Chevrons share of
CAL common stock was approximately $670. The decline in
value below the companys carrying value of $723
million at the end of 2008 was deemed temporary.
Colonial Pipeline Company
Chevron owns an approximate
23 percent equity interest in the Colonial Pipeline
Company. The Colonial Pipeline system runs from Texas
to New Jersey and transports petroleum products in a
13-state market. At December 31, 2008, the companys
carrying value of its investment in Colonial Pipeline
was approximately $560 higher than the amount of
underlying equity in Colonial Pipeline net assets. This
difference primarily relates to purchase price
adjustments from the acquisition of Unocal Corporation.
Chevron Phillips Chemical Company LLC
Chevron owns
50 percent of Chevron Phillips Chemical Company LLC
(CPChem), with the other half owned by
ConocoPhillips Corporation.
Dynegy Inc.
In 2007, Chevron sold its 19 percent
common stock investment in Dynegy Inc., for
approximately $940, resulting in a gain of $680.
Other Information
Sales and other operating revenues
on the Consolidated Statement of Income includes
$15,390, $11,555 and $9,582 with affiliated companies
for 2008, 2007 and 2006, respectively. Purchased crude
oil and products includes $6,850, $5,464 and $4,222
with affiliated companies for 2008, 2007 and 2006,
respectively.
FS-42
Note 13
Note 14
FS-43
Note 15
Litigation
RFG Patent
Fourteen purported class actions were
brought by consumers who purchased reformulated
gasoline (RFG) from January 1995 through August 2005,
alleging that Unocal misled the California Air
Resources Board into adopting standards for composition
of RFG that overlapped with Unocals undisclosed and
pending patents. The parties agreed to a settlement
that calls for, among other things, Unocal to pay $48
and for the establishment of a
cy pres
fund to
administer payout of the award. The court approved the
final settlement in November 2008.
Ecuador
Chevron is a defendant in a civil lawsuit
before the Superior Court of Nueva Loja in Lago Agrio,
Ecuador, brought in May 2003 by plaintiffs who claim
to be representatives of certain residents of an area
where an oil production consortium formerly had
operations. The lawsuit alleges damage to the
environment from the oil exploration and production
operations, and seeks unspecified damages to fund
environmental remediation and restoration of the
alleged environmental harm, plus a health monitoring
program. Until 1992, Texaco Petroleum Company
(Texpet), a subsidiary of Texaco Inc., was a minority
member of this consortium with Petroecuador, the
Ecuadorian state-owned
FS-44
Note 16
Income Taxes
FS-45
2009 through 2032. Foreign tax credit carryforwards
of $4,784 will expire between 2009 and 2018.
FS-46
Taxes Other Than on Income
Note 17
Short-Term Debt
Redeemable long-term obligations consist
primarily of tax-exempt variable-rate put bonds that
are included as current liabilities because they
become redeemable at the option of the bondholders
within one year following the balance sheet date.
The company periodically enters into interest rate
swaps on a portion of its short-term debt. See Note 7,
beginning on page FS-36, for information concerning the
companys debt-related derivative activities.
At December 31, 2008, the company had $4,950 of
committed credit facilities with banks worldwide,
which permit
Note 18
Long-Term Debt
Long-term debt of $1,221 matures as follows: 2009 $429;
2010 $64; 2011 $47; 2012 $33; 2013 $41; and after
2013 $607.
FS-47
Note 19
New Accounting Standards
FASB Staff Position FAS 141(R)-a Accounting for Assets Acquired
and Liabilities Assumed in a Business Combination (FSP FAS 141(R)-a)
In February 2009, the FASB
approved for issuance FSP FAS 141(R)-a, which became effective for business combinations having an acquisition
date on or after January 1, 2009. This standard requires an asset or liability arising from a contingency in a business
combination to be recognized at fair value if fair value can be reasonably determined. If it cannot be reasonably determined then the
asset or liability will need to be recognized in accordance with FASB
Statement No. 5,
Accounting for Contingencies,
and FASB
Interpretation No. 14,
Reasonable Estimation of the Amount of the Loss.
FASB Statement No. 160, Noncontrolling Interests in
Consolidated Financial Statements, an amendment of ARB
No. 51 (FAS 160)
The FASB issued FAS 160 in December
2007, which became effective for the company January 1,
2009, with retroactive adoption of the Standards
presentation and disclosure requirements for existing
minority interests. This standard requires ownership
interests in subsidiaries held by parties other than
the parent to be presented within the equity section of
the Consolidated Balance Sheet but separate from the
parents equity. It also requires the amount of
consolidated net income attributable to the parent and
the noncontrolling interest to be clearly identified
and presented on the face of the Consolidated Statement
of Income. Certain changes in a parents ownership
interest are to be accounted for as equity transactions
and when a subsidiary is deconsolidated, any
noncontrolling equity investment in the former
subsidiary is to be initially measured at fair value.
Implementation of FAS 160 will not significantly change
the presentation of the companys Consolidated
Statement of Income or Consolidated Balance Sheet.
FASB Staff Position FAS 132(R)-1, Employers
Disclosures about Postretirement Benefit Plan Assets
(FSP FAS 132(R)-1)
In December 2008, the FASB issued
FSP FAS 132(R)-1, which becomes effective with the
companys reporting at December 31, 2009. This standard
amends and expands the disclosure requirements on the
plan assets of defined benefit pension and other
postretirement plans to provide users of financial
statements with an understanding of: how investment
allocation decisions are made; the major categories of
plan assets; the inputs and valuation techniques used
to measure the fair value of plan assets; the effect of
fair-value measurements using significant unobservable
inputs on changes in plan assets for the period; and
significant concentrations of risk within plan assets.
The company does not prefund its other postretirement
plan obligations, and the effect on the companys
disclosures for its pension plan assets as a result of
the adoption of FSP FAS 132(R)-1 will depend on the
companys plan assets at that time.
Note 20
Accounting for Suspended Exploratory Wells
FS-48
The following table provides an aging of
capitalized well costs and the number of projects for
which exploratory well costs have been capitalized for
a period greater than one year since the completion of
drilling.
Of the $1,559 of exploratory well costs
capitalized for more than one year at December 31,
2008, $874 (27 projects) is related to projects that
had drilling activities under way or firmly planned for
the near future. An additional $279 (four projects) is
related to projects that had drilling activity during
2008. The $406 balance is related to 19 projects in
areas requiring a major capital expenditure before
production could begin and for which additional
drilling efforts were not under way or firmly planned
for the near future. Additional drilling was not deemed
necessary because the presence of hydrocarbons had
already been established, and other activities were in
process to enable a future decision on project
development.
Note 21
Stock Options and Other Share-Based Compensation
FS-49
Chevron Long-Term
Incentive Plan (LTIP)
Awards under the LTIP may take the form of, but are not
limited to, stock options, restricted stock, restricted stock units, stock appreciation rights,
performance units and nonstock grants. From April 2004 through January 2014, no more than 160
million shares may be issued under the LTIP, and no more than 64 million of those shares may be in
a form other than a stock option, stock appreciation right or award requiring full payment for
shares by the award recipient.
Texaco Stock Incentive Plan (Texaco SIP)
On the closing of the acquisition of Texaco in October
2001, outstanding options granted under the Texaco SIP were converted to Chevron options. These
options, which have 10-year contractual lives extending into 2011, retained a provision for being
restored. This provision enables a participant who exercises a stock option to receive new options
equal to the number of shares exchanged or who has shares withheld to satisfy tax withholding
obligations to receive new options equal to the number of shares exchanged or withheld. The
restored options are fully exercisable six months after the date of grant, and the exercise price
is the market value of the common stock on the day the restored option is granted. Beginning in
2007, restored options were granted under the LTIP. No further awards may be granted under the
former Texaco plans.
Unocal Share-Based Plans (Unocal Plans)
When Chevron acquired Unocal in August 2005, outstanding
stock options and stock appreciation rights granted under various Unocal Plans were exchanged for
fully vested Chevron options and appreciation rights. These awards retained the same provisions as
the original Unocal Plans. If not exercised, these awards will expire between early 2009 and early
2015.
A summary of option activity during 2008 is presented below:
The total intrinsic value (i.e., the difference between the exercise price and the market
price) of options exercised during 2008, 2007 and 2006 was $433, $423 and $281, respectively.
During this period, the company continued its practice of issuing treasury shares upon exercise of
these awards.
FS-50
As of December 31, 2008, there was $179 of total unrecognized before-tax compensation cost
related to nonvested share-based compensation arrangements granted or restored under the plans.
That cost is expected to be recognized over a weighted-average period of 1.9 years.
At January 1, 2008, the number of LTIP performance units outstanding was equivalent to
2,225,015 shares. During 2008, 888,300 units were granted, 652,897 units vested with cash proceeds
distributed to recipients and 59,863 units were forfeited. At December 31, 2008, units outstanding
were 2,400,555, and the fair value of the liability recorded for these instruments was $201. In
addition, outstanding stock appreciation rights and other awards that were granted under various
LTIP and former Texaco and Unocal programs totaled approximately 1.4 million equivalent shares as
of December 31, 2008. A liability of $35 was recorded for these awards.
Broad-Based Employee Stock Options
In addition to the plans described above, Chevron granted all
eligible employees stock options or equivalents in 1998. The options vested in February 2000 and
expired in February 2008. A total of 9,641,600 options were awarded with an exercise price of
$38.16 per share.
FS-51
Amounts recognized on the Consolidated Balance Sheet for the companys pension and other
postretirement benefit plans at December 31, 2008 and 2007, include:
Amounts recognized on a before-tax basis in Accumulated other comprehensive loss for the
companys pension and OPEB postretirement plans were $5,831 and $2,990 at the end of 2008 and 2007.
These amounts consisted of:
The accumulated benefit obligations for all U.S. and international pension plans were $7,376
and $3,273, respectively, at December 31, 2008, and $7,712 and $4,000, respectively, at December
31, 2007.
FS-52
The components of net periodic benefit cost for 2008, 2007 and 2006 and amounts recognized in
other comprehensive income for 2008 and 2007 are shown in the table below. For 2008 and 2007,
changes in pension plan assets and benefit obligations were recognized as changes in other
comprehensive income.
Net actuarial losses recorded in Accumulated
other comprehensive loss at December 31, 2008, for the
companys U.S. pension, international pension and OPEB
plans are being amortized on a straight-line basis over
approximately 10, 13 and 10 years, respectively. These
amortization periods represent the estimated average
remaining service of employees expected to receive
benefits under the plans. These losses are amortized to
the extent they exceed 10 percent of the higher of the
projected benefit obligation or market-related value of
plan assets. The amount subject to amortization is
determined on a plan-by-plan basis. During 2009, the
company estimates actuarial losses of $298, $103 and
$28 will be amortized from Accumulated other
comprehensive loss for U.S. pension, international
pension and OPEB plans, respectively. In
addition, the company estimates an additional $201
will be recognized from Accumulated other
comprehensive loss during 2009 related to lump-sum
settlement costs from
U.S. pension plans.
FS-53
Assumptions
The following weighted-average assumptions were used to determine benefit obligations
and net periodic benefit costs for years ended December 31:
Discount Rate
The discount rate assumptions used to
determine U.S. and international pension and
postretirement benefit plan obligations and expense
reflect the prevailing rates available on high-quality,
fixed-income debt instruments. At December 31, 2008,
the company selected a 6.3 percent discount rate for
the major U.S. pension and postretirement plans. This
rate was based on a cash flow analysis that matched
estimated future benefit payments to the Citigroup
Pension Discount Yield Curve as of year-end 2008. The
discount rates at the end of 2007 and 2006 were 6.3
percent and 5.8 percent, respectively.
Plan Assets and Investment Strategy
The companys
pension plan weighted-average asset allocations at
December 31 by asset category are as follows:
FS-54
Cash Contributions and Benefit Payments
In 2008, the
company contributed $577 and $262 to its U.S. and
international pension plans, respectively. In 2009, the
company expects contributions to be approximately $550
and $250 to its U.S. and international pension plans,
respectively. Actual contribution amounts are dependent
upon plan-investment returns, changes in pension
obligations, regulatory environments and other economic
factors. Additional funding may ultimately be required
if investment returns are insufficient to offset
increases in plan obligations.
The company anticipates paying other
postretirement benefits of approximately $209 in
2009, as compared with $188 paid in 2008.
Employee Savings Investment Plan
Eligible
employees of Chevron and certain of its
subsidiaries participate in the Chevron Employee
Savings Investment Plan (ESIP).
Employee Stock Ownership Plan
Within the Chevron ESIP
is an employee stock ownership plan (ESOP). In 1989,
Chevron established a LESOP as a constituent part of
the ESOP. The LESOP provides partial prefunding of
the companys future commitments to the ESIP.
FS-55
Benefit Plan Trusts
Prior to its acquisition by
Chevron, Texaco established a benefit plan trust for
funding obligations under some of its benefit plans. At
year-end 2008, the trust contained 14.2 million shares
of Chevron treasury stock. The trust will sell the
shares or use the dividends from the shares to pay
benefits only to the extent that the company does not
pay such benefits. The company intends to continue to
pay its obligations under the benefit plans. The
trustee will vote the shares held in the trust as
instructed by the trusts beneficiaries. The shares
held in the trust are not considered outstanding for
earnings-per-share purposes until distributed or sold
by the trust in payment of benefit obligations.
Employee Incentive Plans
Effective January 2008, the
company established the Chevron Incentive Plan (CIP), a
single annual cash bonus plan for eligible employees
that links awards to corporate, unit and individual
performance in the prior year. This plan replaced other
cash bonus programs, which primarily included the
Management Incentive Plan (MIP) and the Chevron Success
Sharing program. In 2008, charges to expense for cash
bonuses were $757. Charges to expense for MIP were $184
and $180 in 2007 and 2006, respectively. Charges for
other cash bonus programs were $431 and $329 in 2007
and 2006, respectively. Chevron also has a Long-Term
Incentive Plan (LTIP) for officers and other regular
salaried employees of the company and its subsidiaries
who hold positions of significant responsibility.
Awards under LTIP consist of stock options and other
share-based compensation that are described in Note 21
on page FS-49.
Note 23
Guarantees
The company has issued a guarantee of
approximately $600 associated with certain payments
under a terminal use agreement entered into by a
company affiliate. The terminal is expected to be
operational by 2012. Over the approximate 16-year term
of the guarantee, the maximum guarantee amount will
reduce over time as certain fees are paid by the
affiliate. There are numerous cross-indemnity
agreements with the affiliate and the other partners to
permit recovery of any amounts paid under the
guarantee. Chevron carries no liability for its
obligation under this guarantee.
Indemnifications
The company provided certain
indemnities of contingent liabilities of Equilon and
Motiva to Shell and Saudi Refining, Inc., in connection
with the February 2002 sale of the companys interests
in those investments. The company would be required to
perform if the indemnified liabilities become actual
losses. Were that to occur, the company could be
required to make future payments up to $300. Through
the end of 2008, the company paid $48 under these
indemnities and continues to be obligated for possible
additional indemnification payments in the future.
FS-56
Securitization
During 2008, the company terminated the
program used to securitize downstream-related trade
accounts receivable. At year-end 2007, the balance of
securitized receivables was $675 million. As of
December 31, 2008, the company had no other
securitization arrangements in place.
Long-Term Unconditional Purchase Obligations and
Commitments, Including Throughput and Take-or-Pay
Agreements
The company and its subsidiaries have
certain other contingent liabilities relating to
long-term unconditional purchase obligations and
commitments, including throughput and take-or-pay
agreements, some of which relate to suppliers
financing arrangements. The agreements typically
provide goods and services, such as pipeline and
storage capacity, drilling rigs, utilities, and
petroleum products, to be used or sold in the ordinary
course of the companys business. The aggregate
approximate amounts of required payments under these
various commitments are: 2009 $6,405; 2010
$3,964; 2011 $3,578; 2012 $1,473; 2013 $1,329;
2014 and after $4,333. A portion of these
commitments may ultimately be shared with project
partners. Total payments under the agreements were
approximately $5,100 in 2008 $3,700 in 2007 and $3,000
in 2006.
Minority Interests
The company has commitments of
$469 related to minority interests in subsidiary
companies.
Environmental
The company is subject to loss
contingencies pursuant to environmental laws and
regulations that in the future may require the company
to take action to correct or ameliorate the effects on
the
environment of prior release of chemicals or petroleum
substances, including MTBE, by the company or other
parties. Such contingencies may exist for various
sites, including, but not limited to, federal
Superfund sites and analogous sites under state laws,
refineries, crude oil fields, service stations, terminals, land
development areas, and mining operations, whether
operating, closed or divested. These future costs are
not fully determinable due to such factors as the
unknown magnitude of possible contamination,
FS-57
Equity Redetermination
For oil and gas producing
operations, ownership agreements may provide for
periodic reassessments of equity interests in estimated
crude oil and natural gas reserves. These activities,
individually or together, may result in gains or losses
that could be material to earnings in any given period.
