e10vk
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
þ ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31,
2011
OR
o TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from
to
Commission File Number
001-00368
Chevron Corporation
(Exact name of registrant as specified in its charter)
|
|
|
|
|
Delaware
|
|
94-0890210
|
|
6001 Bollinger Canyon Road,
San Ramon, California 94583-2324
|
|
|
|
|
|
(State or other jurisdiction of
incorporation or organization)
|
|
(I.R.S. Employer
Identification No.)
|
|
(Address of principal executive offices) (Zip Code)
|
Registrants telephone number, including area code
(925) 842-1000
Securities registered pursuant to Section 12 (b) of the Act:
|
|
|
Title of Each Class
|
|
Name of Each Exchange
on Which Registered
|
Common
stock, par value $.75 per share
|
|
New
York Stock Exchange, Inc.
|
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act.
Yes þ No o
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act.
Yes o No þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days.
Yes þ No o
Indicate by check mark whether the registrant has submitted
electronically and posted on its corporate Web site, if any,
every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of
Regulation S-T
(§ 232.405 of this chapter) during the preceding
12 months (or for such shorter period that the registrant
was required to submit and post such
files). Yes þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
(§ 229.405 of this chapter) is not contained herein,
and will not be contained, to the best of registrants
knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this
Form 10-K
or any amendment to this
Form 10-K. o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in
Rule 12b-2
of the Exchange Act.
|
|
|
|
|
|
|
Large
accelerated filer þ
|
|
Accelerated filer o
|
|
Non-accelerated filer o
(Do not check if a smaller
reporting company)
|
|
Smaller reporting company o
|
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the
Act). Yes o No þ
Aggregate market value of the voting and non-voting common
equity held by non-affiliates computed by reference to the price
at which the common equity was last sold, or the average bid and
asked price of such common equity, as of the last business day
of the registrants most recently completed second fiscal
quarter $205,986,778,815 (As of June 30, 2011)
Number of Shares of Common Stock outstanding as of
February 13, 2012 1,976,966,530
DOCUMENTS INCORPORATED BY REFERENCE
(To The Extent Indicated Herein)
Notice of the 2012 Annual Meeting and 2012 Proxy Statement, to
be filed pursuant to
Rule 14a-6(b)
under the Securities Exchange Act of 1934, in connection with
the companys 2012 Annual Meeting of Stockholders (in
Part III)
CAUTIONARY
STATEMENT RELEVANT TO FORWARD-LOOKING INFORMATION
FOR THE PURPOSE OF SAFE HARBOR PROVISIONS OF THE
PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This Annual Report on
Form 10-K
of Chevron Corporation contains forward-looking statements
relating to Chevrons operations that are based on
managements current expectations, estimates and
projections about the petroleum, chemicals and other
energy-related industries. Words such as
anticipates, expects,
intends, plans, targets,
projects, believes, seeks,
schedules, estimates,
budgets and similar expressions are intended to
identify such forward-looking statements. These statements are
not guarantees of future performance and are subject to certain
risks, uncertainties and other factors, some of which are beyond
the companys control and are difficult to predict.
Therefore, actual outcomes and results may differ materially
from what is expressed or forecasted in such forward-looking
statements. The reader should not place undue reliance on these
forward-looking statements, which speak only as of the date of
this report. Unless legally required, Chevron undertakes no
obligation to update publicly any forward-looking statements,
whether as a result of new information, future events or
otherwise.
Among the important factors that could cause actual results to
differ materially from those in the forward-looking statements
are: changing crude oil and natural gas prices; changing
refining, marketing and chemical margins; actions of competitors
or regulators; timing of exploration expenses; timing of crude
oil liftings; the competitiveness of alternate-energy sources or
product substitutes; technological developments; the results of
operations and financial condition of equity affiliates; the
inability or failure of the companys joint-venture
partners to fund their share of operations and development
activities; the potential failure to achieve expected net
production from existing and future crude oil and natural gas
development projects; potential delays in the development,
construction or
start-up of
planned projects; the potential disruption or interruption of
the companys net production or manufacturing facilities or
delivery/transportation networks due to war, accidents,
political events, civil unrest, severe weather or crude oil
production quotas that might be imposed by the Organization of
Petroleum Exporting Countries; the potential liability for
remedial actions or assessments under existing or future
environmental regulations and litigation; significant investment
or product changes under existing or future environmental
statutes, regulations and litigation; the potential liability
resulting from other pending or future litigation; the
companys future acquisition or disposition of assets and
gains and losses from asset dispositions or impairments;
government-mandated sales, divestitures, recapitalizations,
industry-specific taxes, changes in fiscal terms or restrictions
on scope of company operations; foreign currency movements
compared with the U.S. dollar; the effects of changed
accounting rules under generally accepted accounting principles
promulgated by
rule-setting
bodies; and the factors set forth under the heading Risk
Factors on pages 29 through 31 in this report. In
addition, such results could be affected by general domestic and
international economic and political conditions. Other
unpredictable or unknown factors not discussed in this report
could also have material adverse effects on forward-looking
statements.
2
PART I
|
|
(a)
|
General
Development of Business
|
Summary
Description of Chevron
Chevron
Corporation,*
a Delaware corporation, manages its investments in subsidiaries
and affiliates and provides administrative, financial,
management and technology support to U.S. and international
subsidiaries that engage in fully integrated petroleum
operations, chemicals operations, mining operations, power
generation and energy services. Upstream operations consist
primarily of exploring for, developing and producing crude oil
and natural gas; processing, liquefaction, transportation and
regasification associated with liquefied natural gas;
transporting crude oil by major international oil export
pipelines; transporting, storage and marketing of natural gas;
and a
gas-to-liquids
project. Downstream operations consist primarily of refining
crude oil into petroleum products; marketing of crude oil and
refined products; transporting crude oil and refined products by
pipeline, marine vessel, motor equipment and rail car; and
manufacturing and marketing of commodity petrochemicals,
plastics for industrial uses and fuel and lubricant additives.
A list of the companys major subsidiaries is presented on
pages E-4
and E-5. As
of December 31, 2011, Chevron had approximately
61,000 employees (including about 3,800 service station
employees). Approximately 30,000 employees (including about
3,500 service station employees), or 49 percent, were
employed in U.S. operations.
Overview
of Petroleum Industry
Petroleum industry operations and profitability are influenced
by many factors. Prices for crude oil, natural gas, petroleum
products and petrochemicals are generally determined by supply
and demand. The members of the Organization of Petroleum
Exporting Countries (OPEC) are typically the worlds swing
producers of crude oil and their production levels are a major
factor in determining worldwide supply. Demand for crude oil and
its products and for natural gas is largely driven by the
conditions of local, national and global economies, although
weather patterns and taxation relative to other energy sources
also play a significant part. Laws and governmental policies,
particularly in the areas of taxation, energy and the
environment affect where and how companies conduct their
operations and formulate their products and, in some cases,
limit their profits directly.