One such equity redetermination process has been under
way since 1996 for Chevrons interests in four
producing zones at the Naval Petroleum Reserve at Elk
Hills, California, for the time when the remaining
interests in these zones were owned by the U.S.
Department of Energy. A wide range remains for a
possible net settlement amount for the four zones. For
this range of settlement, Chevron estimates its maximum
possible net before-tax liability at approximately
$200, and the possible maximum net amount that could be
owed to Chevron is estimated at about $150. The timing
of the settlement and the exact amount within this
range of estimates are uncertain.
Other Contingencies
Chevron receives claims from and
submits claims to customers; trading partners; U.S.
federal, state and local regulatory bodies;
governments; contractors; insurers; and suppliers. The
amounts of these claims, individually and in the
aggregate, may be significant and take lengthy periods
to resolve.
Note 24
Asset Retirement Obligations
In the table above, the amounts associated with
Revisions in estimated cash flows reflect increasing
costs to abandon onshore and offshore wells, equipment
and facilities, including an aggregate of $1,804 for
2006 through 2008 for the estimated costs to dismantle
and abandon wells and facilities damaged by hurricanes
in the U.S. Gulf of Mexico in 2005 and 2008. The
long-term portion of the $9,395 balance at the end of
2008 was $8,588.
FS-58
The excess of replacement cost over the carrying value of inventories for which the Last-In,
First-Out (LIFO) method is used was $9,368 and $6,958 at December 31, 2008 and 2007, respectively.
Replacement cost is generally based on average acquisition costs for the year. LIFO profits of
$210, $113 and $82 were included in net income for the years 2008, 2007 and 2006, respectively.
FS-59
THIS PAGE INTENTIONALLY LEFT BLANK
FS-60
Five-Year Financial Summary
FS-61
In accordance with FAS 69,
Disclosures About Oil and
Gas Producing Activities
, this section provides
supplemental information on oil and gas exploration
and producing activities of the company in seven
separate tables. Tables I through IV provide
historical cost information pertaining to costs
incurred in exploration, property acquisitions and
development; capitalized costs; and results of
operations. Tables V
through VII present information
on the companys estimated net proved reserve
quantities, standardized measure of estimated
discounted future net cash flows related to proved
reserves, and changes in estimated discounted future
net cash flows. The Africa geographic area includes
activities principally in Nigeria, Angola, Chad,
Republic of the Congo and Democratic Republic of the
Congo. The Asia-Pacific
Table
I Costs Incurred in Exploration, Property Acquisitions and
Development
1
FS-62
geographic area includes activities principally in
Australia, Azerbaijan, Bangladesh, China, Kazakhstan,
Myanmar, the Partitioned Neutral Zone between Kuwait
and Saudi Arabia, the Philippines, and Thailand. The
international Other geographic category includes
activities in Argentina, Brazil, Canada, Colombia,
Denmark, the Netherlands, Norway, Trinidad and Tobago,
Venezuela, the United Kingdom, and
other countries.
Amounts for TCO represent Chevrons 50 percent equity
share of Tengizchevroil, an exploration and production
partnership in the Republic of Kazakhstan. The
affiliated companies Other amounts are composed of
the companys equity interests in Venezuela, Angola
and Russia. Refer to Note 12 beginning on page FS-41
for a discussion of the companys major equity
affiliates.
Table
II - Capitalized Costs Related to Oil and Gas Producing
Activities
FS-63
FS-64
The companys results of operations from oil and
gas producing activities for the years 2008, 2007 and
2006 are shown in the following table. Net income from
exploration and production activities as reported on
page FS-39 reflects income taxes computed on an
effective rate basis.
In accordance with FAS 69, income taxes in Table III
are based on statutory tax rates, reflecting
allowable deductions and tax credits. Interest income
and expense are excluded from the results reported in
Table III and from the net income amounts on page
FS-39.
FS-65
FS-66
Table V Reserve Quantity Information
Reserves Governance
The company has adopted a
comprehensive reserves and resource classification
system modeled after a system developed and approved by
the Society of Petroleum Engineers, the World Petroleum
Congress and the American Association of Petroleum
Geologists. The system classifies recoverable
hydrocarbons into six categories based on their status
at the time of reporting three deemed commercial and
three noncommercial. Within the commercial
classification are proved reserves and two categories
of unproved: probable and possible. The noncommercial
categories are also referred to as contingent
resources. For reserves estimates to be classified as
proved, they must meet all SEC and company standards.
Due to the inherent uncertainties and the limited
nature of reservoir data, estimates of reserves are
subject to change as additional information becomes
available.
FS-67
During the year, the RAC is represented in
meetings with each of the companys upstream business
units to review and discuss reserve changes
recommended by the various asset teams. Major changes
are also reviewed with the companys Strategy and
Planning Committee and the Executive Committee, whose
members include the Chief Executive Officer and the
Chief Financial Officer. The companys annual reserve
activity is also reviewed with the Board of Directors.
If major changes to reserves were to occur between the
annual reviews, those matters would also be discussed
with the Board.
each contained between 1 percent and 5 percent
of the companys oil-equivalent proved reserves, which
in the aggregate accounted for approximately 40 percent
of the companys total proved reserves. These
properties were geographically dispersed, located in
the United States, South America, West Africa, the
Middle East and the Asia-Pacific region.
FS-68
Net
Proved Reserves of Crude Oil, Condensate and Natural Gas Liquids
Information on Canadian Oil Sands Net Proved Reserves Not Included Above:
Noteworthy amounts in the categories of liquids
proved-reserve changes for 2006 through 2008 are
discussed below:
lion barrels in Indonesia and 27 million barrels in
Thailand. In Indonesia, the increase was the result of infill
drilling and improved steamflood and waterflood
performance.
FS-69
year-end prices.
Higher prices also resulted in downward revisions in
Karachaganak and Azerbaijan. For equity affiliates, most of the upward revision was related to a 92
million-barrel increase for TCOs Tengiz Field and an
11 million-barrel increase for Petroboscan in
Venezuela, both as a result of improved reservoir
performance. At TCO, the upward revision was tempered
by the negative impact of higher year-end prices.
was related to gas reinjection in
Kazakhstan. Affiliated companies increased reserves 10
million barrels due to improved secondary recovery at
Boscan.
FS-70
Net Proved Reserves of Natural Gas
Noteworthy amounts in the categories of natural
gas proved-reserve changes for 2006 through 2008 are
discussed below:
new contract for sales of natural gas. These
additions were partially offset by downward revisions
of 224 BCF in the United Kingdom and 130 BCF in Australia due to
drilling results and reservoir performance. U.S.
Other had a downward revision of 102 BCF due to
reservoir performance, which was partially offset by
upward revisions of 72 BCF in the Gulf of Mexico and
California related to reservoir performance and
development drilling. TCO had an upward revision of 26
BCF associated with additional development activity and
updated reservoir performance.
FS-71
ated companies by a net 73 BCF. For consolidated
companies, net increases were 209 BCF in the United
States and 186 BCF internationally. Improved reservoir
performance for many fields in the United States
contributed 130 BCF in the Other region, 40 BCF in
California and 39 BCF in the Gulf of Mexico. Drilling
activities added 360 BCF in Thailand and improved
reservoir performance added 188 BCF in Trinidad and
Tobago. These additions were partially offset by
downward revisions of 185 BCF in Australia due to
drilling results and 136 BCF in Nigeria due to field
performance. Negative revisions due to the impact of
higher prices were recorded in Azerbaijan and
Kazakhstan. TCO had an upward revision of 75 BCF
associated with improved reservoir performance and
development activities. This upward revision was net of
a negative impact due to higher year-end prices.
In 2007, purchases of natural gas reserves were
141 BCF for consolidated companies, which include the
acquisition of an additional interest in the Bibiyana
Field in Bangladesh. Affiliated company purchases of
211 BCF related to the formation of a new Hamaca
equity affiliate in Venezuela and an initial booking
related to the Angola LNG project.
Table
VI Standardized Measure of Discounted
Future
FS-72
FS-73
The changes in present values between years,
which can be significant, reflect changes in estimated
proved-reserve quantities and prices and assumptions
used in forecasting
production volumes and costs. Changes in the timing of production are included with
Revisions of previous quantity estimates.
FS-74
E-2
By
Principal Executive Officers
(and Directors)
Directors
/s/
David J.
OReilly
David J. OReilly, Chairman of the
Board and Chief Executive Officer
Samuel H. Armacost*
Samuel H. Armacost
/s/
Peter J.
Robertson
Peter J. Robertson, Vice Chairman of the Board
Linnet F. Deily*
Linnet F. Deily
Robert E. Denham*
Robert E. Denham
Robert J. Eaton*
Robert J. Eaton
/s/
Patricia E. Yarrington
Patricia E. Yarrington, Vice President and
Chief Financial Officer
Principal Accounting Officer
/s/
Mark A. Humphrey
Mark A. Humphrey, Vice President and Comptroller
Sam Ginn
Enrique Hernandez, Jr.*
Enrique Hernandez, Jr.
Franklyn G. Jenifer*
Franklyn G. Jenifer
Sam Nunn*
Sam Nunn
Donald B. Rice*
Donald B. Rice
Lydia I. Beebe,
Attorney-in-Fact
Kevin W. Sharer*
Kevin W. Sharer
Charles R.
Shoemate*
Charles R. Shoemate
Ronald D. Sugar*
Ronald D. Sugar
Carl Ware*
Carl Ware
39
FS-2
FS-2
FS-2
FS-5
FS-6
FS-8
FS-10
FS-10
FS-12
FS-12
FS-13
FS-15
FS-15
FS-17
FS-18
FS-21
FS-24
FS-25
FS-26
FS-27
FS-28
FS-29
FS-30
FS-31
Notes
to the Consolidated Financial Statements
Note 1
FS-32
Note 2
FS-34
Note 3
FS-35
Note 4
FS-35
Note 5
FS-36
Note 6
FS-36
Note 7
FS-36
Note 8
FS-37
Note 9
FS-38
Note 10
FS-40
Note 11
FS-41
Note 12
FS-41
Note 13
FS-43
Note 14
FS-43
Note 15
FS-44
Note 16
FS-45
Note 17
FS-47
Note 18
FS-47
Note 19
FS-48
Note 20
FS-48
Note 21
FS-49
Note 22
FS-51
Note 23
FS-56
Note 24
FS-58
Note 25
FS-59
Note 26
FS-59
Note 27
FS-59
Five-Year Financial Summary
FS-61
Supplemental Information on Oil and Gas Producing Activities
FS-62
Table of Contents
Financial Condition and Results of Operations
Millions of dollars, except per-share amounts
2008
2007
2006
$
23,931
$
18,688
$
17,138
$
11.74
$
8.83
$
7.84
$
11.67
$
8.77
$
7.80
$
2.53
$
2.26
$
2.01
$
264,958
$
214,091
$
204,892
26.6
%
23.1
%
22.6
%
29.2
%
25.6
%
26.0
%
Millions of dollars
2008
2007
2006
$
7,126
$
4,532
$
4,270
14,584
10,284
8,872
21,710
14,816
13,142
1,369
966
1,938
2,060
2,536
2,035
3,429
3,502
3,973
182
396
539
(1,390
)
(26
)
(516
)
$
23,931
$
18,688
$
17,138
$
862
$(352
)
$(219
)
Table of Contents
Table of Contents
Financial Condition and Results of Operations
FS-6.
Refer also to the Selected Operating Data table on page
FS-10 for a listing of production volumes
for each of the three years ending December 31, 2008.)
Table of Contents
Table of Contents
Financial Condition and Results of Operations
Millions of dollars
2008
2007
2006
$
7,126
$
4,532
$
4,270
Millions of dollars
2008
2007
2006
$
14,584
$
10,284
$
8,872
$
873
$ (417
)
$ (371
)
Table of Contents
Millions of dollars
2008
2007
2006
$
1,369
$
966
$
1,938
Millions of dollars
2008
2007
2006
$
2,060
$
2,536
$
2,035
$
193
$ 62
$ 98
Table of Contents
Financial Condition and Results of Operations
Millions of dollars
2008
2007
2006
$
182
$
396
$
539
$
(18
)
$ (3
)
$ (8
)
Millions of dollars
2008
2007
2006
$
(1,390
)
$
(26
)
$
(516
)
$
(186
)
$ 6
$ 62
Millions of dollars
2008
2007
2006
$
264,958
$
214,091
$
204,892
Millions of dollars
2008
2007
2006
$
5,366
$
4,144
$
4,255
Table of Contents
Millions of dollars
2008
2007
2006
$
2,681
$
2,669
$
971
Millions of dollars
2008
2007
2006
$
171,397
$
133,309
$
128,151
Millions of dollars
2008
2007
2006
$
26,551
$
22,858
$
19,717
Millions of dollars
2008
2007
2006
$
1,169
$
1,323
$
1,364
Millions of dollars
2008
2007
2006
$
9,528
$
8,708
$
7,506
Millions of dollars
2008
2007
2006
$
21,303
$
22,266
$
20,883
Millions of dollars
2008
2007
2006
$
$
166
$
451
Millions of dollars
2008
2007
2006
$
19,026
$
13,479
$
14,838
Table of Contents
Financial Condition and Results of Operations
2008
2007
2006
421
460
462
1,501
1,699
1,810
671
743
763
7,226
7,624
7,051
159
160
124
$
88.43
$
63.16
$
56.66
$
7.90
$
6.12
$
6.29
1,228
1,296
1,270
3,624
3,320
3,146
1,859
1,876
1,904
4,215
3,792
3,478
114
118
102
$
86.51
$
65.01
$
57.65
$
5.19
$
3.90
$
3.73
671
743
763
1,859
1,876
1,904
2,530
2,619
2,667
692
728
712
721
729
782
1,413
1,457
1,494
891
812
939
589
581
595
1,427
1,446
1,532
2,016
2,027
2,127
967
1,021
1,050
Table of Contents
Table of Contents
Financial Condition and Results of Operations
2008
2007
2006
Millions of dollars
U.S.
Intl.
Total
U.S.
Intl.
Total
U.S.
Intl.
Total
$
5,516
$
11,944
$
17,460
$
4,558
$
10,980
$
15,538
$
4,123
$
8,696
$
12,819
2,182
2,023
4,205
1,576
1,867
3,443
1,176
1,999
3,175
407
78
485
218
53
271
146
54
200
618
7
625
768
6
774
403
14
417
$
8,723
$
14,052
$
22,775
$
7,120
$
12,906
$
20,026
$
5,848
$
10,763
$
16,611
$
8,241
$
12,228
$
20,469
$
6,900
$
10,790
$
17,690
$
5,642
$
9,050
$
14,692
At December 31
2008
2007
2006
1.1
1.2
1.3
166.9
69.2
53.5
9.3
%
8.6
%
12.5
%
Millions of dollars
Commitment Expiration by Period
2010
2012
After
Total
2009
2011
2013
2013
$
613
$
$
$
76
$
537
Table of Contents
Millions of dollars
Payments Due by Period
2010
2012
After
Total
2009
2011
2013
2013
$
2,818
$
2,818
$
$
$
5,742
5,061
74
607
548
97
154
143
154
2,133
174
322
312
1,325
2,888
503
835
603
947
15,726
5,063
5,383
1,261
4,019
5,356
1,342
2,159
1,541
314
1
Excludes contributions for pensions and
other postretirement benefit plans. Information on
employee benefit plans is contained in Note 22
beginning on page FS-51.
2
Does not include amounts related to the
companys income tax liabilities associated with
uncertain tax positions. The company is unable to
make reasonable estimates for the periods in which
these liabilities may become payable. The company
does not expect settlement of such liabilities will
have a material effect on its results of operations,
consolidated financial position or liquidity in any
single period.
3
$5.0 billion of short-term debt that
the company expects to refinance is included in
long-term debt. The repayment schedule above reflects the projected repayment of the entire amounts in
the 20102011 period.
4
Does not include obligations to
purchase the companys share of natural gas liquids
and regasified natural gas associated with
operations of the 36.4 percent-owned Angola LNG affiliate. The LNG plant is expected to commence
operations in 2012 and is designed to produce 5.2
million metric tons of liquefied natural gas and
related natural gas liquids per year. Volumes and
prices associated with these purchase obligations are
neither fixed nor determinable.