Strong competition exists in all sectors of the petroleum and
petrochemical industries in supplying the energy, fuel and
chemical needs of industry and individual consumers. Chevron
competes with fully integrated, major global petroleum
companies, as well as independent and national petroleum
companies, for the acquisition of crude oil and natural gas
leases and other properties and for the equipment and labor
required to develop and operate those properties. In its
downstream business, Chevron also competes with fully
integrated, major petroleum companies and other independent
refining, marketing, transportation and chemicals entities and
national petroleum companies in the sale or acquisition of
various goods or services in many national and international
markets.
Operating
Environment
Refer to pages FS-2 through FS-8 of this
Form 10-K
in Managements Discussion and Analysis of Financial
Condition and Results of Operations for a discussion of the
companys current business environment and outlook.
* Incorporated
in Delaware in 1926 as Standard Oil Company of California, the
company adopted the name Chevron Corporation in 1984 and
ChevronTexaco Corporation in 2001. In 2005, ChevronTexaco
Corporation changed its name to Chevron Corporation. As used in
this report, the term Chevron and such terms as
the company, the corporation,
our, we and us may refer to
Chevron Corporation, one or more of its consolidated
subsidiaries, or all of them taken as a whole, but unless stated
otherwise it does not include affiliates of
Chevron i.e., those companies accounted for by the
equity method (generally owned 50 percent or less) or
investments accounted for by the cost method. All of these terms
are used for convenience only and are not intended as a precise
description of any of the separate companies, each of which
manages its own affairs.
3
Chevrons
Strategic Direction
Chevrons primary objective is to create shareholder value
and achieve sustained financial returns from its operations that
will enable it to outperform its competitors. In the upstream,
the companys strategies are 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 natural gas business. In the downstream, the
strategies are to improve returns and grow earnings across the
value chain. The company also continues to utilize technology
across all its businesses to differentiate performance, and to
invest in profitable renewable energy and energy efficiency
solutions.
|
|
(b)
|
Description
of Business and Properties
|
The upstream and downstream activities of the company and its
equity affiliates are widely dispersed geographically, with
operations in North America, South America, Europe, Africa, Asia
and Australia. Tabulations of segment sales and other operating
revenues, earnings and income taxes for the three years ending
December 31, 2011, and assets as of the end of 2011 and
2010 for the United States and the companys
international geographic areas are in Note 11
to the Consolidated Financial Statements beginning on
page FS-37.
Similar comparative data for the companys investments in
and income from equity affiliates and property, plant and
equipment are in Notes 12 and 13 on pages FS-39 through
FS-41.
Capital
and Exploratory Expenditures
Total expenditures for 2011 were $29.1 billion, including
$1.7 billion for the companys share of
equity-affiliate expenditures. In 2010 and 2009, expenditures
were $21.8 billion and $22.2 billion, respectively,
including the companys share of affiliates
expenditures of $1.4 billion in 2010 and $1.6 billion
in 2009.
Of the $29.1 billion in expenditures for 2011,
89 percent, or $25.9 billion, was related to upstream
activities. Approximately 87 and 80 percent was expended
for upstream operations in 2010 and 2009, respectively.
International upstream accounted for about 68 percent of
the worldwide upstream investment in 2011, about 82 percent
in 2010 and about 80 percent in 2009. These amounts exclude
the acquisition of Atlas Energy, Inc. in 2011. Refer to a
discussion of the acquisition of Atlas Energy, Inc., in
Note 2 to the Consolidated Financial Statements on
page FS-30.
In 2012, the company estimates capital and exploratory
expenditures will be $32.7 billion, including
$3 billion of spending by affiliates. Approximately
87 percent of the total, or $28.5 billion, is budgeted
for exploration and production activities, with
$22.3 billion, or about 78 percent, of this amount for
projects outside the United States.
Refer also to a discussion of the companys capital and
exploratory expenditures on pages FS-11 through FS-12.
Upstream
The table on the following page summarizes the net production of
liquids and natural gas for 2011 and 2010 by the company and its
affiliates. Worldwide oil-equivalent production was
2.673 million barrels per day, down about three percent
from 2010. The decrease was mainly associated with normal field
declines, maintenance-related downtime and the impact of higher
prices on entitlement volumes. The
start-up and
ramp-up of
several major capital projects the Perdido project
in the U.S. Gulf of Mexico, the expansion at the Athabasca
Oil Sands Project in Canada, the Frade Field in Brazil, and the
Platong II natural gas project in Thailand as
well as acquisitions in the Marcellus Shale, partially offset
the decrease in net production from 2010. Refer to the
Results of Operations section beginning on
page FS-6
for a detailed discussion of the factors explaining the
2009 2011 changes in production for crude oil and
natural gas liquids, and natural gas.
The company estimates its average worldwide oil-equivalent
production in 2012 will be approximately 2.680 million
barrels per day based on the average Brent price of $111 per
barrel in 2011. This estimate is subject to many factors and
uncertainties, including quotas that may be imposed by OPEC,
price effects on entitlement volumes, changes in fiscal terms or
restrictions on the scope of company operations, delays in
project startups, fluctuations in demand for natural gas in
various markets, weather conditions that may shut in production,
civil unrest, changing geopolitics, delays in completion of
maintenance turnarounds,
greater-than-expected
declines in production from mature fields, or other disruptions
to operations. The outlook for future production levels is also
affected by the size and number of economic investment
opportunities and, for new, large-scale projects, the time lag
between initial exploration and the beginning of production.
Refer to the Review of Ongoing Exploration and Production
Activities in Key Areas, beginning on page 8, for a
discussion of the companys major crude oil and natural gas
development projects.
4
Net
Production of Crude Oil and Natural Gas Liquids and Natural Gas
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Components of Oil-Equivalent
|
|
|
|
|
|
|
|
|
|
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)
|
|
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
United States
|
|
|
678
|
|
|
|
708
|
|
|
|
465
|
|
|
|
489
|
|
|
|
1,279
|
|
|
|
1,314
|
|
Other Americas:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
70
|
|
|
|
54
|
|
|
|
69
|
|
|
|
53
|
|
|
|
4
|
|
|
|
4
|
|
Colombia
|
|
|
39
|
|
|
|
41
|
|
|
|
|
|
|
|
|
|
|
|
234
|
|
|
|
249
|
|
Brazil
|
|
|
35
|
|
|
|
24
|
|
|
|
33
|
|
|
|
23
|
|
|
|
13
|
|
|
|
7
|
|
Trinidad and Tobago
|
|
|
31
|
|
|
|
38
|
|
|
|
|
|
|
|
1
|
|
|
|
183
|
|
|
|
223
|
|
Argentina
|
|
|
27
|
|
|
|
32
|
|
|
|
26
|
|
|
|
31
|
|
|
|
4
|
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Other Americas
|
|
|
202
|
|
|
|
189
|
|
|
|
128
|
|
|
|
108
|
|
|
|
438
|
|
|
|
488
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Africa:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nigeria
|
|
|
260
|
|
|
|
253
|
|
|
|
236
|
|
|
|
239
|
|
|
|
142
|
|
|
|
86
|
|
Angola
|
|
|
147
|
|
|
|
161
|
|
|
|
139
|
|
|
|
152
|
|
|
|
50
|
|
|
|
52
|
|
Chad
|
|
|
26
|
|
|
|
28
|
|
|
|
25
|
|
|
|
27
|
|
|
|
6
|
|
|
|
6
|
|
Republic of the Congo
|
|
|
23
|
|
|
|
25
|
|
|
|
21
|
|
|
|
23
|
|
|
|
10
|
|
|
|
10
|
|
Democratic Republic of the Congo
|
|
|
3
|
|
|
|
2
|
|
|
|
3
|
|
|
|
2
|
|
|
|
1
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Africa
|
|
|
459
|
|
|
|
469
|
|
|
|
424
|
|
|
|
443
|
|
|
|
209
|
|
|
|
155
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asia:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Thailand
|
|
|
209
|
|
|
|
216
|
|
|
|
65
|
|
|
|
70
|
|
|
|
867
|
|
|
|
875
|
|
Indonesia
|
|
|
208
|
|
|
|
226
|
|
|
|
166
|
|
|
|
187
|
|
|
|
253
|
|
|
|
236
|
|
Partitioned
Zone2
|
|
|
91
|
|
|
|
98
|
|
|
|
88
|
|
|
|
94
|
|
|
|
20
|
|
|
|
23
|
|
Bangladesh
|
|
|
74
|
|
|
|
69
|
|
|
|
2
|
|
|
|
2
|
|
|
|
434
|
|
|
|
404
|
|
Kazakhstan
|
|
|
62
|
|
|
|
64
|
|
|
|
38
|
|
|
|
39
|
|
|
|
144
|
|
|
|
149
|
|
Azerbaijan
|
|
|
28
|
|
|
|
30
|
|
|
|
26
|
|
|
|
28
|
|
|
|
10
|
|
|
|
11
|
|
Philippines
|
|
|
25
|
|
|
|
25
|
|
|
|
4
|
|
|
|
4
|
|
|
|
126
|
|
|
|
124
|
|
China
|
|
|
22
|
|
|
|
20
|
|
|
|
20
|
|
|
|
18
|
|
|
|
10
|
|
|
|
13
|
|
Myanmar
|
|
|
14
|
|
|
|
13
|
|
|
|
|
|
|
|
|
|
|
|
86
|
|
|
|
81
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Asia
|
|
|
733
|
|
|
|
761
|
|
|
|
409
|
|
|
|
442
|
|
|
|
1,950
|
|
|
|
1,916
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Australia
|
|
|
101
|
|
|
|
111
|
|
|
|
26
|
|
|
|
34
|
|
|
|
448
|
|
|
|
458
|
|
Europe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United Kingdom
|
|
|
85
|
|
|
|
97
|
|
|
|
59
|
|
|
|
64
|
|
|
|
155
|
|
|
|
194
|
|
Denmark
|
|
|
44
|
|
|
|
51
|
|
|
|
29
|
|
|
|
32
|
|
|
|
91
|
|
|
|
116
|
|
Netherlands
|
|
|
7
|
|
|
|
8
|
|
|
|
2
|
|
|
|
2
|
|
|
|
31
|
|
|
|
35
|
|
Norway
|
|
|
3
|
|
|
|
3
|
|
|
|
3
|
|
|
|
3
|
|
|
|
1
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Europe
|
|
|
139
|
|
|
|
159
|
|
|
|
93
|
|
|
|
101
|
|
|
|
278
|
|
|
|
346
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Consolidated Operations
|
|
|
2,312
|
|
|
|
2,397
|
|
|
|
1,545
|
|
|
|
1,617
|
|
|
|
4,602
|
|
|
|
4,677
|
|
Equity
Affiliates3
|
|
|
361
|
|
|
|
366
|
|
|
|
304
|
|
|
|
306
|
|
|
|
339
|
|
|
|
363
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Including
Affiliates4
|
|
|
2,673
|
|
|
|
2,763
|
|
|
|
1,849
|
|
|
|
1,923
|
|
|
|
4,941
|
|
|
|
5,040
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 Includes
synthetic oil: Canada, net
|
|
|
40
|
|
|
|
24
|
|
|
|
40
|
|
|
|
24
|
|
|
|
|
|
|
|
|
|
Venezuelan
affiliate,
net 32
|
|
|
28
|
|
|
|
32
|
|
|
|
28
|
|
|
|
|
|
|
|
|
|
2 Located
between Saudi Arabia and Kuwait.
|
3 Volumes
represent Chevrons share of production by affiliates,
including Tengizchevroil in Kazakhstan and Petroboscan,
Petroindependiente and Petropiar in Venezuela.
|
4 Volumes
include natural gas consumed in operations of 582 million
and 537 million cubic feet per day in 2011 and 2010,
respectively. Total as sold natural gas volumes were
4,359 million and 4,503 million cubic feet per day for
2011 and 2010, respectively.
|
5
Average
Sales Prices and Production Costs per Unit of
Production
Refer to Table IV on
page FS-67
for the companys average sales price per barrel of crude
oil, condensate and natural gas liquids and per thousand cubic
feet of natural gas produced, and the average production cost
per oil-equivalent barrel for 2011, 2010 and 2009.