Table of Contents
Financial Condition and Results of Operations
Millions of dollars
2008
2007
$
39
$
29
5
3
45
23
Table of Contents
Table of Contents
Financial Condition and Results of Operations
Table of Contents
Table of Contents
Financial Condition and Results of Operations
1.
the nature of the estimates or
assumptions is material due to the levels of
subjectivity and judgment neces-
sary to
account for highly uncertain matters or the
susceptibility of such matters to change; and
2.
the impact of the estimates and
assumptions on the companys financial
condition or operating performance is
material.
Table of Contents
Table of Contents
Financial Condition and Results of Operations
Table of Contents
Combinations (FAS 141-R)
In
December 2007, the FASB
issued FAS 141-R, which became effective for business
combination transactions having an acquisition date on
or after January 1, 2009. This standard requires the
acquiring entity in a business combination to recognize
the assets acquired, the liabilities assumed, and any
noncontrolling interest in the acquiree at the
acquisition date to be measured at their respective
fair values. It also requires acquisition-related
costs, as well as restructuring costs the acquirer
expects to incur for which it is not obligated at
acquisition date, to be recorded against income rather
than included in purchase-price determination. Finally,
the standard requires recognition of contingent
arrangements at their acquisition-date fair values,
with subsequent changes in fair value generally reflected in income.
Table of Contents
Financial Condition and Results of Operations
Table of Contents
Table of Contents
2008
2007
Millions of dollars, except per-share amounts
4th Q
3rd Q
2nd Q
1st Q
4th Q
3rd Q
2nd Q
1st Q
$
43,145
$
76,192
$
80,962
$
64,659
$
59,900
$
53,545
$
54,344
$
46,302
886
1,673
1,563
1,244
1,153
1,160
894
937
1,172
1,002
464
43
357
468
856
988
45,203
78,867
82,989
65,946
61,410
55,173
56,094
48,227
23,575
49,238
56,056
42,528
38,056
33,988
33,138
28,127
5,416
5,676
5,248
4,455
4,798
4,397
4,124
3,613
1,492
1,278
1,639
1,347
1,833
1,446
1,516
1,131
338
271
307
253
449
295
273
306
2,589
2,449
2,275
2,215
2,094
2,495
2,156
1,963
4,547
5,614
5,699
5,443
5,560
5,538
5,743
5,425
7
22
63
74
6
32
34
28
35
25
19
28
37,963
64,558
71,258
56,269
52,832
48,206
47,032
40,667
7,240
14,309
11,731
9,677
8,578
6,967
9,062
7,560
2,345
6,416
5,756
4,509
3,703
3,249
3,682
2,845
$
4,895
$
7,893
$
5,975
$
5,168
$
4,875
$
3,718
$
5,380
$
4,715
$
2.45
$
3.88
$
2.91
$
2.50
$
2.34
$
1.77
$
2.52
$
2.20
$
2.44
$
3.85
$
2.90
$
2.48
$
2.32
$
1.75
$
2.52
$
2.18
$
0.65
$
0.65
$
0.65
$
0.58
$
0.58
$
0.58
$
0.58
$
0.52
$
82.20
$
99.08
$
103.09
$
94.61
$
94.86
$
94.84
$
84.24
$
74.95
$
57.83
$
77.50
$
86.74
$
77.51
$
83.79
$
80.76
$
74.83
$
66.43
$
2,080
$
2,577
$
2,652
$
2,537
$
2,548
$
2,550
$
2,609
$
2,414
Table of Contents
Patricia E. Yarrington
Mark A. Humphrey
Vice President
Vice President
and Chief Financial Officer
and Comptroller
Table of Contents
February 26, 2009
Table of Contents
Year ended December 31
2008
2007
2006
$
264,958
$
214,091
$
204,892
5,366
4,144
4,255
2,681
2,669
971
273,005
220,904
210,118
171,397
133,309
128,151
20,795
16,932
14,624
5,756
5,926
5,093
1,169
1,323
1,364
9,528
8,708
7,506
21,303
22,266
20,883
166
451
100
107
70
230,048
188,737
178,142
42,957
32,167
31,976
19,026
13,479
14,838
$
23,931
$
18,688
$
17,138
$
11.74
$
8.83
$
7.84
$
11.67
$
8.77
$
7.80
$
9,846
$
10,121
$
9,551
Refer also to Note 14, on page FS-43.
$
$
$
6,725
Table of Contents
Year ended December 31
2008
2007
2006
$
23,931
$
18,688
$
17,138
(112
)
31
55
(6
)
17
(88
)
2
(6
)
19
(88
)
139
(10
)
2
32
7
95
(
61
)
(3
)
(30
)
110
(6
)
67
(88
)
483
356
(3,228
)
530
(64
)
(15
)
(32
)
204
(97
)
19
1,037
(409
)
50
(
1,901
)
685
(38
)
(1,909
)
729
(4
)
$
22,022
$
19,417
$
17,134
Table of Contents
At December 31
2008
2007
$
9,347
$
7,362
213
732
15,856
22,446
5,175
4,003
459
290
1,220
1,017
6,854
5,310
4,200
3,527
36,470
39,377
2,413
2,194
20,920
20,477
173,299
154,084
81,519
75,474
91,780
78,610
4,711
3,491
4,619
4,637
252
$
161,165
$
148,786
$
2,818
$
1,162
16,580
21,756
8,077
5,275
3,079
3,972
1,469
1,633
32,023
33,798
5,742
5,664
341
406
17,678
15,007
11,539
12,170
6,725
4,449
469
204
74,517
71,698
1,832
1,832
14,448
14,289
101,102
82,329
(1
)
(3,924
)
(2,015
)
(434
)
(454
)
(26,376
)
(18,892
)
86,648
77,088
$
161,165
$
148,786
Table of Contents
Year ended December 31
2008
2007
2006
$
23,931
$
18,688
$
17,138
9,528
8,708
7,506
375
507
520
(440
)
(1,439
)
(979
)
(1,358
)
(2,315
)
(229
)
(355
)
378
259
598
261
614
(1,673
)
685
1,044
100
107
70
(161
)
(82
)
(900
)
(84
)
(530
)
232
(839
)
(317
)
(449
)
10
326
(503
)
29,632
24,977
24,323
(19,666
)
(16,678
)
(13,813
)
179
21
463
1,491
3,338
989
483
185
142
432
(799
)
(17,081
)
(13,933
)
(12,219
)
2,647
(345
)
(677
)
(965
)
(3,343
)
(2,224
)
650
(5,162
)
(4,791
)
(4,396
)
(99
)
(77
)
(60
)
(6,821
)
(6,389
)
(4,491
)
(10,400
)
(14,295
)
(11,848
)
(166
)
120
194
1,985
(3,131
)
450
7,362
10,493
10,043
$
9,347
$
7,362
$
10,493
Table of Contents
2008
2007
2006
Shares
Amount
Shares
Amount
Shares
Amount
$
$
$
2,442,677
$
1,832
2,442,677
$
1,832
2,442,677
$
1,832
2,442,677
$
1,832
2,442,677
$
1,832
2,442,677
$
1,832
$
14,289
$
14,126
$
13,894
159
163
232
$
14,448
$
14,289
$
14,126
$
82,329
$
68,464
$
55,738
23,931
18,688
17,138
(5,162
)
(4,791
)
(4,396
)
(19
)
(35
)
4
3
3
$
101,102
$
82,329
$
68,464
$
$
(1
)
$
(2
)
Balance at January 1
$
(59
)
$
(90
)
$
(145
)
(112
)
31
55
$
(171
)
$
(59
)
$
(90
)
Balance at January 1
$
(2,008
)
$
(2,585
)
$
(344
)
(1,901
)
685
(38
)
(108
)
(2,203
)
$
(3,909
)
$
(2,008
)
$
(2,585
)
$
19
$
$
88
(6
)
19
(88
)
$
13
$
19
$
$
33
$
39
$
(28
)
110
(6
)
67
$
143
$
33
$
39
$
(3,924
)
$
(2,015
)
$
(2,636
)
$
(214
)
$
(214
)
$
(246
)
20
32
(194
)
(214
)
(214
)
14,168
(240
)
14,168
(240
)
14,168
(240
)
14,168
$
(434
)
14,168
$
(454
)
14,168
$
(454
)
352,243
$
(18,892
)
278,118
$
(12,395
)
209,990
$
(7,870
)
95,631
(8,011
)
85,429
(7,036
)
80,369
(5,033
)
(9,429
)
527
(11,304
)
539
(12,241
)
508
438,445
$
(26,376
)
352,243
$
(18,892
)
278,118
$
(12,395
)
$
86,648
$
77,088
$
68,935
Table of Contents
Millions of dollars, except per-share amounts
Summary of Significant Accounting Policies
Table of Contents
Table of Contents
Year ended December 31
2008
2007
2006
$
6,030
$
(3,867
)
$
17
(1,545
)
(749
)
(536
)
(621
)
(370
)
(31
)
(4,628
)
4,930
1,246
(909
)
741
348
$
(1,673
)
$
685
$
1,044
$
$
203
$
470
$
19,130
$
12,340
$
13,806
$
3,719
$
2,160
$
1,413
(
3,236
)
(1,975
)
(1,271
)
$
483
$
185
$
142
Table of Contents
Cash Flows - Continued
Year ended December 31
2008
2007
2006
$
18,495
$
16,127
$
12,800
1,051
881
880
320
418
400
(200
)
(748
)
(267
)
19,666
16,678
13,813
794
816
844
9
196
35
20,469
17,690
14,692
2,306
2,336
1,919
$
22,775
$
20,026
$
16,611
Table of Contents
Year ended December 31
2008
2007
2006
$
195,593
$
153,574
$
145,774
185,788
147,510
137,765
7,237
5,203
5,668
At December 31
2008
2007
$
32,760
$
32,801
31,806
27,400
14,322
20,050
14,805
11,447
35,439
28,704
$
6,813
$
4,433
Year ended December 31
2008
2007
2006
$
1,022
$
667
$
692
947
713
602
120
(39
)
119
At December 31
2008
2007
$
482
$
335
172
337
98
107
88
188
468
377
Year ended December 31
2008
2007
2006
$
14,329
$
8,919
$
7,654
5,621
3,387
2,967
6,134
3,952
3,315
At December 31
2008
2007
$
2,740
$
2,784
12,240
11,446
1,867
1,534
4,759
4,927
8,354
7,769
Table of Contents
Fair Value Measurements
Table of Contents
Fair Value on a Recurring Basis
Prices in Active
Markets for
Other
Identical
Observable
Unobservable
At December 31
Assets/Liabilities
Inputs
Inputs
2008
(Level 1)
(Level 2)
(Level 3)
$
213
$
213
$
$
805
529
276
$
1,018
$
742
$
276
$
$
516
$
98
$
418
$
$
516
$
98
$
418
$
Operating Segments and Geographic Data
Table of Contents
Year ended December 31
2008
2007
2006
$
7,126
$
4,532
$
4,270
14,584
10,284
8,872
21,710
14,816
13,142
1,369
966
1,938
2,060
2,536
2,035
3,429
3,502
3,973
22
253
430
160
143
109
182
396
539
25,321
18,714
17,654
(107
)
(312
)
192
385
380
(1,582
)
(304
)
(584
)
$
23,931
$
18,688
$
17,138
At December 31
2008
2007
$
26,071
$
23,535
72,530
61,049
4,619
4,637
103,220
89,221
15,869
16,790
23,572
26,075
39,441
42,865
2,535
2,484
1,086
870
3,621
3,354
146,282
135,440
8,984
6,847
5,899
6,499
14,883
13,346
53,459
49,656
103,087
94,493
4,619
4,637
$
161,165
$
148,786
*
All Other assets consist primarily of worldwide
cash, cash equivalents and marketable securities,
real estate, information systems, mining operations,
power generation businesses, technology companies,
and assets of the corporate administrative
functions.
Table of Contents
Year ended December 31
2008
2007
2006
$
23,503
$
18,736
$
18,061
15,142
11,625
10,069
38,645
30,361
28,130
19,469
15,213
14,560
24,204
19,647
17,139
43,673
34,860
31,699
82,318
65,221
59,829
87,515
70,535
69,367
4,746
4,990
4,829
447
491
533
92,708
76,016
74,729
122,064
97,178
91,325
5,044
5,042
4,657
122
38
37
127,230
102,258
96,019
219,938
178,274
170,748
305
351
372
2
2
2
266
235
243
573
588
617
1,388
1,143
959
55
86
63
154
142
160
1,597
1,371
1,182
2,170
1,959
1,799
815
757
653
917
760
584
1,732
1,517
1,237
52
58
44
33
31
23
85
89
67
1,817
1,606
1,304
133,658
108,482
104,713
172,585
138,578
128,967
306,243
247,060
233,680
(41,285
)
(32,969
)
(28,788
)
$
264,958
$
214,091
$
204,892
*
Includes buy/sell contracts of $6,725 in 2006.
Substantially all of the amounts relate to the
downstream segment. Refer to Note 14, on page FS-43,
for a discussion of the companys accounting for
buy/sell contracts.
Year ended December 31
2008
2007
2006
$
3,693
$
2,541
$
2,668
15,132
11,307
10,987
18,825
13,848
13,655
815
520
1,162
813
400
586
1,628
920
1,748
(
22
)
6
213
47
36
30
25
42
243
(1,452
)
(1,331
)
(808
)
$
19,026
$
13,479
$
14,838
Lease Commitments
At December 31
2008
2007
$
491
$
482
$
399
$
551
171
171
1,061
1,204
522
628
$
539
$
576
Year ended December 31
2008
2007
2006
$
2,984
$
2,419
$
2,326
6
6
6
2,990
2,425
2,332
41
30
33
$
2,949
$
2,395
$
2,299
Table of Contents
At December 31
Operating
Capital
Leases
Leases
$
503
$
97
463
77
372
77
315
84
288
59
947
154
$
2,888
$
548
(110
)
438
(97
)
$
341
Restructuring and Reorganization Costs
Amounts before tax
2008
2007
$
85
$
(11
)
85
(52
)
$
22
$
85
Investments and Advances
Investments and Advances
Equity in Earnings
At December 31
Year ended December 31
2008
2007
2008
2007
2006
$
6,290
$
6,321
$
3,220
$
2,135
$
1,817
1,130
1,168
317
327
319
816
762
244
185
31
1,191
574
(8
)
21
725
765
206
204
123
10,152
9,590
3,979
2,872
2,290
2,601
2,276
444
217
316
749
951
103
102
117
877
944
22
157
116
628
86
103
146
723
580
250
129
186
536
546
32
39
34
1,664
1,501
268
215
212
7,150
7,426
1,205
962
1,127
2,037
2,024
158
380
697
25
24
4
6
5
2,062
2,048
162
386
702
567
449
20
(76
)
136
$
19,931
$
19,513
$
5,366
$
4,144
$
4,255
989
964
$
20,920
$
20,477
$
4,002
$
3,889
$
307
$
478
$
955
$
16,918
$
16,588
$
5,059
$
3,666
$
3,300
40-year period. At December 31, 2008, the companys
carrying value of its investment in TCO was about
$210 higher than the amount of underlying equity in
TCO net assets. This difference results from
Chevron acquiring a portion of its interest in TCO
at a value greater than the underlying equity for
that portion of TCOs assets.