Gross and
Net Productive Wells
The following table summarizes gross and net productive wells at
year-end 2011 for the company and its affiliates:
Productive
Oil and Gas Wells at December 31, 2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
Productive
|
|
|
|
Oil Wells
|
|
|
Gas Wells
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
United States
|
|
|
49,511
|
|
|
|
32,368
|
|
|
|
14,061
|
|
|
|
7,671
|
|
Other Americas
|
|
|
709
|
|
|
|
533
|
|
|
|
40
|
|
|
|
17
|
|
Africa
|
|
|
2,548
|
|
|
|
850
|
|
|
|
17
|
|
|
|
7
|
|
Asia
|
|
|
12,612
|
|
|
|
10,861
|
|
|
|
3,437
|
|
|
|
2,125
|
|
Australia
|
|
|
807
|
|
|
|
453
|
|
|
|
64
|
|
|
|
11
|
|
Europe
|
|
|
332
|
|
|
|
105
|
|
|
|
222
|
|
|
|
48
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Consolidated Companies
|
|
|
66,519
|
|
|
|
45,170
|
|
|
|
17,841
|
|
|
|
9,879
|
|
Equity in Affiliates
|
|
|
1,231
|
|
|
|
434
|
|
|
|
7
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Including Affiliates
|
|
|
67,750
|
|
|
|
45,604
|
|
|
|
17,848
|
|
|
|
9,881
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Multiple completion wells included above:
|
|
|
887
|
|
|
|
573
|
|
|
|
378
|
|
|
|
280
|
|
Reserves
Refer to Table V beginning on
page FS-67
for a tabulation of the companys proved net crude oil and
natural gas reserves by geographic area, at the beginning of
2009 and each year-end from 2009 through 2011. Reserves
governance, technologies used in establishing proved reserves
additions, and major changes to proved reserves by geographic
area for the three-year period ended December 31, 2011, are
summarized in the discussion for Table V. Discussion is also
provided regarding the nature of, status of and planned future
activities associated with the development of proved undeveloped
reserves. The company recognizes reserves for projects with
various development periods, sometimes exceeding five years. The
external factors that impact the duration of a project include
scope and complexity, remoteness or adverse operating
conditions, infrastructure constraints, and contractual
limitations.
The net proved reserve balances at the end of each of the three
years 2009 through 2011 are shown in the following table.
Net
Proved Reserves at December 31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
Liquids Millions of barrels
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated Companies
|
|
|
4,295
|
|
|
|
4,270
|
|
|
|
4,610
|
|
Affiliated Companies
|
|
|
2,160
|
|
|
|
2,233
|
|
|
|
2,363
|
|
Natural Gas Billions of cubic feet
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated Companies
|
|
|
25,229
|
|
|
|
20,755
|
|
|
|
22,153
|
|
Affiliated Companies
|
|
|
3,454
|
|
|
|
3,496
|
|
|
|
3,896
|
|
Total Oil-Equivalent Millions of barrels
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated Companies
|
|
|
8,500
|
|
|
|
7,729
|
|
|
|
8,303
|
|
Affiliated Companies
|
|
|
2,736
|
|
|
|
2,816
|
|
|
|
3,012
|
|
6
Acreage
At December 31, 2011, the company owned or had under lease
or similar agreements undeveloped and developed crude oil and
natural gas properties throughout the world. The geographical
distribution of the companys acreage is shown in the
following table.
Acreage
at December 31, 2011
(Thousands of Acres)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed and
|
|
|
|
Undeveloped*
|
|
|
Developed
|
|
|
Undeveloped
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
United States
|
|
|
6,290
|
|
|
|
5,171
|
|
|
|
7,752
|
|
|
|
5,051
|
|
|
|
14,042
|
|
|
|
10,222
|
|
Other Americas
|
|
|
26,803
|
|
|
|
15,338
|
|
|
|
1,392
|
|
|
|
395
|
|
|
|
28,195
|
|
|
|
15,733
|
|
Africa
|
|
|
8,068
|
|
|
|
3,921
|
|
|
|
3,324
|
|
|
|
1,370
|
|
|
|
11,392
|
|
|
|
5,291
|
|
Asia
|
|
|
41,125
|
|
|
|
21,613
|
|
|
|
5,426
|
|
|
|
2,760
|
|
|
|
46,551
|
|
|
|
24,373
|
|
Australia
|
|
|
12,801
|
|
|
|
6,064
|
|
|
|
920
|
|
|
|
240
|
|
|
|
13,721
|
|
|
|
6,304
|
|
Europe
|
|
|
5,093
|
|
|
|
3,608
|
|
|
|
645
|
|
|
|
137
|
|
|
|
5,738
|
|
|
|
3,745
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Consolidated Companies
|
|
|
100,180
|
|
|
|
55,715
|
|
|
|
19,459
|
|
|
|
9,953
|
|
|
|
119,639
|
|
|
|
65,668
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in Affiliates
|
|
|
419
|
|
|
|
191
|
|
|
|
252
|
|
|
|
100
|
|
|
|
671
|
|
|
|
291
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Including Affiliates
|
|
|
110,599
|
|
|
|
55,906
|
|
|
|
19,711
|
|
|
|
10,053
|
|
|
|
120,310
|
|
|
|
65,959
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
|
The gross undeveloped acres that will expire in 2012, 2013 and
2014 if production is not established by certain required dates
are 4,675, 5,993 and 2,903, respectively.
|
Delivery
Commitments
The company sells crude oil and natural gas from its producing
operations under a variety of contractual obligations. Most
contracts generally commit the company to sell quantities based
on production from specified properties, but some natural gas
sales contracts specify delivery of fixed and determinable
quantities, as discussed below.
In the United States, the company is contractually committed to
deliver to third parties 232 billion cubic feet of natural
gas through 2014. The company believes it can satisfy these
contracts through a combination of equity production from the
companys proved developed U.S. reserves and
third-party purchases. These contracts include a variety of
pricing terms, including both indexed and fixed-price contracts.
Outside the United States, the company is contractually
committed to deliver a total of 891 billion cubic feet of
natural gas from 2012 through 2014 from operations in Australia,
Colombia, Denmark and the Philippines to third parties. The
sales contracts contain variable pricing formulas that are
generally referenced to the prevailing market price for crude
oil, natural gas or other petroleum products at the time of
delivery. The company believes it can satisfy these contracts
from quantities available from production of the companys
proved developed reserves in these countries.
Development
Activities
Refer to Table I on
page FS-62
for details associated with the companys development
expenditures and costs of proved property acquisitions for 2011,
2010 and 2009.
The table on the next page summarizes the companys net
interest in productive and dry development wells completed in
each of the past three years and the status of the
companys development wells drilling at December 31,
2011. A development well is a well drilled within
the proved area of a crude oil or natural gas reservoir to the
depth of a stratigraphic horizon known to be productive.
7
Development
Well Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wells Drilling
|
|
|
Net Wells Completed
|
|
|
|
at 12/31/11
|
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
|
Gross
|
|
|
Net
|
|
|
Prod.
|
|
|
Dry
|
|
|
Prod.
|
|
|
Dry
|
|
|
Prod.
|
|
|
Dry
|
|
|
United States
|
|
|
105
|
|
|
|
62
|
|
|
|
909
|
|
|
|
9
|
|
|
|
634
|
|
|
|
7
|
|
|
|
582
|
|
|
|
3
|
|
Other Americas
|
|
|
8
|
|
|
|
4
|
|
|
|
37
|
|
|
|
|
|
|
|
32
|
|
|
|
|
|
|
|
36
|
|
|
|
|
|
Africa
|
|
|
7
|
|
|
|
3
|
|
|
|
29
|
|
|
|
|
|
|
|
33
|
|
|
|
|
|
|
|
40
|
|
|
|
|
|
Asia
|
|
|
85
|
|
|
|
37
|
|
|
|
549
|
|
|
|
15
|
|
|
|
445
|
|
|
|
15
|
|
|
|
580
|
|
|
|
10
|
|
Australia
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Europe
|
|
|
5
|
|
|
|
|
|
|
|
6
|
|
|
|
|
|
|
|
4
|
|
|
|
|
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Consolidated Companies
|
|
|
211
|
|
|
|
106
|
|
|
|
1,530
|
|
|
|
24
|
|
|
|
1,148
|
|
|
|
22
|
|
|
|
1,245
|
|
|
|
13
|
|
Equity in Affiliates
|
|
|
1
|
|
|
|
1
|
|
|
|
25
|
|
|
|
|
|
|
|
8
|
|
|
|
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Including Affiliates
|
|
|
212
|
|
|
|
107
|
|
|
|
1,555
|
|
|
|
24
|
|
|
|
1,156
|
|
|
|
22
|
|
|
|
1,251
|
|
|
|
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration
Activities
The following table summarizes the companys net interests
in productive and dry exploratory wells completed in each of the
last three years and the number of exploratory wells drilling at
December 31, 2011. Exploratory wells are wells
drilled to find and produce crude oil or natural gas in unproved
areas and include delineation wells, which are wells drilled to
find a new reservoir in a field previously found to be
productive of crude oil or natural gas in another reservoir or
to extend a known reservoir beyond the proved area.
Exploratory
Well Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wells Drilling
|
|
|
Net Wells Completed
|
|
|
|
at 12/31/11
|
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
|
Gross
|
|
|
Net
|
|
|
Prod.
|
|
|
Dry
|
|
|
Prod.
|
|
|
Dry
|
|
|
Prod.
|
|
|
Dry
|
|
|
United States
|
|
|
2
|
|
|
|
2
|
|
|
|
5
|
|
|
|
1
|
|
|
|
1
|
|
|
|
1
|
|
|
|
4
|
|
|
|
5
|
|
Other Americas
|
|
|
2
|
|
|
|
1
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
1
|
|
|
|
2
|
|
Africa
|
|
|
3
|
|
|
|
1
|
|
|
|
1
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
2
|
|
|
|
1
|
|
Asia
|
|
|
1
|
|
|
|
1
|
|
|
|
10
|
|
|
|
1
|
|
|
|
5
|
|
|
|
5
|
|
|
|
9
|
|
|
|
1
|
|
Australia
|
|
|
1
|
|
|
|
1
|
|
|
|
4
|
|
|
|
1
|
|
|
|
5
|
|
|
|
2
|
|
|
|
4
|
|
|
|
2
|
|
Europe
|
|
|
2
|
|
|
|
1
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Consolidated Companies
|
|
|
11
|
|
|
|
7
|
|
|
|
21
|
|
|
|
4
|
|
|
|
12
|
|
|
|
9
|
|
|
|
20
|
|
|
|
11
|
|
Equity in Affiliates
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Including Affiliates
|
|
|
11
|
|
|
|
7
|
|
|
|
22
|
|
|
|
4
|
|
|
|
12
|
|
|
|
9
|
|
|
|
20
|
|
|
|
11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refer to Table I on
page FS-62
for detail of the companys exploration expenditures and
costs of unproved property acquisitions for 2011, 2010 and 2009.
Review of
Ongoing Exploration and Production Activities in Key
Areas
Chevrons 2011 key upstream activities, some of which are
also discussed in Managements Discussion and Analysis of
Financial Condition and Results of Operations, beginning on
page FS-2,
are presented below. The comments include references to
total production and net production,
which are defined under Production in
Exhibit 99.1
on page E-11.
8
The discussion that follows references the status of proved
reserves recognition for significant long-lead-time projects not
on production and for projects recently placed on production.
Reserves are not discussed for exploration activities or recent
discoveries that have not advanced to a project stage or for
mature areas of production that do not have individual projects
requiring significant levels of capital or exploratory
investment. Amounts indicated for project costs represent total
project costs, not the companys share of costs for
projects that are less than wholly owned.
|
|
|
|
|
|
|
|
|
Chevron has exploration and production 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 exploration and production.
|
Upstream activities in the United States are concentrated in
California, the Gulf of Mexico, the Appalachian Basin, Colorado,
Michigan, New Mexico, Ohio, Oklahoma, Texas, Wyoming and Alaska.
Average net oil-equivalent production in the United States
during 2011 was 678,000 barrels per day.
In California, the company has significant production in the
San Joaquin Valley. In 2011, average net oil-equivalent
production was 183,000 barrels per day, composed of
165,000 barrels of crude oil, 83 million cubic feet of
natural gas and 4,000 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).
|
|
|
|
|
|
|
|
|
Average net oil-equivalent production during 2011 for the companys combined interests in the Gulf of Mexico shelf and deepwater areas, and the onshore fields in the region was 244,000 barrels per day. The daily oil-equivalent production was composed of 161,000 barrels of crude oil, 401 million cubic feet of natural gas and 16,000 barrels of natural gas liquids.
Chevron was engaged in various exploration and development activities in the deepwater Gulf of Mexico during 2011. The Jack and St. Malo fields are located within 25 miles of each other and are being jointly developed. Chevron has a 50 percent working interest in Jack and a 51 percent working interest in St. Malo. Both fields are company operated. All major installation contracts have been awarded and construction began for
|
the floating production unit hull and topsides modules during
2011. Development drilling operations commenced in fourth
quarter 2011. The facility is planned to have a design capacity
of 177,000 barrels of oil-equivalent per day to accommodate
production from the Jack/St. Malo development, which is
estimated to have maximum total daily production of
94,000 barrels of oil equivalent, plus production from a
nearby third-party field. Total project costs for the initial
phase of development are estimated at $7.5 billion and
start-up is
expected in 2014. The project has an estimated production life
of 30 years. The initial recognition of proved reserves for
the project occurred in 2011.
9
Work continued at the 60 percent-owned and operated Big
Foot discovery. The development plan includes a 15-slot drilling
and production tension leg platform with water injection
facilities and a design capacity of 79,000 barrels of oil
equivalent per day. Fabrication of topsides, hull and other
components began in first-half 2011 and initial development
drilling commenced in fourth quarter 2011. First production is
anticipated in 2014. The field has an estimated production life
of 20 years. Initial proved reserves were recognized in
2011.
Tahiti 2 is the second development phase for the
58 percent-owned and operated Tahiti Field and is designed
to increase recovery and return well capacity to
125,000 barrels of oil per day. The project includes three
water injection wells, two additional production wells and the
water injection facilities required to deliver water to the
injection wells. Two water injection wells have been completed
and drilling commenced on the first production well in early
2012. The water injection facilities have been installed and
water injection began in first quarter 2012.