Table of Contents
Table of Contents
Affiliates
Chevron Share
Year ended December 31
2008
2007
2006
2008
2007
2006
$
112,707
$
94,864
$
73,746
$
54,055
$
46,579
$
35,695
17,500
12,510
10,973
7,532
5,836
5,295
12,705
9,743
7,905
5,524
4,550
4,072
$
25,194
$
26,360
$
19,769
$
10,804
$
11,914
$
8,944
51,878
48,440
49,896
20,129
19,045
18,575
17,727
19,033
15,254
7,474
9,009
6,818
21,049
22,757
24,059
4,533
3,745
3,902
$
38,296
$
33,010
$
30,352
$
18,926
$
18,205
$
16,799
Properties, Plant and Equipment
At December 31
Year ended December 31
Gross Investment at Cost
Net Investment
Additions at Cost
1
Depreciation Expense
2
2008
2007
2006
2008
2007
2006
2008
2007
2006
2008
2007
2006
$
54,156
$
50,991
$
46,191
$
22,294
$
19,850
$
16,706
$
5,374
$
5,725
$
3,739
$
2,683
$
2,700
$
2,374
84,282
71,408
61,281
51,140
43,431
37,730
13,177
10,512
7,290
5,441
4,605
3,888
138,438
122,399
107,472
73,434
63,281
54,436
18,551
16,237
11,029
8,124
7,305
6,262
17,394
15,807
14,553
8,977
7,685
6,741
2,032
1,514
1,109
629
509
474
11,587
10,471
11,036
6,001
4,690
5,233
2,285
519
532
469
633
551
28,981
26,278
25,589
14,978
12,375
11,974
4,317
2,033
1,641
1,098
1,142
1,025
725
678
645
338
308
289
50
40
25
19
19
19
828
815
771
496
453
431
72
53
54
33
26
24
1,553
1,493
1,416
834
761
720
122
93
79
52
45
43
4,310
3,873
3,243
2,523
2,179
1,709
598
680
270
250
215
171
17
41
27
11
14
19
5
5
8
4
1
5
4,327
3,914
3,270
2,534
2,193
1,728
603
685
278
254
216
176
76,585
71,349
64,632
34,132
30,022
25,445
8,054
7,959
5,143
3,581
3,443
3,038
96,714
82,735
73,115
57,648
48,588
43,413
15,539
11,089
7,884
5,947
5,265
4,468
$
173,299
$
154,084
$
137,747
$
91,780
$
78,610
$
68,858
$
23,593
$
19,048
$
13,027
$
9,528
$
8,708
$
7,506
Accounting for Buy/Sell Contracts
Table of Contents
Table of Contents
Taxes
Year ended December 31
2008
2007
2006
$
2,879
$
1,446
$
2,828
274
225
200
669
338
581
3,822
2,009
3,609
15,021
11,416
11,030
183
54
199
15,204
11,470
11,229
$
19,026
$
13,479
$
14,838
Year ended December 31
2008
2007
2006
35.0
%
35.0
%
35.0
%
10.2
8.3
10.3
1.0
0.8
1.0
(0.1
)
0.3
0.9
(0.5
)
(0.4
)
(0.4
)
(0.6
)
(0.3
)
0.3
(0.7
)
(1.8
)
(0.7
)
44.3
%
41.9
%
46.4
%
At December 31
2008
2007
$
18,271
$
17,310
2,225
1,837
20,496
19,147
(4,338
)
(3,587
)
(3,488
)
(2,148
)
(1,139
)
(1,603
)
(3,933
)
(1,689
)
(4,784
)
(3,138
)
(260
)
(608
)
(445
)
(477
)
(1,732
)
(1,528
)
(20,119
)
(14,778
)
7,535
5,949
$
7,912
$
10,318
Table of Contents
At December 31
2008
2007
$
(1,130
)
$
(1,234
)
(2,686
)
(812
)
189
194
11,539
12,170
$
7,912
$
10,318
2008
2007
$
2,199
$
2,296
(1
)
19
522
418
(17
)
175
337
120
(246
)
(225
)
(215
)
(255
)
(58
)
(174
)
$
2,696
$
2,199
Table of Contents
Year ended December 31
2008
2007
2006
$
4,748
$
4,992
$
4,831
1
12
32
588
491
475
204
185
155
431
288
360
5,972
5,968
5,853
5,098
5,129
4,720
8,368
10,404
9,618
1,557
528
491
106
89
75
202
148
126
15,331
16,298
15,030
$
21,303
$
22,266
$
20,883
At December 31
2008
2007
$
5,742
$
3,030
149
219
429
850
78
73
1,351
1,351
19
21
7,768
5,544
(4,950
)
(4,382
)
$
2,818
$
1,162
At December 31
2008
2007
$
$
749
400
405
194
213
147
161
108
108
85
85
74
81
56
57
40
46
30
30
30
38
64
21
27
13
17
15
59
1,221
2,132
(429
)
(850
)
4,950
4,382
$
5,742
$
5,664
Table of Contents
Table of Contents
2008
2007
2006
$
1,660
$
1,239
$
1,109
643
486
446
(49
)
(23
)
(171
)
(136
)
(42
)
(121
)
(24
)
$
2,118
$
1,660
$
1,239
At December 31
2008
2007
2006
$
559
$
449
$
332
1,559
1,211
907
$
2,118
$
1,660
$
1,239
50
54
44
Number
Aging based on drilling completion date of individual wells:
Amount
of wells
$
7
3
31
4
176
34
1,345
154
$
1,559
195
Aging based on drilling completion date of last
Number
suspended well in project:
Amount
of projects
$
7
1
8
1
69
3
1,475
45
$
1,559
50
Table of Contents
Year ended December 31
2008
2007
2006
6.1
6.3
6.4
22.0
%
22.0
%
23.7
%
3.0
%
4.5
%
4.7
%
2.7
%
3.2
%
3.1
%
$
15.97
$
15.27
$
12.74
1.2
1.6
2.2
23.1
%
21.2
%
19.6
%
1.9
%
4.5
%
4.8
%
2.7
%
3.2
%
3.3
%
$
10.01
$
8.61
$
7.72
1
Expected term is based on historical exercise and post-vesting cancellation
data.
2
Volatility rate is based on historical stock prices over an appropriate period,
generally equal to the expected term.
Weighted-
Weighted-
Average
Average
Remaining
Aggregate
Shares
Exercise
Contractual
Intrinsic
(Thousands)
Price
Term
Value
January 1, 2008
57,357
$
54.50
12,391
$
84.98
(10,758
)
$
53.69
1,196
$
94.53
(1,173
)
$
79.53
December 31, 2008
59,013
$
61.36
6.5 yrs.
$
883
December 31, 2008
36,934
$
51.51
5.2 yrs.
$
838
Table of Contents
Employee Benefit Plans
Table of Contents
Pension Benefits
2008
2007
Other Benefits
U.S.
Intl.
U.S.
Intl.
2008
2007
$
8,395
$
4,633
$
8,792
$
4,207
$
2,939
$
3,257
250
132
260
125
44
49
499
292
483
255
178
184
9
7
152
122
32
(301
)
97
(12
)
(62
)
(104
)
(131
)
(40
)
(14
)
(413
)
(858
)
219
(28
)
12
(955
)
(246
)
(708
)
(225
)
(340
)
(272
)
1
8,127
3,891
8,395
4,633
2,931
2,939
7,918
3,892
7,941
3,456
(2,092
)
(655
)
607
232
(662
)
183
577
262
78
239
188
150
9
7
152
122
(955
)
(246
)
(708
)
(225
)
(340
)
(272
)
5,448
2,600
7,918
3,892
$
(2,679
)
$
(1,291
)
$
(477
)
$
(741
)
$
(2,931
)
$
(2,939
)
Pension Benefits
2008
2007
Other Benefits
U.S.
Intl.
U.S.
Intl.
2008
2007
$
6
$
31
$
181
$
279
$
$
(72
)
(61
)
(68
)
(55
)
(209
)
(207
)
(2,613
)
(1,261
)
(590
)
(965
)
(2,722
)
(2,732
)
$
(2,679
)
$
(1,291
)
$
(477
)
$
(741
)
$
(2,931
)
$
(2,939
)
Pension Benefits
2008
2007
Other Benefits
U.S.
Intl.
U.S.
Intl.
2008
2007
$
3,797
$
1,804
$
1,539
$
1,237
$
410
$
490
(68
)
211
(75
)
203
(323
)
(404
)
$
3,729
$
2,015
$
1,464
$
1,440
$
87
$
86
Pension Benefits
2008
2007
U.S.
Intl.
U.S.
Intl.
$
8,121
$
2,906
$
678
$
1,089
7,371
2,539
638
926
5,436
1,698
20
271
Table of Contents
Pension Benefits
2008
2007
2006
Other Benefits
U.S.
Intl.
U.S.
Intl.
U.S.
Intl.
2008
2007
2006
$
250
$
132
$
260
$
125
$
234
$
98
$
44
$
49
$
35
499
292
483
255
468
214
178
184
181
(593
)
(273
)
(578
)
(266
)
(550
)
(227
)
1
(7
)
24
46
17
46
14
(81
)
(81
)
(86
)
60
77
128
82
149
69
38
81
97
306
2
65
70
3
1
515
255
404
216
417
169
179
233
227
2,624
646
(160
)
31
(42
)
(401
)
(366
)
(79
)
(193
)
(82
)
(38
)
(81
)
32
(301
)
97
7
(24
)
(46
)
(20
)
81
81
2,265
575
(700
)
26
1
(401
)
$
2,780
$
830
$
(296
)
$
242
$
417
$
169
$
180
$
(168
)
$
227
Table of Contents
Pension Benefits
2008
2007
2006
Other Benefits
U.S.
Intl.
U.S.
Intl.
U.S.
Intl.
2008
2007
2006
6.3
%
7.5
%
6.3
%
6.7
%
5.8
%
6.0
%
6.3
%
6.3
%
5.8
%
4.5
%
6.8
%
4.5
%
6.4
%
4.5
%
6.1
%
4.0
%
4.5
%
4.5
%
6.3
%
6.7
%
5.8
%
6.0
%
5.8
%
5.9
%
6.3
%
5.8
%
5.9
%
7.8
%
7.4
%
7.8
%
7.5
%
7.8
%
7.4
%
N/A
N/A
N/A
4.5
%
6.4
%
4.5
%
6.1
%
4.2
%
5.1
%
4.5
%
4.5
%
4.2
%
1 Percent
1 Percent
Increase
Decrease
$
9
$
(8
)
$
88
$
(75
)
U.S.
International
Asset Category
2008
2007
2008
2007
52
%
64
%
47
%
56
%
34
%
23
%
50
%
43
%
13
%
12
%
2
%
1
%
1
%
1
%
1
%
100
%
100
%
100
%
100
%
Table of Contents
Pension Benefits
Other
U.S.
Intl.
Benefits
$
853
$
226
$
209
$
841
$
249
$
216
$
849
$
240
$
222
$
863
$
265
$
225
$
874
$
277
$
230
$
4,379
$
1,746
$
1,205
Table of Contents
Thousands
2008
2007
19,651
20,506
6,366
7,365
26,017
27,871
Income Taxes
The company calculates its income tax
expense and liabilities quarterly. These liabilities
generally are subject to audit and are not finalized
with the individual taxing authorities until several
years after the end of the annual
Table of Contents
Table of Contents
2008
2007
2006
$
8,253
$
5,773
$
4,304
308
178
153
(973
)
(818
)
(387
)
430
399
*
275
1,377
2,721
1,428
$
9,395
$
8,253
$
5,773
Table of Contents
Other Financial Information
Year ended December 31
2008
2007
2006
$
256
$
468
$
608
256
302
157
$
$
166
$
451
$
835
$
562
$
468
$
862
$
(352
)
$
(219
)
*
Includes $420, $18 and $15 in 2008, 2007 and 2006, respectively, for the companys share of
equity affiliates foreign currency effects.
Assets Held for Sale
Earnings Per Share
Year ended December 31
2008
2007
2006
$
23,931
$
18,688
$
17,138
1
$
23,931
$
18,688
$
17,139
2,037
2,117
2,185
1
1
1
2,038
2,118
2,186
$
11.74
$
8.83
$
7.84
$
23,931
$
18,688
$
17,138
1
$
23,931
$
18,688
$
17,139
2,037
2,117
2,185
1
1
1
12
14
11
2,050
2,132
2,197
$
11.67
$
8.77
$
7.80
Table of Contents
Table of Contents
Unaudited
Millions of dollars, except per-share amounts
2008
2007
2006
2005
2004
$
264,958
$
214,091
$
204,892
$
193,641
$
150,865
8,047
6,813
5,226
4,559
4,435
273,005
220,904
210,118
198,200
155,300
230,048
188,737
178,142
173,003
134,749
42,957
32,167
31,976
25,197
20,551
19,026
13,479
14,838
11,098
7,517
23,931
18,688
17,138
14,099
13,034
294
$
23,931
$
18,688
$
17,138
$
14,099
$
13,328
$
11.74
$
8.83
$
7.84
$
6.58
$
6.16
$
11.67
$
8.77
$
7.80
$
6.54
$
6.14
$
$
$
$
$
0.14
$
$
$
$
$
0.14
$
11.74
$
8.83
$
7.84
$
6.58
$
6.30
$
11.67
$
8.77
$
7.80
$
6.54
$
6.28
$
2.53
$
2.26
$
2.01
$
1.75
$
1.53
$
36,470
$
39,377
$
36,304
$
34,336
$
28,503
124,695
109,409
96,324
91,497
64,705
161,165
148,786
132,628
125,833
93,208
2,818
1,162
2,159
739
816
29,205
32,636
26,250
24,272
17,979
6,083
6,070
7,679
12,131
10,456
36,411
31,830
27,605
26,015
18,727
74,517
71,698
63,693
63,157
47,978
$
86,648
$
77,088
$
68,935
$
62,676
$
45,230
$
9,846
$
10,121
$
9,551
$
8,719
$
7,968
$
$
$
6,725
$
23,822
$
18,650
3
Per-share amounts in all periods reflect a two-for-one stock split effected as a 100 percent stock dividend in September 2004.
Table of Contents
Unaudited
Consolidated Companies
United States
International
Gulf of
Total
Asia-
Total
Affiliated Companies
Millions of dollars
Calif.
Mexico
Other
U.S.
Africa
Pacific
Indonesia
Other
Intl.
Total
TCO
Other
$
$
477
$
42
$
519
$
197
$
312
$
20
$
67
$
596
$
1,115
$
$
65
1
66
90
56
11
106
263
329
140
3
143
60
148
37
97
342
485
682
46
728
347
516
68
270
1,201
1,929
(1
)
2
87
88
169
169
257
1
576
2
579
280
280
859
578
89
667
449
449
1,116
928
1,923
1,497
4,348
3,723
4,484
753
1,879
10,839
15,187
643
120
$
928
$
3,183
$
1,632
$
5,743
$
4,070
$
5,449
$
821
$
2,149
$
12,489
$
18,232
$
643
$
120
$
4
$
430
$
18
$
452
$
202
$
156
$
3
$
195
$
556
$
1,008
$
$
7
59
14
73
136
48
11
98
293
366
128
5
133
70
120
50
79
319
452
4
617
37
658
408
324
64
372
1,168
1,826
7
10
220
13
243
5
92
(2
)
95
338
35
75
3
113
8
35
24
67
180
45
295
16
356
13
127
22
162
518
1,198
2,237
1,775
5,210
4,176
1,897
620
1,504
8,197
13,407
832
64
$
1,247
$
3,149
$
1,828
$
6,224
$
4,597
$
2,348
$
684
$
1,898
$
9,527
$
15,751
$
832
$
71
$
$
493
$
22
$
515
$
151
$
121
$
20
$
246
$
538
$
1,053
$
25
$
96
8
104
180
53
12
92
337
441
116
16
132
48
140
58
50
296
428
705
46
751
379
314
90
388
1,171
1,922
25
6
152
158
1
10
15
26
184
581
1
47
10
58
1
135
136
194
7
199
10
216
1
11
150
162
378
581
686
1,632
868
3,186
2,890
1,788
460
1,019
6,157
9,343
671
25
$
693
$
2,536
$
924
$
4,153
$
3,270
$
2,113
$
550
$
1,557
$
7,490
$
11,643
$
696
$
606
1
Includes costs incurred whether capitalized or expensed. Excludes general support
equipment expenditures. Includes capitalized amounts related to asset retirement obligations. See
Note 24, Asset Retirement Obligations, beginning on page FS-58.
2
Includes wells, equipment and facilities associated with proved reserves.
Does not include properties acquired in nonmonetary transactions.
3
Includes
$224, $99 and $160 costs incurred prior to assignment of proved reserves in 2008, 2007 and
2006, respectively.
Table of Contents
Gas Producing Activities
Consolidated Companies
United States
International
Gulf of
Total
Asia-
Total
Affiliated Companies
Millions of dollars
Calif.
Mexico
Other
U.S.
Africa
Pacific
Indonesia
Other
Intl.
Total
TCO
Other
$
810
$
1,357
$
328
$
2,495
$
294
$
2,788
$
651
$
912
$
4,645
$
7,140
$
113
$
12,048
19,318
14,914
46,280
17,495
21,726
8,117
13,041
60,379
106,659
5,991
841
239
226
252
717
967
266
1,150
475
2,858
3,575
888
602
602
499
495
107
415
1,516
2,118
405
3,812
58
4,275
4,226
2,490
875
1,739
9,330
13,605
501
81
13,502
25,315
15,552
54,369
23,481
27,765
10,900
16,582
78,728
133,097
7,493
922
744
80
21
845
202
223
64
439
928
1,773
29
7,802
14,546
8,432
30,780
6,602
8,692
6,214
8,360
29,868
60,648
831
212
145
99
138
382
523
128
611
307
1,569
1,951
307
8,691
14,725
8,591
32,007
7,327
9,043
6,889
9,106
32,365
64,372
1,167
212
$
4,811
$
10,590
$
6,961
$
22,362
$
16,154
$
18,722
$
4,011
$
7,476
$
46,363
$
68,725
$
6,326
$
710
$
805
$
892
$
353
$
2,050
$
314
$
2,639
$
630
$
1,015
$
4,598
$
6,648
$
112
$
11,260
19,110
13,718
44,088
11,894
17,321
7,705
11,360
48,280
92,368
4,247
858
201
206
230
637
850
284
1,123
439
2,696
3,333
758
406
7
413
368
293
148
438
1,247
1,660
308
3,128
573
4,009
6,430
2,049
593
1,421
10,493
14,502
1,633
55
12,574
23,742
14,881
51,197
19,856
22,586
10,199
14,673
67,314
118,511
6,750
913
741
57
35
833
201
221
39
427
888
1,721
23
7,383
15,074
7,640
30,097
5,427
6,912
5,592
7,062
24,993
55,090
644
167
133
92
124
349
464
144
571
261
1,440
1,789
267
8,257
15,223
7,799
31,279
6,092
7,277
6,202
7,750
27,321
58,600
934
167
$
4,317
$
8,519
$
7,082
$
19,918
$
13,764
$
15,309
$
3,997
$
6,923
$
39,993
$
59,911
$
5,816
$
746
Table of Contents
Table II
Capitalized Costs
Related to Oil and
Gas Producing
Activities - Continued
Consolidated Companies
United States
International
Gulf of
Total
Asia-
Total
Affiliated Companies
Millions of dollars
Calif.
Mexico
Other
U.S.
Africa
Pacific
Indonesia
Other
Intl.
Total
TCO
Other
$
770
$
1,007
$
370
$
2,147
$
342
$
2,373
$
707
$
1,082
$
4,504
$
6,651
$
112
$
9,960
18,464
12,284
40,708
9,943
15,486
7,110
10,461
43,000
83,708
2,701
1,096
189
212
226
627
745
240
1,093
364
2,442
3,069
611
343
7
350
231
217
149
292
889
1,239
370
2,188
2,558
4,299
1,546
493
917
7,255
9,813
2,493
40
11,289
22,214
12,887
46,390
15,560
19,862
9,552
13,116
58,090
104,480
5,917
1,136
738
52
29
819
189
74
14
337
614
1,433
22
7,082
14,468
6,880
28,430
4,794
5,273
4,971
6,087
21,125
49,555
541
109
125
111
130
366
400
102
522
238
1,262
1,628
242
7,945
14,631
7,039
29,615
5,383
5,449
5,507
6,662
23,001
52,616
805
109
$
3,344
$
7,583
$
5,848
$
16,775
$
10,177
$
14,413
$
4,045
$
6,454
$
35,089
$
51,864
$
5,112
$
1,027
Table of Contents
Gas Producing Activities
1
Consolidated Companies
United States
International
Gulf of
Total
Asia-
Total
Affiliated Companies
Millions of dollars
Calif.
Mexico
Other
U.S.
Africa
Pacific
Indonesia
Other
Intl.
Total
TCO
Other
$
226
$
1,543
$
3,113
$
4,882
$
2,578
$
7,030
$
1,447
$
4,026
$
15,081
$
19,963
$
4,971
$
1,599
6,405
2,839
3,624
12,868
8,373
5,703
2,975
3,651
20,702
33,570
6,631
4,382
6,737
17,750
10,951
12,733
4,422
7,677
35,783
53,533
4,971
1,599
(1,385
)
(914
)
(1,523
)
(3,822
)
(1,228
)
(1,182
)
(1,009
)
(874
)
(4,293
)
(8,115
)
(376
)
(125
)
(107
)
(55
)
(554
)
(716
)
(163
)
(585
)
(1
)
(47
)
(796
)
(1,512
)
(41
)
(278
)
(415
)
(926
)
(945
)
(2,286
)
(1,176
)
(1,804
)
(617
)
(1,330
)
(4,927
)
(7,213
)
(237
)
(77
)
(29
)
(119
)
(94
)
(242
)
(60
)
(31
)
(22
)
(54
)
(167
)
(409
)
(2
)
(1
)
(330
)
(40
)
(370
)
(223
)
(243
)
(83
)
(250
)
(799
)
(1,169
)
(3
)
(91
)
(20
)
(114
)
(13
)
(12
)
(25
)
(7
)
(57
)
(171
)
(20
)
(383
)
1,110
707
(350
)
298
(64
)
282
166
873
184
105
4,672
1,564
4,671
10,907
7,738
9,174
2,601
5,397
24,910
35,817
4,499
1,223
(1,652
)
(553
)
(1,651
)
(3,856
)
(6,051
)
(4,865
)
(1,257
)
(3,016
)
(15,189
)
(19,045
)
(1,357
)
(612
)
$
3,020
$
1,011
$
3,020
$
7,051
$
1,687
$
4,309
$
1,344
$
2,381
$
9,721
$
16,772
$
3,142
$
611
$
202
$
1,555
$
2,476
$
4,233
$
1,810
$
6,192
$
1,045
$
3,012
$
12,059
$
16,292
$
3,327
$
1,290
4,671
2,630
2,707
10,008
6,778
4,440
2,590
2,744
16,552
26,560
4,873
4,185
5,183
14,241
8,588
10,632
3,635
5,756
28,611
42,852
3,327
1,290
(1,063
)
(936
)
(1,400
)
(3,399
)
(892
)
(953
)
(892
)
(828
)
(3,565
)
(6,964
)
(248
)
(92
)
(91
)
(53
)
(378
)
(522
)
(49
)
(292
)
(2
)
(58
)
(401
)
(923
)
(31
)
(163
)
(300
)
(1,143
)
(833
)
(2,276
)
(646
)
(1,668
)
(623
)
(980
)
(3,917
)
(6,193
)
(127
)
(94
)
(92
)
1
(167
)
(258
)
(33
)
(36
)
(21
)
(27
)
(117
)
(375
)
(1
)
(2
)
(486
)
(25
)
(511
)
(267
)
(225
)
(61
)
(259
)
(812
)
(1,323
)
(3
)
(102
)
(27
)
(132
)
(12
)
(150
)
(30
)
(120
)
(312
)
(444
)
3
2
31
36
(447
)
(302
)
(197
)
33
(913
)
(877
)
18
7
3,327
1,468
2,384
7,179
6,242
7,006
1,809
3,517
18,574
25,753
2,938
946
(1,204
)
(531
)
(864
)
(2,599
)
(4,907
)
(3,456
)
(841
)
(1,830
)
(11,034
)
(13,633
)
(887
)
(462
)
$
2,123
$
937
$
1,520
$
4,580
$
1,335
$
3,550
$
968
$
1,687
$
7,540
$
12,120
$
2,051
$
484
1
The value of owned production consumed in operations as fuel has been eliminated from
revenues and production expenses, and the related volumes have been deducted from net production in
calculating the unit average sales price and production cost. This has no effect on the results of
producing operations.
2
Represents accretion of ARO liability. Refer to Note 24, Asset Retirement
Obligations, beginning on page FS-58.
3
Includes foreign currency gains and losses, gains and losses on property
dispositions, and income from operating and technical service agreements.
4
Includes $10 costs incurred prior to assignment of proved reserves in 2007.
Table of Contents
Gas Producing
Activities
1
- Continued
Consolidated Companies
United States
International
Gulf of
Total
Asia-
Total
Affiliated Companies
Millions of dollars
Calif.
Mexico
Other
U.S.
Africa
Pacific
Indonesia
Other
Intl.
Total
TCO
Other
$
308
$
1,845
$
2,976
$
5,129
$
2,377
$
4,938
$
1,001
$
2,814
$
11,130
$
16,259
$
2,861
$
598
4,072
2,317
2,046
8,435
5,264
4,084
2,211
2,848
14,407
22,842
4,380
4,162
5,022
13,564
7,641
9,022
3,212
5,662
25,537
39,101
2,861
598
(889
)
(765
)
(1,057
)
(2,711
)
(640
)
(740
)
(728
)
(664
)
(2,772
)
(5,483
)
(202
)
(42
)
(84
)
(57
)
(442
)
(583
)
(57
)
(231
)
(1
)
(60
)
(349
)
(932
)
(28
)
(6
)
(275
)
(1,096
)
(763
)
(2,134
)
(579
)
(1,475
)
(666
)
(703
)
(3,423
)
(5,557
)
(114
)
(33
)
(11
)
(80
)
(39
)
(130
)
(26
)
(30
)
(23
)
(49
)
(128
)
(258
)
(1
)
(407
)
(24
)
(431
)
(296
)
(209
)
(110
)
(318
)
(933
)
(1,364
)
(25
)
(3
)
(73
)
(8
)
(84
)
(28
)
(15
)
(14
)
(27
)
(84
)
(168
)
1
(732
)
254
(477
)
(435
)
(475
)
50
385
(475
)
(952
)
8
(50
)
3,119
952
2,943
7,014
5,580
5,847
1,720
4,226
17,373
24,387
2,499
467
(1,169
)
(357
)
(1,103
)
(2,629
)
(4,740
)
(3,224
)
(793
)
(2,151
)
(10,908
)
(13,537
)
(750
)
(174
)
$
1,950
$
595
$
1,840
$
4,385
$
840
$
2,623
$
927
$
2,075
$
6,465
$
10,850
$
1,749
$
293
1
The value of owned production consumed in operations as fuel has been eliminated from
revenues and production expenses, and the related volumes have been deducted from net production in
calculating the unit average sales price and production cost. This has no effect on the results of
producing operations.
2
Represents accretion of ARO liability. Refer to Note 24, Asset Retirement
Obligations, beginning on page FS-58.
3
Includes foreign currency gains and losses, gains and losses on property
dispositions, and income from operating and technical service agreements.
Table of Contents
Gas Producing
Activities - Unit Prices and Costs
1,2
Consolidated Companies
United States
International
Gulf of
Total
Asia-
Total
Affiliated Companies
Calif.
Mexico
Other
U.S.
Africa
Pacific
Indonesia
Other
Intl.
Total
TCO
Other
$
87.43
$
95.62
$
85.30
$
88.43
$
91.71
$
86.38
$
79.14
$
85.14
$
86.99
$
87.44
$
79.11
$
69.65
7.19
9.17
7.43
7.90
4.56
8.25
6.00
5.14
6.02
1.56
3.98
17.67
16.22
14.31
15.85
10.00
5.14
16.46
7.36
8.06
10.49
5.24
5.32
$
62.61
$
65.07
$
62.35
$
63.16
$
69.90
$
64.20
$
61.05
$
62.97
$
65.40
$
64.71
$
62.47
$
51.98
5.77
7.01
5.65
6.12
3.60
7.61
4.13
4.02
4.79
0.89
0.44
13.23
12.32
12.62
12.72
7.26
3.96
14.28
6.96
6.54
8.58
3.98
3.56
$
55.20
$
60.35
$
55.80
$
56.66
$
61.53
$
57.05
$
52.23
$
57.31
$
57.92
$
57.53
$
56.80
$
37.26
6.08
7.20
5.73
6.29
0.06
3.44
7.12
4.03
3.88
4.85
0.77
0.36
10.94
9.59
9.26
9.85
5.13
3.36
11.44
5.23
5.17
6.76
3.31
2.51
1
The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net
production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations.
2
Natural gas converted to oil-equivalent gas (OEG) barrels at a rate of 6 MCF = 1 OEG barrel.
Table of Contents
Table of Contents
1
Included are year-end reserve quantities related to production-sharing contracts
(PSC) (refer to page E-146 for the definition of a PSC). PSC-related reserve quantities are 32
percent, 26 percent and 30 percent for consolidated companies for 2008, 2007 and 2006,
respectively.
2
Includes reserves acquired
through nonmonetary transactions.
3
Includes reserves disposed
of through nonmonetary transactions.
4
Net reserve changes (excluding production) in 2008 consist of 770 million barrels of
developed reserves and (180) million barrels of undeveloped reserves for consolidated companies and
180 million barrels of developed reserves and 97 million barrels of undeveloped reserves for
affiliated companies.
5
During 2008, the percentages of undeveloped reserves at December 31, 2007,
transferred to developed reserves were 18 percent and 2 percent for consolidated companies and
affiliated companies, respectively.
Table of Contents
Table of Contents
Consolidated Companies
United States
International
Gulf of
Total
Asia-
Total
Affiliated Companies
Billions of cubic feet
Calif.
Mexico
Other
U.S.
Africa
Pacific
Indonesia
Other
Intl.
Total
TCO
Other
304
1,171
2,953
4,428
3,191
8,623
646
3,578
16,038
20,466
2,787
181
32
40
(102
)
(30
)
34
400
38
39
511
481
26
5
5
3
5
8
13
111
157
268
11
510
10
531
799
6
13
19
16
16
35
54
(1
)
(1
)
(148
)
(148
)
(149
)
(37
)
(241
)
(383
)
(661
)
(33
)
(629
)
(110
)
(302
)
(1,074
)
(1,735
)
(70
)
(4
)
310
1,094
2,624
4,028
3,206
8,920
574
3,182
15,882
19,910
2,743
231
40
39
130
209
(141
)
149
12
166
186
395
75
(2
)
1
1
1
40
46
86
11
392
29
432
518
2
19
29
50
91
91
141
211
(39
)
(37
)
(76
)
(76
)
(175
)
(35
)
(210
)
(375
)
(620
)
(27
)
(725
)
(101
)
(279
)
(1,132
)
(1,752
)
(70
)
(10
)
317
943
2,417
3,677
3,049
8,827
485
3,099
15,460
19,137
2,748
255
8
21
(57
)
(28
)
60
961
107
66
1,194
1,166
498
632
95
13
108
23
1
24
132
66
66
441
441
507
(27
)
(97
)
(124
)
(124
)
(32
)
(161
)
(356
)
(549
)
(53
)
(769
)
(117
)
(308
)
(1,247
)
(1,796
)
(71
)
(9
)
293
871
1,986
3,150
3,056
9,483
475
2,858
15,872
19,022
3,175
878
251
977
2,794
4,022
1,346
4,819
449
2,453
9,067
13,089
2,314
85
250
873
2,434
3,557
1,306
4,751
377
1,912
8,346
11,903
1,412
144
261
727
2,238
3,226
1,151
5,081
326
1,915
8,473
11,699
1,762
117
247
669
1,793
2,709
1,209
5,374
302
2,245
9,130
11,839
1,999
124
1
Includes year-end reserve quantities related to production-sharing contracts (PSC)
(refer to page E-146 for the definition of a PSC). PSC-related reserve quantities are 40 percent, 37
percent and 47 percent for consolidated companies for 2008, 2007 and 2006, respectively.
2
Includes reserves acquired through nonmonetary transactions.
3
Includes reserves disposed of through nonmonetary transactions.
4
Net reserve changes (excluding production) in 2008 consist of 1,936 billion cubic
feet of developed reserves and (255) billion cubic feet of undeveloped reserves for consolidated
companies and 324 billion cubic feet of developed reserves and 806 billion cubic feet of
undeveloped reserves for affiliated companies.
5
During 2008, the percentages of
undeveloped reserves at December 31, 2007, transferred to developed reserves were 12 percent and 0
percent for consolidated companies and affiliated companies, respectively.
Revisions
In 2006, revisions accounted
for a net increase of 481 billion cubic feet (BCF) for
consolidated companies and 26 BCF for affiliates. For
consolidated companies, net increases of 511 BCF
internationally were partially offset by a 30 BCF
downward revision in the United States. Drilling and
development activities added 337 BCF of reserves in
Thailand, while Kazakhstan added 200 BCF, largely due
to development activity. Trinidad and Tobago increased
185 BCF, attributable to improved reservoir performance
and a
Table of Contents
Net
Cash Flows Related to Proved
Oil
and
Gas Reserves
Table of Contents
Flows Related to Proved Oil and Gas Reserves
Consolidated Companies
United States
International
Gulf of
Total
Asia-
Total
Affiliated Companies
Millions of dollars
Calif.
Mexico
Other
U.S.
Africa
Pacific
Indonesia
Other
Intl.