Start-up of
the first production well of the second phase is expected by
2013. Initial proved reserves for the Tahiti 2 project were
recognized in 2011, and the field has an estimated production
life of 30 years.
The final investment decision was made for the Tubular Bells
deepwater project in fourth quarter 2011. The company has a
42.9 percent nonoperated working interest in the Tubular
Bells unitized area after receiving an additional
12.9 percent equity interest relinquished by a partner in
2011. Development drilling is scheduled to begin in second
quarter 2012, and plans include three producing and two
injection wells, with a subsea tieback to a third-party
production facility. First oil is anticipated in 2014, and
maximum total daily production is expected to reach 40,000 to
45,000 barrels of oil-equivalent. At the end of 2011,
proved reserves had not been recognized for this project.
The company has a 20.3 percent nonoperated working interest
in the Caesar and Tonga unitized area. Development plans include
a total of four wells and a subsea tieback to a nearby
third-party production facility. Three of the four development
wells have been drilled and completed as of year-end 2011.
Drilling of the fourth well is expected to begin in mid-2012.
Work on the subsea system, commissioning of the topsides and the
initial well completion program continued into 2012.
Installation of the production riser and first production are
expected in mid-2012. Maximum total production is expected to be
46,000 barrels of oil-equivalent per day. Proved reserves
have been recognized for the project.
The company has a 15.6 percent nonoperated working interest
in the Mad Dog II Project. Front-end engineering and design
(FEED) is expected to commence by second quarter 2012. It is
anticipated that this future development would require new
production facilities to support planned maximum total daily
production of 120,000 to 140,000 barrels of oil equivalent.
At the end of 2011, proved reserves had not been recognized for
this project.
Development planning and unitization talks with owners of an
adjacent field continued in 2011 for the Knotty Head project.
Chevron has a 25 percent nonoperated working interest in
this subsalt, Green Canyon Block 512 discovery. At the end
of 2011, proved reserves had not been recognized for this
project.
Deepwater exploration activities in 2011 included participation
in four exploratory wells two wildcats, one
appraisal and one delineation. Following successful permitting
under new, more stringent, U.S. Department of Interior
guidelines, two wells resumed drilling activities after
operations were halted in 2010 as a result of the deepwater
drilling moratorium in the Gulf of Mexico. Drilling operations
at the 43.8 percent-owned and operated Moccasin prospect
resumed in first quarter 2011 and resulted in a new discovery in
the Lower Tertiary Wilcox Trend. Drilling operations resumed in
second quarter 2011 at the 55 percent-owned and operated
Buckskin prospect, resulting in a successful appraisal well.
These two discoveries, located 12 miles apart, could
facilitate future co-development upon the successful completion
of additional appraisal drilling planned at each prospect in
2012. Drilling was terminated at the Coronado wildcat well due
to drilling conditions in the shallow section of the wellbore.
The company plans to drill a replacement well at an alternate
location by mid-2012.
Besides the activities connected with the development and
exploration projects in the Gulf of Mexico, the company also has
contracted capacity at the third-party Sabine Pass liquefied
natural gas (LNG) regasification terminal in Louisiana and in a
third-party pipeline system connecting the Sabine Pass LNG
terminal to the natural gas pipeline grid. The pipeline provides
access to two major salt dome storage fields and 10 major
interstate pipeline systems, including access to Chevrons
Sabine Pipeline, which connects to the Henry Hub. The Henry Hub
interconnects to nine interstate and four intrastate pipelines
and is the pricing point for natural gas futures contracts
traded on the New York Mercantile Exchange.
10
|
|
|
|
|
|
|
|
|
Company activities outside California and the Gulf of Mexico include operated and nonoperated interests in properties across the mid-continental United States, the Appalachian Basin, Michigan, Ohio and Alaska. During 2011, the companys U.S. production outside California and the Gulf of Mexico averaged 251,000 net oil-equivalent barrels per day, composed of 91,000 barrels of crude oil, 795 million cubic feet of natural gas and 28,000 barrels of natural gas liquids.
In West Texas, the company continues to pursue development of tight carbonates, tight sands, and liquids-rich shale resources in the Midland Basins Wolfcamp play and several plays in the Delaware Basin through use of advanced drilling and completion technologies. Additional production growth is expected from interests in these formations in
|
future years.
In February 2011, Chevron acquired Atlas Energy, Inc. The
acquisition provided a natural gas resource position in the
Marcellus Shale and Utica Shale, primarily located in
southwestern Pennsylvania and Ohio. The acquisition also
provided a 49 percent interest in Laurel Mountain
Midstream, LLC, an affiliate that owns more than
1,000 miles of natural gas gathering lines servicing the
Marcellus. In addition, the acquisition provided assets in
Michigan, which include Antrim Shale producing assets and
approximately 350,000 total acres in the Antrim and
Collingwood/Utica Shale formations. Additional asset
acquisitions in 2011 expanded the companys holdings in the
Marcellus and Utica to approximately 700,000 and 600,000 total
acres, respectively. In the Marcellus, 61 natural gas wells were
completed in 2011.
Other Americas is composed of Argentina, Brazil,
Canada, Colombia, Greenland, Trinidad and Tobago, and Venezuela.
Net oil-equivalent production from these countries averaged
267,000 barrels per day during 2011, including the
companys share of synthetic oil production.
|
|
|
|
|
|
|
|
|
Canada: Company activities in Canada include nonoperated working interests of 26.9 percent in the Hibernia Field, 26.6 percent in the Hebron Field and 23.6 percent in the unitized Hibernia South Extension, all offshore eastern Canada. In Alberta, the company holds a 20 percent nonoperated working interest in the Athabasca Oil Sands Project (AOSP). Average net oil-equivalent production during 2011 was 70,000 barrels per day, composed of 69,000 barrels of crude oil, synthetic oil and natural gas liquids and 4 million cubic feet of natural gas.
Development of the Hibernia Southern Extension is expected to stem the production decline from the Hibernia Field. The project includes drilling of producing wells from the existing Hibernia platform and subsea drilling of water injection wells. All project approvals were in place by early 2011 and two producing wells were successfully drilled
|
from the platform to obtain early reservoir information.
Further drilling is anticipated to commence in 2013 with full
production
start-up
expected in 2014. The initial recognition of proved reserves
occurred in 2011 for this project.
FEED activities continued in 2011 for the development of the
heavy-oil Hebron Field and a final investment decision is
expected in 2013. The project has an expected economic life of
30 years. At the end of 2011, proved reserves had not been
recognized for this project.
11
At AOSP, oil sands are mined from both the Muskeg River and
Jackpine mines and bitumen is extracted from the oil sands and
upgraded into synthetic oil. The AOSP Expansion 1 Project
activities continued in 2011 with completion of the Scotford
Upgrader expansion, which increased daily production design
capacity to approximately 255,000 barrels per day.