Total
TCO
Other
$
27,223
$
16,407
$
22,544
$
66,174
$
52,344
$
67,386
$
22,836
$
23,041
$
165,607
$
231,781
$
51,252
$
13,968
(20,554
)
(8,311
)
(16,873
)
(45,738
)
(20,302
)
(21,949
)
(17,857
)
(9,374
)
(69,482
)
(115,220
)
(14,502
)
(2,319
)
(3,087
)
(1,650
)
(1,362
)
(6,099
)
(19,001
)
(12,575
)
(3,632
)
(2,499
)
(37,707
)
(43,806
)
(10,140
)
(1,551
)
(1,272
)
(2,289
)
(1,530
)
(5,091
)
(9,581
)
(11,906
)
(613
)
(5,352
)
(27,452
)
(32,543
)
(7,517
)
(5,223
)
2,310
4,157
2,779
9,246
3,460
20,956
734
5,816
30,966
40,212
19,093
4,875
(1,118
)
(583
)
(617
)
(2,318
)
(1,139
)
(9,145
)
(352
)
(1,597
)
(12,233
)
(14,551
)
(11,261
)
(2,966
)
$
1,192
$
3,574
$
2,162
$
6,928
$
2,321
$
11,811
$
382
$
4,219
$
18,733
$
25,661
$
7,832
$
1,909
$
75,201
$
34,162
$
52,775
$
162,138
$
132,450
$
93,046
$
35,020
$
45,566
$
306,082
$
468,220
$
159,078
$
29,845
(17,888
)
(7,193
)
(16,780
)
(41,861
)
(15,707
)
(16,022
)
(18,270
)
(11,990
)
(61,989
)
(103,850
)
(10,408
)
(1,529
)
(3,491
)
(3,011
)
(1,578
)
(8,080
)
(11,516
)
(8,263
)
(4,012
)
(3,468
)
(27,259
)
(35,339
)
(8,580
)
(1,175
)
(19,112
)
(8,507
)
(12,221
)
(39,840
)
(74,172
)
(26,838
)
(5,796
)
(15,524
)
(122,330
)
(162,170
)
(39,575
)
(13,600
)
34,710
15,451
22,196
72,357
31,055
41,923
6,942
14,584
94,504
166,861
100,515
13,541
(17,204
)
(4,438
)
(9,491
)
(31,133
)
(14,171
)
(17,117
)
(2,702
)
(4,689
)
(38,679
)
(69,812
)
(64,519
)
(7,779
)
$
17,506
$
11,013
$
12,705
$
41,224
$
16,884
$
24,806
$
4,240
$
9,895
$
55,825
$
97,049
$
35,996
$
5,762
$
48,828
$
23,768
$
38,727
$
111,323
$
97,571
$
70,288
$
30,538
$
36,272
$
234,669
$
345,992
$
104,069
$
20,644
(14,791
)
(6,750
)
(12,845
)
(34,386
)
(12,523
)
(13,398
)
(16,281
)
(10,777
)
(52,979
)
(87,365
)
(7,796
)
(2,348
)
(3,999
)
(2,947
)
(1,399
)
(8,345
)
(9,648
)
(6,963
)
(2,284
)
(3,082
)
(21,977
)
(30,322
)
(7,026
)
(1,732
)
(10,171
)
(4,764
)
(8,290
)
(23,225
)
(53,214
)
(20,633
)
(5,448
)
(11,164
)
(90,459
)
(113,684
)
(25,212
)
(8,282
)
19,867
9,307
16,193
45,367
22,186
29,294
6,525
11,249
69,254
114,621
64,035
8,282
(9,779
)
(3,256
)
(7,210
)
(20,245
)
(10,065
)
(12,457
)
(2,426
)
(3,608
)
(28,556
)
(48,801
)
(40,597
)
(5,185
)
$
10,088
$
6,051
$
8,983
$
25,122
$
12,121
$
16,837
$
4,099
$
7,641
$
40,698
$
65,820
$
23,438
$
3,097
Table of Contents
Future Net Cash Flows From Proved Reserves
Consolidated Companies
Affiliated Companies
Millions of dollars
2008
2007
2006
2008
2007
2006
$
97,049
$
65,820
$
84,287
$
41,758
$
26,535
$
26,769
(43,906
)
(34,957
)
(32,690
)
(5,750
)
(4,084
)
(3,180
)
13,682
10,468
8,875
763
889
721
233
780
580
7,711
1,767
(542
)
(425
)
(306
)
(7,767
)
646
3,664
4,067
83
37,853
(7,801
)
7,277
3,718
(1,333
)
(967
)
(169,046
)
74,900
(24,725
)
(51,696
)
23,616
(837
)
17,458
12,196
14,218
5,976
3,745
3,673
72,234
(27,596
)
4,237
14,889
(7,554
)
(1,411
)
(71,388
)
31,229
(18,467
)
(32,017
)
15,223
(234
)
$
25,661
$
97,049
$
65,820
$
9,741
$
41,758
$
26,535
Table of Contents
3
.1
Restated Certificate of Incorporation of Chevron Corporation,
dated May 30, 2008, filed as Exhibit 3.1 to Chevron
Corporations Quarterly Report on
Form 10-Q
for the quarterly period ended June 30, 2008, and
incorporated herein by reference.
3
.2
By-Laws of Chevron Corporation, as amended January 30,
2008, filed as Exhibit 3.1 to Chevron Corporations
Current Report on
Form 8-K
dated February 1, 2008, and incorporated herein by
reference.
4
.1
Pursuant to the Instructions to Exhibits, certain instruments
defining the rights of holders of long-term debt securities of
the company and its consolidated subsidiaries are not filed
because the total amount of securities authorized under any such
instrument does not exceed 10 percent of the total assets
of the corporation and its subsidiaries on a consolidated basis.
A copy of such instrument will be furnished to the Commission
upon request.
4
.2*
Confidential Stockholder Voting Policy of Chevron Corporation
(page E-3).
10
.1*
Chevron Corporation Non-Employee Directors Equity
Compensation and Deferral Plan (pages E-4 to E-16).
10
.2*
Chevron Incentive Plan (pages E-17 to E-30).
10
.3*
Long-Term Incentive Plan of Chevron Corporation (pages E-31 to
E-57).
10
.4
Chevron Corporation Deferred Compensation Plan for Management
Employees, as amended and restated on December 7, 2005,
filed as Exhibit 10.5 to Chevron Corporations Current
Report on
Form 8-K
dated December 7, 2005, and incorporated herein by
reference.
10
.5*
Chevron Corporation Deferred Compensation Plan for Management
Employees II (pages E-58 to E-71).
10
.6*
Chevron Corporation Retirement Restoration Plan (pages E-72 to
E-98).
10
.7*
Chevron Corporation ESIP Restoration Plan (pages E-99 to E-120).
10
.8
Texaco Inc. Stock Incentive Plan, adopted May 9, 1989, as
amended May 13, 1993, and May 13, 1997, filed as
Exhibit 10.13 to Chevron Corporations Annual Report
on
Form 10-K
for the year ended December 31, 2001, and incorporated
herein by reference.
10
.9
Supplemental Pension Plan of Texaco Inc., dated June 26,
1975, filed as Exhibit 10.14 to Chevron Corporations
Annual Report on
Form 10-K
for the year ended December 31, 2001, and incorporated
herein by reference.
10
.10
Supplemental Bonus Retirement Plan of Texaco Inc., dated
May 1, 1981, filed as Exhibit 10.15 to Chevron
Corporations Annual Report on
Form 10-K
for the year ended December 31, 2001, and incorporated
herein by reference.
10
.11
Texaco Inc. Director and Employee Deferral Plan approved
March 28, 1997, filed as Exhibit 10.16 to Chevron
Corporations Annual Report on
Form 10-K
for the year ended December 31, 2001, and incorporated
herein by reference.
10
.12
Chevron Corporation 1998 Stock Option Program for U.S. Dollar
Payroll Employees, filed as Exhibit 10.12 to Chevron
Corporations Annual Report on
Form 10-K
for the year ended December 31, 2002, and incorporated
herein by reference.
10
.13*
Summary of Chevron Incentive Plan Award Criteria (pages E-121 to
E-122).
10
.14
Chevron Corporation Change in Control Surplus Employee Severance
Program for Salary Grades 41 through 43, filed as
Exhibit 10.1 to Chevron Corporations Current Report
on
Form 8-K
dated December 6, 2006, and incorporated herein by
reference.
10
.15
Chevron Corporation Benefit Protection Program, filed as
Exhibit 10.2 to Chevron Corporations Current Report
on
Form 8-K
dated December 6, 2006, and incorporated herein by
reference.
10
.16
Form of Notice of Grant under the Chevron Corporation Long-Term
Incentive Plan, filed as Exhibit 10.1 to Chevrons
Current Report on
Form 8-K
dated June 29, 2005, and incorporated herein by reference.
10
.17
Form of Restricted Stock Unit Grant Agreement under the Chevron
Corporation Long-Term Incentive Plan, filed as
Exhibit 10.20 to Chevron Corporations Quarterly
Report on
Form 10-Q
for the quarterly period ended June 30, 2006, and
incorporated herein by reference.
10
.18
Form of Retainer Stock Option Agreement under the Chevron
Corporation Non-Employee Directors Equity Compensation and
Deferral Plan, filed as Exhibit 10.2 to Chevrons
Current Report on
Form 8-K
dated June 29, 2005, and incorporated herein by reference.
10
.19*
Form of Stock Units Agreement under Chevron Corporation
Non-Employee Directors Equity Compensation and Deferral
Plan (page E-123).
12
.1*
Computation of Ratio of Earnings to Fixed Charges
(page E-124).
E-1
Table of Contents
21
.1*
Subsidiaries of Chevron Corporation (pages
E-125
to
E-127).
23
.1*
Consent of PricewaterhouseCoopers LLP
(page E-128).
24
.1 to 24.13*
Powers of Attorney for directors and certain officers of Chevron
Corporation, authorizing the signing of the Annual Report on
Form 10-K
on their behalf (pages E-129 to E-141).
31
.1*
Rule 13a-14(a)/15d-14(a)
Certification of the companys Chief Executive Officer
(page E-142).
31
.2*
Rule 13a-14(a)/15d-14(a)
Certification of the companys Chief Financial Officer
(page E-143).
32
.1*
Section 1350 Certification of the companys Chief
Executive Officer
(page E-144).
32
.2*
Section 1350 Certification of the companys Chief
Financial Officer
(page E-145).
99
.1*
Definitions of Selected Energy and Financial Terms (pages
E-146
to
E-148).
100
.INS*
XBRL Instance Document
100
.SCH*
XBRL Schema Document
100
.CAL*
XBRL Calculation Linkbase Document
100
.LAB*
XBRL Label Linkbase Document
100
.PRE*
XBRL Presentation Linkbase Document
100
.DEF*
XBRL Definition Linkbase Document
*
Filed herewith.
E-3
E-4
SECTION I. PURPOSE
|
E-7 | |||
|
||||
SECTION II. DEFINITIONS
|
E-7 | |||
|
||||
(a) Account
|
E-7 | |||
(b) Annual Cash Retainer
|
E-7 | |||
(c) Annual Compensation Cycle
|
E-7 | |||
(d) Annual Meeting
|
E-7 | |||
(e) Award or Awards
|
E-7 | |||
(f) Beneficiary
|
E-8 | |||
(g) Board
|
E-8 | |||
(h) Change in Control
|
E-8 | |||
(i) Code
|
E-8 | |||
(j) Committee
|
E-8 | |||
(k) Common Stock
|
E-8 | |||
(l) Corporation
|
E-8 | |||
(m) Disability
|
E-8 | |||
(n) Discretionary Transaction
|
E-8 | |||
(o) Dividend Equivalent
|
E-8 | |||
(p) Exchange Act
|
E-8 | |||
(q) Fair Market Value
|
E-9 | |||
(r) Non-Employee Director
|
E-9 | |||
(s) Option
|
E-9 | |||
(t) Option Agreement
|
E-9 | |||
(u) Plan
|
E-9 | |||
(v) Restricted Stock
|
E-9 | |||
(w) Rules
|
E-9 | |||
(x) Share
|
E-9 | |||
(y) Stock Unit
|
E-9 | |||
|
||||
SECTION III. ADMINISTRATION
|
E-9 | |||
|
||||
(a) Composition and Powers of the Committee
|
E-9 | |||
(b) Liability of Board and Committee Members
|
E-10 | |||
(c) Administration of the Plan Following a Change in Control
|
E-10 | |||
|
||||
SECTION IV. DURATION OF THE PLAN AND SHARES SUBJECT TO THE PLAN
|
E-10 | |||
|
||||
(a) Duration of the Plan
|
E-10 | |||
(b) Shares Subject to the Plan
|
E-10 | |||
(c) Accounting for Numbers of Shares
|
E-10 | |||
(d) Source of Stock Issued Under the Plan
|
E-10 | |||
|
||||
SECTION V. PERSONS ELIGIBLE FOR AWARDS AND DEFERRALS
|
E-10 | |||
|
||||
SECTION VI. OPTIONS
|
E-11 | |||
|
||||
(a) Option Grant
|
E-11 | |||
(b) Exercise of Options
|
E-11 | |||
(c) Rights as a Stockholder
|
E-11 | |||
|
||||
SECTION VII. STOCK UNITS
|
E-11 | |||
|
||||
(a) Stock Unit Awards
|
E-11 | |||
(b) Stockholders Rights
|
E-11 |
E-5
(c) Pre-1997 Stock Unit Accounts
|
E-12 | |||
|
||||
SECTION VIII. RESTRICTED STOCK
|
E-12 | |||
|
||||
(a) Restricted Stock Awards
|
E-12 | |||
(b) Stockholders Rights
|
E-12 | |||
|
||||
SECTION IX. DEFERRED COMPENSATION
|
E-12 | |||
|
||||
SECTION X. RECAPITALIZATION
|
E-12 | |||
|
||||
SECTION XI. SECURITIES LAW REQUIREMENTS
|
E-14 | |||
|
||||
SECTION XII. AMENDMENTS OF THE PLAN AND AWARDS
|
E-14 | |||
|
||||
(a) Plan Amendments
|
E-14 | |||
(b) Amendments of Awards
|
E-14 | |||
(c) Rights of Non-Employee Directors
|
E-14 | |||
|
||||
SECTION XIII. TERMINATION OR SUSPENSION OF THE PLAN
|
E-15 | |||
|
||||
(a) Termination or Suspension
|
E-15 | |||
(b) Dissolution or Bankruptcy
|
E-15 | |||
|
||||
SECTION XIV. GENERAL PROVISIONS
|
E-15 | |||
|
||||
(a) Application of Funds
|
E-15 | |||
(b) Creditors Rights
|
E-15 | |||
(c) No Obligation to Exercise Option
|
E-15 | |||
(d) Costs of the Plan
|
E-15 | |||
(e) Non-Employee Directors Beneficiary
|
E-15 | |||
(f) Prohibition of Opposite Way Transactions and Discretionary Transactions
|
E-15 | |||
(g) Severability
|
E-16 | |||
(h) Binding Effect of Plan
|
E-16 | |||
(i) No Waiver of Breach
|
E-16 | |||
(j) Authority to Establish Grantor Trust
|
E-16 | |||
|
||||
SECTION XV. APPROVAL OF STOCKHOLDERS
|
E-16 |
E-6
E-7
E-8
E-9
E-10
E-11
E-12
E-13
E-14
E-15
E-16
E-17
SECTION I. PURPOSE | 1 | |||||||
|
||||||||
SECTION II. EFFECTIVE DATE | 1 | |||||||
|
||||||||
SECTION III. DEFINITIONS | 1 | |||||||
|
||||||||
|
(a) | Annual Income | E-20 | |||||
|
(b) | Award | E-20 | |||||
|
(c) | Benefit Protection Period | E-20 | |||||
|
(d) | Board | E-20 | |||||
|
(e) | Business in Competition | E-20 | |||||
|
(f) | Change in Control | E-20 | |||||
|
(g) | Code | E-20 | |||||
|
(h) | Committee | E-21 | |||||
|
(i) | Corporation | E-21 | |||||
|
(j) | Corporation Confidential Information | E-21 | |||||
|
(k) | Covered Employee | E-21 | |||||
|
(l) | Director | E-21 | |||||
|
(m) | Document | E-21 | |||||
|
(n) | Eligible Employee | E-22 | |||||
|
(o) | Executive Committee | E-22 | |||||
|
(p) | Independent Director | E-22 | |||||
|
(q) | Misconduct | E-22 | |||||
|
(r) | Outside Director | E-23 | |||||
|
(s) | Participant | E-23 | |||||
|
(t) | Payroll | E-23 | |||||
|
(u) | Performance Year | E-23 | |||||
|
(v) | Plan | E-23 | |||||
|
(w) | Rules | E-24 | |||||
|
(x) | Subsidiary | E-24 | |||||
|
(y) | Successors or Assigns | E-24 | |||||
|
(z) | Termination, Terminated, or Terminates | E-24 | |||||
|
||||||||
SECTION IV. ADMINISTRATION | E-24 | |||||||
|
||||||||
|
(a) | Composition of the Committee | E-24 | |||||
|
(b) | Actions by the Committee | E-24 | |||||
|
(c) | Powers of the Committee | E-25 | |||||
|
(d) | Liability of Committee Members | E-26 | |||||
|
(e) | Administration of the Plan Following a Change in Control | E-26 | |||||
|
||||||||
SECTION V. AWARDS UNDER THE PLAN | E-26 | |||||||
|
||||||||
|
(a) | Discretion to Grant Awards | E-26 | |||||
|
(b) | Limitation for Covered Employees | E-26 | |||||
|
(c) | Awards Payable After Change in Control | E-26 | |||||
|
(d) | Effect of Mandatory Wage Controls | E-27 |
E-18
SECTION VI. PAYMENT OF AWARDS | E-27 | |||||||
|
||||||||
|
(a) | Non-Deferred Awards | E-27 | |||||
|
(b) | Deferral of Awards | E-27 | |||||
|
||||||||
SECTION VII. ASSIGNABILITY | E-27 | |||||||
|
||||||||
SECTION VIII. FORFEITURE FOR MISCONDUCT | E-28 | |||||||
|
||||||||
SECTION IX. AMENDMENT OF THE PLAN OR AWARDS | E-28 | |||||||
|
||||||||
SECTION X. GENERAL PROVISIONS | E-29 | |||||||
|
||||||||
|
(a) | Participants Rights Unsecured | E-29 | |||||
|
(b) | Authority to Establish a Grantor Trust | E-29 | |||||
|
(c) | Awards in Foreign Countries | E-29 | |||||
|
(d) | Costs of the Plan | E-29 | |||||
|
(e) | Binding Effect of Plan | E-29 | |||||
|
(f) | No Waiver of Breach | E-29 | |||||
|
(g) | No Right to Employment | E-29 | |||||
|
(h) | Choice of Law | E-29 | |||||
|
(i) | Severability | E-30 | |||||
|
||||||||
SECTION XI. EXECUTION | E-30 |
E-19
E-20
E-21
E-22
E-23
E-24
E-25
Officer | Percentage | |||
CEO
|
40 | % | ||
Other Covered Employees
|
15 | % each | ||
Total
|
100 | % |
E-26
E-27
E-28
E-29
By
|
/s/ Robert J. Eaton | Date | December 10, 2008 | |||||||
|
|
|
E-30
E-31
SECTION I. PURPOSE OF THE PLAN
|
E-35 | |||
|
||||
SECTION II. DEFINITIONS
|
E-35 | |||
|
||||
(a) Award
|
E-35 | |||
(b) Benefit Protection Period
|
E-35 | |||
(c) Board
|
E-35 | |||
(d) Business in Competition
|
E-35 | |||
(e) Change in Control
|
E-35 | |||
(f) Code
|
E-35 | |||
(g) Commission
|
E-36 | |||
(h) Committee
|
E-36 | |||
(i) Common Stock
|
E-36 | |||
(j) Corporation
|
E-36 | |||
(k) Corporation Confidential Information
|
E-36 | |||
(l) Covered Employee
|
E-36 | |||
(m) Director
|
E-36 | |||
(n) Dividend Equivalent
|
E-37 | |||
(o) Document
|
E-37 | |||
(p) Eligible Employee
|
E-37 | |||
(q) Exchange Act
|
E-37 | |||
(r) Fair Market Value
|
E-37 | |||
(s) Full Value Award
|
E-37 | |||
(t) Grant Eligible Employee
|
E-37 | |||
(u) Independent Director
|
E-37 | |||
(v) Misconduct
|
E-37 | |||
(w) Non-Employee Director
|
E-39 | |||
(x) Non-Stock Award
|
E-39 | |||
(y) Non-Stock Award Agreement
|
E-39 | |||
(z) Optionee
|
E-39 | |||
(aa) Other Share-Based Award
|
E-39 | |||
(bb) Other Share-Based Award Agreement
|
E-39 | |||
(cc) Outside Director
|
E-39 | |||
(dd) Participant
|
E-39 | |||
(ee) Payroll
|
E-39 | |||
(ff) Performance Share
|
E-39 | |||
(gg) Plan
|
E-39 | |||
(hh) Restricted Stock
|
E-39 | |||
(ii) Restricted Stock Agreement
|
E-39 | |||
(jj) Restricted Stock Award
|
E-40 | |||
(kk) Restricted Stock Unit
|
E-40 | |||
(ll) Restriction Period
|
E-40 | |||
(mm) Rule 16b-3
|
E-40 | |||
(nn) Rules
|
E-40 | |||
(oo) Share
|
E-40 |
E-32
(pp) Stock Appreciation Right or SAR
|
E-40 | |||
(qq) Stock Option
|
E-40 | |||
(rr) Stock Option Agreement
|
E-40 | |||
(ss) Subsidiary
|
E-40 | |||
(tt) Stock Unit
|
E-40 | |||
(uu) Successors or Assigns
|
E-40 | |||
(vv) Termination, Terminated, or Terminate
|
E-40 | |||
|
||||
SECTION III. ADMINISTRATION
|
E-41 | |||
|
||||
(a) Composition of the Committee
|
E-41 | |||
(b) Actions by the Committee
|
E-41 | |||
(c) Powers of the Committee
|
E-41 | |||
(d) Liability of Committee Members
|
E-42 | |||
(e) Administration of the Plan Following a Change in Control
|
E-43 | |||
|
||||
SECTION IV. DURATION OF THE PLAN
|
E-43 | |||
|
||||
SECTION V. SHARES SUBJECT TO THE PLAN
|
E-43 | |||
|
||||
(a) Maximum Number of Shares
|
E-43 | |||
(b) Accounting for Number of Shares
|
E-43 | |||
(c) Source of Stock Issued Under the Plan
|
E-43 | |||
|
||||
SECTION VI. PERSONS ELIGIBLE FOR AWARDS
|
E-44 | |||
|
||||
SECTION VII. AGGREGATE LIMITS ON AWARDS
|
E-44 | |||
|
||||
(a) Stock Options, Stock Appreciation Rights, Restricted Stock and Other
Share-Based Awards
|
E-44 | |||
(b) Non-stock Awards
|
E-44 | |||
|
||||
SECTION VIII. STOCK OPTIONS
|
E-44 | |||
|
||||
(a) Limitation to Non-Statutory Stock Options
|
E-44 | |||
(b) Awards of Stock Options
|
E-44 | |||
(c) Number of Shares
|
E-44 | |||
(d) Exercise Price
|
E-44 | |||
(e) Method of Payment
|
E-45 | |||
(f) Term and Exercise of Stock Options; Non-Transferability of Stock Options
|
E-45 | |||
(g) Termination of Employment
|
E-46 | |||
(h) Rights as a Stockholder
|
E-46 | |||
(i) Stock Appreciation Rights
|
E-46 | |||
|
||||
SECTION IX. RESTRICTED STOCK
|
E-46 | |||
|
||||
(a) Restricted Stock Awards
|
E-46 | |||
(b) Terms, Conditions, and Restrictions
|
E-47 | |||
(c) Limitations
|
E-47 | |||
(d) Rights as a Stockholder
|
E-48 | |||
(e) Recording of the Participants Interest
|
E-48 |
E-33
SECTION X. OTHER SHARE-BASED AWARDS
|
E-48 | |||
|
||||
(a) Grants
|
E-48 | |||
(b) Terms, Conditions, and Restrictions
|
E-49 | |||
(c) Limitations
|
E-50 | |||
|
||||
SECTION XI. NON-STOCK AWARDS
|
E-50 | |||
|
||||
(a) Grants
|
E-50 | |||
(b) Terms and Conditions
|
E-50 | |||
|
||||
SECTION XII. RECAPITALIZATION
|
E-51 | |||
|
||||
SECTION XIII. FORFEITURE FOR MISCONDUCT
|
E-52 | |||
|
||||
SECTION XIV. SECURITIES LAW REQUIREMENTS
|
E-53 | |||
|
||||
SECTION XV. AMENDMENTS OF THE PLAN OR AWARDS
|
E-54 | |||
|
||||
(a) Amendment of the Plan
|
E-54 | |||
(b) Amendments of Awards
|
E-54 | |||
(c) Rights of Participant
|
E-54 | |||
|
||||
SECTION XVI. GENERAL PROVISIONS
|
E-55 | |||
|
||||
(a) Authority to Satisfy Obligations
|
E-55 | |||
(b) Participants Stockholder Rights
|
E-55 | |||
(c) Participants Rights Unsecured
|
E-55 | |||
(d) Authority to Establish a Grantor Trust
|
E-55 | |||
(e) No Obligation to Exercise Stock Option
|
E-55 | |||
(f) Participants Beneficiary
|
E-55 | |||
(g) Deferral Elections
|
E-55 | |||
(h) Awards in Foreign Countries
|
E-55 | |||
(i) Withholding Taxes
|
E-56 | |||
(j) Other Corporation Benefit and Compensation Programs
|
E-56 | |||
(k) Application of Funds
|
E-56 | |||
(l) Costs of the Plan
|
E-56 | |||
(m) Binding Effect of Plan
|
E-56 | |||
(n) No Waiver of Breach
|
E-56 | |||
(o) No Right to Employment
|
E-57 | |||
(p) Choice of Law
|
E-57 | |||
(q) Severability
|
E-57 | |||
|
||||
SECTION XVII. APPROVAL OF STOCKHOLDERS
|
E-57 | |||
|
||||
SECTION XVIII. EXECUTION
|
E-57 |
E-34
E-35
E-36
E-37
E-38
E-39
E-40
E-41
E-42
E-43
E-44
E-45
E-46
E-47
E-48
E-49
E-50
E-51
E-52
E-53
E-54
E-55
E-56
By
|
/s/ Robert J. Eaton | Date | December 10, 2008 | |||||||
|
|
|
E-57
E-58
SECTION I. ESTABLISHMENT AND PURPOSE
|
E-61 | |||
|
||||
SECTION II. DEFINITIONS
|
E-61 | |||
|
||||
(a) Account
|
E-61 | |||
(b) Board
|
E-61 | |||
(c) Business in Competition
|
E-61 | |||
(d) Change in Control
|
E-61 | |||
(e) Chevron Incentive Plan
|
E-62 | |||
(f) Code
|
E-62 | |||
(g) Commission
|
E-62 | |||
(h) Committee
|
E-62 | |||
(i) Common Stock
|
E-62 | |||
(j) Corporation
|
E-62 | |||
(k) Corporation Confidential Information
|
E-62 | |||
(l) Covered Employee
|
E-63 | |||
(m) Director
|
E-63 | |||
(n) Document
|
E-63 | |||
(o) Eligible Employee
|
E-63 | |||
(p) ERISA
|
E-63 | |||
(q) Exchange Act
|
E-63 | |||
(r) Independent Director
|
E-63 | |||
(s) Long-Term Incentive Plan
|
E-63 | |||
(t) Misconduct
|
E-63 | |||
(u) Non-Employee Director
|
E-64 | |||
(v) Outside Director
|
E-64 | |||
(w) Participant
|
E-65 | |||
(x) Payroll
|
E-65 | |||
(y) Plan
|
E-65 | |||
(z) Plan Year
|
E-65 | |||
(aa) Prior Plan
|
E-65 | |||
(bb) Rule 16b-3
|
E-65 | |||
(cc) Rules
|
E-65 | |||
(dd) Subsidiary
|
E-65 | |||
(ee) Successors or Assigns
|
E-65 | |||
|
||||
SECTION III. ADMINISTRATION
|
E-65 | |||
|
||||
(a) Composition of the Committee
|
E-65 | |||
(b) Actions by the Committee
|
E-66 | |||
(c) Powers of the Committee
|
E-66 | |||
(d) Liability of Committee Members
|
E-67 | |||
(e) Administration of the Plan Following a Change in Control
|
E-67 | |||
|
||||
SECTION IV. ASSIGNMENT OR TRANSFER OF ACCOUNT
|
E-67 |
E-59
SECTION V. RECAPITALIZATION
|
E-67 | |||
|
||||
SECTION VI. SECURITIES LAW REQUIREMENTS
|
E-68 | |||
|
||||
SECTION VII. FORFEITURE FOR MISCONDUCT
|
E-68 | |||
|
||||
SECTION VIII. AMENDMENT OR TERMINATION OF THE PLAN
|
E-69 | |||
|
||||
(a) Right to Alter, Amend, or Terminate the Plan
|
E-69 | |||
(b) Rights of Participant
|
E-70 | |||
(c) Effect on Other Plans
|
E-70 | |||
(d) Corporation Dissolution or Bankruptcy
|
E-70 | |||
|
||||
SECTION IX. GENERAL PROVISIONS
|
E-70 | |||
|
||||
(a) Participants Rights Unsecured
|
E-70 | |||
(b) Authority to Establish a Grantor Trust
|
E-70 | |||
(c) Other Benefit Plans
|
E-71 | |||
(d) Participants Beneficiary
|
E-71 | |||
(e) Costs of the Plan
|
E-71 | |||
(f) Binding Effect of Plan
|
E-71 | |||
(g) No Waiver of Breach
|
E-71 | |||
(h) No Right to Employment
|
E-71 | |||
(i) Choice of Law
|
E-71 | |||
(j) Severability
|
E-71 | |||
|
||||
SECTION X. EXECUTION
|
E-71 |
E-60
E-61
E-62
E-63
E-64
E-65
E-66
E-67
E-68
E-69
E-70
By
|
/s/ Robert J. Eaton | Date | December 10, 2008 | |||||
|
E-71
E-72
Page | ||||
SECTION I. INTRODUCTION
|
E-76 | |||
|
||||
SECTION II. DEFINITIONS
|
E-77 | |||
|
||||
(a) Beneficiary
|
E-77 | |||
(b) Benefit Calculation Date
|
E-77 | |||
(c) Benefit Protection Period
|
E-77 | |||
(d) Benefit Protection Period Commencement Date
|
E-77 | |||
(e) Business in Competition
|
E-77 | |||
(f) Change in Control
|
E-77 | |||
(g) Code
|
E-77 | |||
(h) Committee
|
E-78 | |||
(i) Corporation
|
E-78 | |||
(j) Corporation Confidential Information
|
E-78 | |||
(k) Document
|
E-78 | |||
(l) Employee
|
E-78 | |||
(m) ERISA
|
E-79 | |||
(n) ESIP-RP
|
E-79 | |||
(o) Excess Plan
|
E-79 | |||
(p) Initial Election Due Date
|
E-79 | |||
(q) Misconduct
|
E-79 | |||
(r) Participant
|
E-80 | |||
(s) Payroll
|
E-81 | |||
(t) Plan Year
|
E-81 | |||
(u) Prior Period Plan
|
E-81 | |||
(v) Prior Plans
|
E-81 | |||
(w) Quarter
|
E-81 | |||
(x) Restoration Benefit
|
E-81 | |||
(y) Retirement Plan
|
E-81 | |||
(z) Retirement Plan Benefit
|
E-81 | |||
(aa) RRP
|
E-81 | |||
(bb) Separation from Service
|
E-81 |
E-73
Page | ||||
(cc) SRP
|
E-82 | |||
(dd) Subsidiary
|
E-82 | |||
(ee) Successors and Assigns
|
E-82 | |||
(ff) Unforeseeable Emergency
|
E-82 | |||
(gg) Unocal
|
E-83 | |||
(hh) Unocal Nonqualified Retirement Plans
|
E-83 | |||
|
||||
SECTION III. ELIGIBILITY AND PARTICIPATION
|
E-83 | |||
|
||||
(a) Active Employee Participants
|
E-83 | |||
(b) Terminated Employee Participants
|
E-83 | |||
(c) Other Employee Participants
|
E-83 | |||
|
||||
SECTION IV. PLAN BENEFITS
|
E-83 | |||
|
||||
(a) Restoration Benefit
|
E-84 | |||
(b) Gulf Retirement Bonus
|
E-84 | |||
(c) Calculation of Lump Sum Value of Single Life Annuity
|
E-85 | |||
(d) Interest
|
E-85 | |||
|
||||
SECTION V. DISTRIBUTION OF PLAN BENEFITS
|
E-85 | |||
|
||||
(a) Default Distribution Form
|
E-85 | |||
(b) Distribution Election
|
E-85 | |||
(c) Determination of Installment Payment Amount
|
E-86 | |||
(d) Change of Distribution Time and Form
|
E-86 | |||
(e) Acceleration of Payments
|
E-86 | |||
(f) Unforeseeable Emergency
|
E-86 | |||
(g) Mandatory Cashout Limit
|
E-86 | |||
|
||||
SECTION VI. DEATH BENEFITS
|
E-87 | |||
|
||||
(a) Beneficiary Designation
|
E-87 | |||
(b) Time and Form of Death Benefit
|
E-87 | |||
|
||||
SECTION VII. MISCELLANEOUS
|
E-87 | |||
|
||||
(a) Forfeitures
|
E-87 | |||
(b) Funding
|
E-87 | |||
(c) Tax Withholding
|
E-87 | |||
(d) No Employment Rights
|
E-88 |
E-74
Page | ||||
(e) No Assignment of Property Rights
|
E-88 | |||
(f) Administration
|
E-88 | |||
(g) Amendment and Termination
|
E-88 | |||
(h) Effect of Reemployment
|
E-89 | |||
(i) Excess Plan/Top-Hat Plan Status
|
E-89 | |||
(j) Successors and Assigns
|
E-90 | |||
(k) 409A Compliance
|
E-90 | |||
(l) Choice of Law
|
E-90 | |||
|
||||
SECTION VIII. CHANGE IN CONTROL
|
E-90 | |||
|
||||
(a) Restrictions on Amendments During Benefit Protection Period
|
E-90 | |||
(b) Exception to Section VIII.(a)
|
E-90 | |||
(c) Restrictions on Certain Actions Prior to or Following, a Change in Control
|
E-91 | |||
(d) Effect on other Benefits
|
E-91 | |||
(e) Distribution of Restoration Benefits
|
E-91 | |||
(f) Establishment of a Trust
|
E-91 | |||
(g) No Forfeitures
|
E-91 | |||
(h) Miscellaneous
|
E-91 | |||
|
||||
SECTION IX. GRANDFATHERED PROVISIONS