During 2011, the company increased its shale exploration acreage
in Alberta in the Duvernay formation. In third quarter 2011, a
multiwell drilling program commenced on these
100 percent-owned and operated leases. A long-term well
test is expected to begin in fourth quarter 2012, when the first
well is expected to be tied into third-party processing
facilities. The company also holds exploration licenses and
leases in the Flemish Pass and Orphan basins offshore Atlantic
Canada, the Mackenzie Delta region of the Northwest Territories
and the Beaufort Sea region of Canadas Arctic, including a
35.4 percent nonoperated working interest in the offshore
Amauligak discovery.
In addition, Chevron holds interests in the Aitken Creek and
Alberta Hub natural gas storage facilities with an approximate
total capacity of 100 billion cubic feet. These facilities
are located adjacent to the Duvernay, Horn River and Montney
shale gas plays.
Greenland: In 2011, the Greenland government granted a
one-year extension to the initial four-year term for License
2007/26, which includes Block 4 offshore West Greenland.
Interpretation of seismic data continued into early 2012.
Chevron has a 29.2 percent nonoperated working interest in
this exploration license.
|
|
|
|
|
|
|
|
|
Argentina: Chevron holds operated interests in four concessions in the Neuquen Basin. Working interests range from 18.8 percent to 100 percent. Net oil-equivalent production in 2011 averaged 27,000 barrels per day, composed of 26,000 barrels of crude oil and natural gas liquids and 4 million cubic feet of natural gas. During 2011, the company reached an agreement to extend the El Trapial concession for an additional 10 years until 2032. The company expects to drill two exploratory wells in 2012 in the Vaca Muerta formation, targeting shale gas and tight oil resources.
Brazil: Chevron holds working interests in three deepwater fields in the Campos Basin. Net oil-equivalent production in 2011 averaged 35,000 barrels per day, composed of 33,000 barrels of crude oil and 13 million cubic feet of
|
natural gas.
During 2011, development drilling continued at the
51.7 percent-owned and operated Frade Field, located in the
Campos Basin. Eleven development wells and four injection wells
had been completed as of year-end 2011. Development drilling is
planned to continue through 2013, with one additional
development well, one sidetrack well and several injection
wells. The concession that includes the Frade project expires in
2025.
In the partner-operated Campos Basin Block BC-20, two
areas 37.5 percent-owned Papa-Terra and
30 percent-owned Maromba were retained for
development following the end of the exploration phase of this
block. During 2011, construction progressed on a floating
production, storage and offloading (FPSO) vessel and tension leg
well platform for the Papa-Terra project. Development drilling
was initiated in fourth quarter 2011. The facility has a planned
total daily capacity of 140,000 barrels of crude oil. First
production is expected in 2013, and the initial recognition of
proved reserves occurred during 2011. Evaluation of the field
development concept for Maromba continued into early 2012. At
the end of 2011, proved reserves had not been recognized for
this project. These concessions expire in 2032.
Colombia: The company operates the offshore Chuchupa and
the onshore Ballena and Riohacha natural gas fields as part of
the Guajira Association contract. In exchange, Chevron receives
43 percent of the production for the remaining life of each
field and a variable production volume based on prior Chuchupa
capital contributions. During 2011, a gas export agreement with
Venezuela was extended. An onshore, multiwell drilling program
commenced in late 2011. Daily net production averaged
234 million cubic feet of natural gas in 2011.
Trinidad and Tobago: Company interests include
50 percent ownership in three partner-operated blocks in
the East Coast Marine Area offshore Trinidad, which includes the
Dolphin and Dolphin Deep producing natural gas fields and the
Starfish discovery. Net production in 2011 averaged
183 million cubic feet of natural gas per day. Chevron also
holds a
12
50 percent operated interest in the Manatee Area of
Block 6(d), which includes a 2005 discovery. During 2011,
work progressed to mature a development concept called the
Regional Cooperative Agreement.
|
|
|
|
|
|
|
|
|
Venezuela: Chevron holds interests in two producing
affiliates located in western Venezuela and one producing
affiliate in the Orinoco Belt. Chevron has a 30 percent
interest in the Petropiar affiliate that operates the Hamaca
heavy-oil production and upgrading project located in
Venezuelas Orinoco Belt, a 39.2 percent interest in
the Petroboscan affiliate that operates the Boscan Field in the
western part of the country, and a 25.2 percent interest in
the Petroindependiente affiliate that operates the LL-652 Field
in Lake Maracaibo. The companys share of net
oil-equivalent production during 2011 from these operations,
including synthetic oil from Hamaca, averaged
|
65,000 barrels per day, composed of 60,000 barrels of
crude oil, synthetic oil and natural gas liquids and
27 million cubic feet of natural gas.
Chevron holds a 34 percent interest in the
Petroindependencia affiliate that is working on a heavy-oil
project in three blocks within the Carabobo Area of eastern
Venezuelas Orinoco Belt. During 2011, work continued
toward commercialization of the Carabobo 3 Project. Conceptual
engineering for the potential development of the concession is
in progress.
The company operates and has a working interest of
60 percent in Block 2 in the Plataforma Deltana area
offshore eastern Venezuela. During 2011, work progressed to
mature a development concept called the Regional Cooperative
Agreement.
In Africa, the company is engaged in exploration and production
activities in Angola, Chad, Democratic Republic of the Congo,
Liberia, Nigeria and Republic of the Congo. Net oil-equivalent
production in Africa averaged 459,000 barrels per day
during 2011.
|
|
|
|
|
|
|
|
|
Angola: Chevron holds company-operated working interests in offshore Blocks 0 and 14 and nonoperated working interests in offshore Block 2 and the onshore Fina Sonangol Texaco area. Net production from these operations in 2011 averaged 147,000 barrels of oil-equivalent per day.
The company operates the 39.2 percent-owned Block 0, which averaged 108,000 barrels per day of net liquids production in 2011. The Block 0 concession extends through 2030.
Work on the second development stage of the Mafumeira Field in Block 0 continued in 2011. Mafumeira Sul, a project to develop the southern portion of the field, is expected to reach a final investment decision in second quarter 2012. Maximum total production from Mafumeira Sul is expected to be 110,000 barrels of crude oil and 10,000 barrels of LPG per day. At year-end 2011, proved reserves had not been recognized for the Mafumeira Sul project.
In the Greater Vanza/Longui Area of Block 0, development concept studies continued during 2011 and the project is expected to enter FEED in second-half 2012. FEED activities continued on the south extension
|
13
of the NDola Field development with a final investment
decision expected in late 2012. At year-end 2011, no proved
reserves were recognized for these projects.