|
E-92 | |||
|
||||
SECTION X. EXECUTION
|
E-92 | |||
|
||||
APPENDIX A
|
E-93 | |||
|
||||
APPENDIX B
|
E-94 | |||
|
||||
APPENDIX C
|
E-96 | |||
|
||||
APPENDIX D
|
E-97 |
E-75
E-76
E-77
E-78
E-79
E-80
E-81
E-82
E-83
E-84
E-85
E-86
E-87
E-88
E-89
E-90
E-91
By
|
/s/ Robert J. Eaton | Date | December 10, 2008 | |||||
|
E-92
E-93
E-94
(a) | the Participants effective election as of December 31, 2008, or | ||
(b) | in the case of a Pre-2006 Plan Participant whose Annuity Starting Date for Retirement Plan benefits occurred in 2005 or 2006, if the Participant did not make an effective election as of December 31, 2008, the default distribution form of ten (10) approximately equal annual installments that commenced in the first Quarter that was at least 12 months after the date the Annuity Starting Date. | ||
(c) | All installments after the first shall be paid in January. The amount of any installment payment shall be determined by dividing the unpaid balance of the Pre-2006 Plan Participants Pre-2006 Plan Benefit, including credited interest, as of the beginning of the Quarter that includes the distribution date, by the number of annual payments remaining to be made. |
E-95
(a) | the Participants effective election as of December 31, 2008, or if the Participant did not make an effective election, the default distribution form of a lump sum payable in the first Quarter that is at least 12 months after the date the Participant incurs a Separation from Service, and | ||
(b) | Section 4(f) of the 2006 Plan, if applicable. | ||
(c) | All installments after the first shall be paid in January. The amount of any installment payment shall be determined by dividing the unpaid balance of the 2006 Plan Participants 2006 Plan Benefit, including credited interest, as of the beginning of the Quarter that includes the distribution date, by the number of annual payments remaining to be made. |
E-96
E-97
(a) | the Participants effective election as of December 31, 2008, or | ||
(b) | if the Participant did not make an effective election as of December 31, 2008, the default distribution form of ten (10) approximately equal annual installments that commenced in the first Quarter that was at least 12 months after the date the Participant incurred a Separation from Service. | ||
(c) | All installments after the first shall be paid in January. The amount of any installment payment shall be determined by dividing the unpaid balance of the SRP Participants SRP Benefit, including credited interest, as of the beginning of the Quarter that includes the distribution date, by the number of annual payments remaining to be made. |
E-98
E-99
Page | ||||||
SECTION I. INTRODUCTION | E-103 | |||||
|
||||||
SECTION II. DEFINITIONS | E-104 | |||||
|
||||||
(a)
|
Account or Accounts | E-104 | ||||
(b)
|
Beneficiary | E-104 | ||||
(c)
|
Benefit Protection Period | E-104 | ||||
(d)
|
Benefit Protection Period Commencement Date | E-104 | ||||
(e)
|
Business in Competition | E-104 | ||||
(f)
|
Change in Control | E-104 | ||||
(g)
|
Chevron Stock | E-104 | ||||
(h)
|
Code | E-104 | ||||
(i)
|
Committee | E-104 | ||||
(j)
|
Composite Transaction Report | E-105 | ||||
(k)
|
Corporation | E-105 | ||||
(l)
|
Corporation Confidential Information | E-105 | ||||
(m)
|
Deferred Compensation Plan | E-105 | ||||
(n)
|
DCP | E-105 | ||||
(o)
|
DCP Salary Deferral | E-105 | ||||
(p)
|
Document | E-106 | ||||
(q)
|
Employee | E-106 | ||||
(r)
|
ERISA | E-106 | ||||
(s)
|
ESIP | E-106 | ||||
(t)
|
ESIP RP Regular Earnings | E-106 | ||||
(u)
|
ESIP RP | E-106 | ||||
(v)
|
ESIP Restoration Benefit | E-106 | ||||
(w)
|
Excess Plan | E-106 | ||||
(x)
|
Grandfathered Amount | E-107 | ||||
(y)
|
Misconduct | E-107 | ||||
(z)
|
Participant | E-108 |
E-100
Page | ||||||
(aa)
|
Payroll | E-108 | ||||
(bb)
|
Plan Benefit | E-108 | ||||
(cc)
|
Plan Year | E-108 | ||||
(dd)
|
Quarter | E-108 | ||||
(ee)
|
Section 401(a)(17) Limitation | E-108 | ||||
(ff)
|
Separation from Service | E-108 | ||||
(gg)
|
Stock Units | E-109 | ||||
(hh)
|
Subsidiary | E-109 | ||||
(ii)
|
Successors and Assigns | E-109 | ||||
(jj)
|
Unforeseeable Emergency | E-109 | ||||
|
||||||
SECTION III. ELIGIBILITY AND PARTICIPATION | E-110 | |||||
|
||||||
SECTION IV. PLAN BENEFITS | E-110 | |||||
|
||||||
(a)
|
Allocation of Stock Units | E-110 | ||||
(b)
|
Earnings | E-111 | ||||
|
||||||
SECTION V. DISTRIBUTION OF PLAN BENEFITS | E-111 | |||||
|
||||||
(a)
|
Default Distribution Form | E-111 | ||||
(b)
|
Distribution Election | E-111 | ||||
(c)
|
Valuation of Stock Units/Determination of Installment Payments | E-111 | ||||
(d)
|
Change of Distribution Form Election | E-112 | ||||
(e)
|
Acceleration of Payments | E-112 | ||||
(f)
|
Unforeseeable Emergency | E-112 | ||||
(g)
|
Cashout Limit | E-113 | ||||
|
||||||
SECTION VI. DEATH BENEFITS | E-113 | |||||
|
||||||
(a)
|
Beneficiary Designation | E-113 | ||||
(b)
|
Time and Form of Death Benefit | E-113 | ||||
|
||||||
SECTION VII. MISCELLANEOUS | E-113 | |||||
|
||||||
(a)
|
Forfeitures | E-113 | ||||
(b)
|
Funding | E-113 | ||||
(c)
|
Tax Withholding | E-113 |
E-101
E-102
E-103
E-104
E-105
E-106
E-107
E-108
E-109
E-110
E-111
E-112
E-113
E-114
E-115
E-116
E-117
By
|
/s/ Robert J. Eaton | Date | December 10, 2008 | |||||
|
E-118
E-119
(i) | the Participants election in effect on December 31, 2008 or, if no election was in effect on December 31, 2008, the default distribution form specified in Section 4(a) of the Chevron Corporation ESIP Restoration Plan (Amended and Restated as of July 1, 2006) (the 2006 Plan), and | ||
(ii) | Section 4(e) of the 2006 Plan, if applicable. |
E-120
E-121
E-122
1. | Date of Grant: | ||
2. | The number of Stock Units awarded is , subject to adjustment as provided in Section 10 of the Plan. | ||
3. | The Stock Units vest on the last day of the Annual Compensation Cycle to which the Grant relates. |
Date:
|
By: | |||||
|
||||||
|
||||||
Date:
|
By: | |||||
|
||||||
|
Director |
E-123
Year Ended December 31 | ||||||||||||||||||||
2008 | 2007 | 2006 | 2005 | 2004 | ||||||||||||||||
Income From Continuing Operations
|
$ | 23,931 | $ | 18,688 | $ | 17,138 | $ | 14,099 | $ | 13,034 | ||||||||||
Income Tax Expense
|
19,026 | 13,479 | 14,838 | 11,098 | 7,517 | |||||||||||||||
Distributions (Less) Greater Than Equity in Earnings of
Affiliates
|
(440 | ) | (1,439 | ) | (979 | ) | (1,304 | ) | (1,422 | ) | ||||||||||
Minority Interest
|
100 | 107 | 70 | 96 | 85 | |||||||||||||||
Previously Capitalized Interest Charged to Earnings During Period
|
91 | 62 | 111 | 93 | 83 | |||||||||||||||
Interest and Debt Expense
|
| 166 | 451 | 482 | 406 | |||||||||||||||
Interest Portion of Rentals*
|
983 | 798 | 766 | 688 | 687 | |||||||||||||||
Earnings Before Provision for Taxes and Fixed Charges
|
$ | 43,691 | $ | 31,861 | $ | 32,395 | $ | 22,252 | $ | 20,390 | ||||||||||
Interest and Debt Expense
|
$ | | $ | 166 | $ | 451 | $ | 482 | $ | 406 | ||||||||||
Interest Portion of Rentals*
|
983 | 798 | 766 | 688 | 687 | |||||||||||||||
Preferred Stock Dividends of Subsidiaries
|
| 1 | 1 | 1 | 1 | |||||||||||||||
Capitalized Interest
|
256 | 302 | 157 | 60 | 44 | |||||||||||||||
Total Fixed Charges
|
$ | 1,239 | $ | 1,267 | $ | 1,375 | $ | 1,231 | $ | 1,138 | ||||||||||
Ratio of Earnings to Fixed Charges
|
35.26 | 25.15 | 23.56 | 20.51 | 17.92 |
E-124
State, Province or Country in Which
|
||
Name of Subsidiary | Organized | |
Beta Offshore Nigeria Deepwater
Limited
2
|
Nigeria | |
Cabinda Gulf Oil Company Limited
|
Bermuda | |
Chevron and Gulf UK Pension Plan Trustee Company Limited
|
England | |
Chevron Argentina S.R.L
|
Argentina | |
Chevron Australia Pty Ltd.
|
Australia | |
Chevron Australia Transport Pty Ltd.
|
Australia | |
Chevron (Bermuda) Investments Limited
|
Bermuda | |
Chevron Brasil Ltda.
|
Brazil | |
Chevron Brasil Petróleo Limitada
|
Brazil | |
Chevron Canada Capital Company
|
Nova Scotia | |
Chevron Canada Finance Limited
|
Canada | |
Chevron Canada Funding Company
|
Nova Scotia | |
Chevron Canada Limited
|
Canada | |
Chevron Capital Corporation
|
Delaware | |
Chevron Caspian Pipeline Consortium Company
|
Delaware | |
Chevron Environmental Management Company
3
|
California | |
Chevron Funding Corporation
|
Delaware | |
Chevron Geothermal Indonesia, Ltd.
|
Bermuda | |
Chevron Global Energy Inc.
|
Delaware | |
Chevron Global Power Company
|
Pennsylvania | |
Chevron Global Technology Services Company
|
Delaware | |
Chevron Global Upstream and
Gas
4
|
Pennsylvania | |
Chevron International (Congo) Limited
|
Bermuda | |
Chevron International Petroleum Company
|
Delaware | |
Chevron Investment Management Company
|
Delaware | |
Chevron LNG Shipping Company Limited
|
Bermuda | |
Chevron Marine Products
LLC
5
|
Delaware | |
Chevron Mining Inc.
|
Missouri | |
Chevron New Zealand
|
New Zealand | |
Chevron Nigeria Deepwater B Limited
|
Nigeria | |
Chevron Nigeria Deepwater D Limited
|
Nigeria | |
Chevron Nigeria Limited
|
Nigeria | |
Chevron Oil Congo (D.R.C.) Limited
|
Bermuda |
E-125
State, Province or Country in Which
|
||
Name of Subsidiary | Organized | |
Chevron Oronite Company LLC
|
Delaware | |
Chevron Oronite Pte. Ltd.
|
Singapore | |
Chevron Oronite S.A.
|
France | |
Chevron Overseas Company
|
Delaware | |
Chevron Overseas (Congo) Limited
|
Bermuda | |
Chevron Overseas Petroleum Limited
|
Bahamas | |
Chevron Overseas Pipeline (Cameroon) Limited
|
Bahamas | |
Chevron Overseas Pipeline (Chad) Limited
|
Bahamas | |
Chevron Pakistan Limited
|
Bahamas | |
Chevron Petroleum Chad Company Limited
|
Bermuda | |
Chevron Petroleum Company
|
New Jersey | |
Chevron Petroleum Limited
|
Bermuda | |
Chevron Philippines Inc.
|
Philippines | |
Chevron Pipe Line Company
|
Delaware | |
Chevron South Natuna B Inc.
|
Liberia | |
Chevron Synfuels Limited
|
Bermuda | |
Chevron Thailand Exploration and Production, Ltd.
|
Bermuda | |
Chevron Thailand
LLC
6
|
Delaware | |
Chevron (Thailand) Limited
|
Bahamas | |
Chevron Transport Corporation Ltd.
|
Bermuda | |
Chevron United Kingdom Limited
|
England and Wales | |
Chevron U.S.A. Holdings Inc.
|
Delaware | |
Chevron U.S.A. Inc.
|
Pennsylvania | |
Equatorial Guinea Ltd.
|
Bermuda | |
Four Star Oil & Gas Company
|
Delaware | |
Heddington Insurance Limited
|
Bermuda | |
HUTTS, LLC
|
Delaware | |
Insco Limited
|
Bermuda | |
Iron Horse Insurance Co.
|
Vermont | |
Oilfield Concession Operators
Limited
7
|
Nigeria | |
PT Chevron Pacific Indonesia
|
Indonesia | |
Saudi Arabian Chevron Inc.
|
Delaware | |
Texaco Britain Limited
|
England | |
Texaco Capital Inc.
|
Delaware | |
Texaco Captain Inc.
|
Delaware | |
Texaco Inc.
|
Delaware | |
Texaco Investments (Netherlands), Inc.
|
Delaware | |
Texaco Overseas Holdings Inc.
|
Delaware | |
Texaco Venezuela Holdings (I) Company
|
Delaware | |
Traders Insurance Limited
|
Bermuda | |
TRMI-H LLC
|
Delaware | |
Union Oil Company of California
|
California |
E-126
State, Province or Country in Which
|
||
Name of Subsidiary | Organized | |
Unocal Corporation
|
Delaware | |
Unocal Energy Trading Inc.
|
Delaware | |
Unocal International Corporation
|
Nevada | |
Unocal Pipeline Company
|
California | |
West Australian Petroleum Pty Limited
|
Australia |
1 | All of the subsidiaries in the above list are wholly owned, either directly or indirectly, by Chevron Corporation. Certain subsidiaries are not listed since, considered in the aggregate as a single subsidiary, they would not constitute a significant subsidiary at December 31, 2008. | |
2 | Name changed from Chevron Nigeria Deepwater A Limited in April 2008. | |
3 | Chevron Environmental Services Company merged into Chevron Environmental Management Company in April 2008. | |
4 | Chevron International Exploration and Production Company became Chevron Global Upstream and Gas in January 2008. | |
5 | Name changed from Fuel and Marine Marketing LLC in February 2008. | |
6 | Chevron Thailand Inc became Chevron Thailand LLC in September 2008. | |
7 | Chevron Nigeria Deepwater C Limited became Oilfield Concession Operators Limited in January 2008. |
E-127
E-128
/s/ Samuel H. Armacost | ||||
E-129
/s/ Linnet F. Deily | ||||
E-130
/s/ Robert E. Denham | ||||
E-131
/s/ Robert J. Eaton | ||||
E-132
/s/ Sam Ginn | ||||
E-133
/s/ Enrique Hernandez, Jr. | ||||
E-134
/s/ Franklyn G. Jenifer | ||||
E-135
/s/ Sam Nunn | ||||
E-136
/s/ Donald B. Rice | ||||
E-137
/s/ Kevin W. Sharer | ||||
E-138
/s/ Charles R. Shoemate | ||||
E-139
/s/ Ronald D. Sugar | ||||
E-140
/s/ Carl Ware | ||||
E-141
E-142
E-143
E-144
E-145
E-146
E-147
E-148