In Block 0, the Area A gas management projects at the
Takula and Malongo reservoirs were designed to eliminate routine
flaring of natural gas. The final project entered service in
2011, which together have reduced flaring by approximately
70 million cubic feet per day, as of year-end 2011. In Area
B, the first stage of the Nemba Enhanced Secondary Recovery and
Flare Reduction Project was completed in second quarter 2011.
The final stage is expected to eliminate routine flaring at the
North and South Nemba platforms and is scheduled to begin gas
injection in 2014.
Also in Block 0, a two-well appraisal and exploration
program was completed in 2011. The appraisal well completed in
July 2011 in the Lifua Field was successful and development
opportunities are being evaluated. The second well, completed in
October 2011 in the pre-salt play, was not successful. Two
additional exploratory wells are planned for second-half 2012.
In the 31 percent-owned Block 14, net production in
2011 averaged 29,000 barrels of liquids per day.
Development and production rights for the various producing
fields in Block 14 expire between 2023 and 2028.
For the Lucapa Field in Block 14, development alternatives
continued to be evaluated during 2011. The project is expected
to enter FEED in second quarter 2012. Development alternatives
were evaluated during the year at the Malange Field and the
preferred alternative is expected to enter FEED in mid-2012. As
of the end of 2011, development of the Negage Field remained
suspended until cooperative arrangements between Angola and
Democratic Republic of the Congo are finalized. At the end of
2011, proved reserves had not been recognized for these projects.
In addition to the exploration and production activities in
Angola, Chevron has a 36.4 percent ownership interest in
the Angola LNG affiliate that began construction in 2008 of an
onshore natural gas liquefaction plant at Soyo, Angola. The
plant is designed to process 1.1 billion cubic feet of
natural gas per day, with expected average total daily sales of
670 million cubic feet of regasified LNG and up to
63,000 barrels of natural gas liquids. Construction
continued during 2011, reaching mechanical completion at
year-end. The first LNG shipment from the plant is expected in
second quarter 2012. The estimated total cost of the LNG plant
is $10 billion, with an estimated life in excess of
20 years. The company also holds a 38.1 percent
interest in a pipeline project that is expected to transport up
to 250 million cubic feet of natural gas per day from
Block 0 and Block 14 to the Angola LNG plant. The
pipeline project entered construction in May 2011 and is
expected to be completed in late 2013. Proved reserves have been
recognized for the producing operations associated with the
Angola LNG project.
Angola Republic of the Congo Joint Development
Area: Chevron operates and holds a 31.3 percent
interest in the Lianzi Development Area located between Angola
and Republic of the Congo. A final investment decision for the
Lianzi development project is expected in mid-2012. The project
is expected to commence production in late 2014. At the end of
2011, proved reserves had not been recognized for the project.
Democratic Republic of the Congo: Chevron has a
17.7 percent nonoperated working interest in an offshore
concession. Daily net production in 2011 averaged
3,000 barrels of oil-equivalent.
Republic of the Congo: Chevron has a
31.5 percent nonoperated working interest in the Nkossa,
Nsoko and
Moho-Bilondo
permit areas and a 29.3 percent nonoperated working
interest in the Kitina permit area, all of which are offshore.
The development and production rights for Kitina, Nsoko, Nkossa
and Moho-Bilondo expire in 2014, 2018, 2027 and 2030,
respectively. Net production averaged 23,000 barrels of
oil-equivalent per day in 2011.
The Moho Nord Project, located in the Moho-Bilondo Development
Area, entered FEED in fourth quarter 2011. The project is
expected to reach a final investment decision in 2013. At the
end of 2011, proved reserves had not been recognized for this
project.
Chad/Cameroon: Chevron has a 25 percent
nonoperated working interest in crude oil producing operations
in southern Chad and an approximate 21 percent interest in
two affiliates that own an export pipeline that transports the
crude oil to the coast of Cameroon. Average daily net production
from the Chad fields in 2011 was 26,000 barrels of
oil-equivalent. The Chad producing operations are conducted
under a concession that expires in 2030.
14
|
|
|
|
|
|
|
|
|
Nigeria: Chevron holds a 40 percent interest in 13 concessions predominantly in the onshore and near-offshore region of the Niger Delta. The company operates under a joint-venture arrangement in this region with the Nigerian National Petroleum Corporation, which owns a 60 percent interest. The company also owns varying interests in four operated and six nonoperated deepwater blocks. In 2011, the companys net oil-equivalent production in Nigeria averaged 260,000 barrels per day, composed of 236,000 barrels of liquids and 142 million cubic feet of natural gas.
Chevron operates and holds a 67.3 percent interest in the Agbami Field, located in deepwater Oil Mining Lease (OML) 127 and OML 128. During 2011, drilling continued on a 10-well, Phase 2 development program that is designed to offset field decline and maintain plateau production. The first well is expected to be
|
completed and placed on production in second-half 2012. The
leases that contain the Agbami Field expire in 2023 and 2024.
The company holds a 30 percent nonoperated working interest
in the deepwater Usan project in OML 138. During 2011,
development drilling continued and the FPSO vessel was moored on
location. Production
start-up is
expected in early 2012, with maximum total production of
180,000 barrels of crude oil per day expected within one
year of
start-up.
The production-sharing contract (PSC) expires in 2023. Proved
reserves have been recognized for this project.
Also in the deepwater area, the Aparo Field in OML 132 and OML
140 and the third-party-owned Bonga SW Field in OML
118 share a common geologic structure and are planned to be
jointly developed. Initiation of FEED is expected in late 2012.
At the end of 2011, no proved reserves were recognized for this
project.
In the Niger Delta,
ramp-up
activity continued at the Escravos Gas Plant (EGP). During 2011,
construction continued on Phase 3B of the EGP project, which is
designed to gather 120 million cubic feet of natural gas
per day from eight offshore fields and to compress and transport
the natural gas to onshore facilities. The Phase 3B project is
expected to be completed in 2016. Proved reserves associated
with this project have been recognized.
The 40 percent-owned and operated Sonam Field Development
includes facilities to produce natural gas from the Sonam
natural gas field in the Escravos area. The project is designed
to utilize EGP and to deliver 215 million cubic feet of
natural gas per day to the domestic market, and produce an
average of 30,000 barrels of liquids per day. A final
investment decision was reached in late 2011, and first
production is expected in 2016. Proved reserves associated with
the project were recognized in 2011.
Chevron has a 75 percent-owned and operated interest in a
gas-to-liquids
facility at Escravos that is being developed with the Nigerian
National Petroleum Corporation. The 33,000-barrel-per-day
facility is designed to process 325 million cubic feet per
day of natural gas supplied from the Phase 3A expansion of EGP.
At the end of 2011, work on the project was more than
80 percent complete and
start-up is
planned for 2013. The estimated cost of the plant is
$8.4 billion.
The company has a 40 percent-owned and operated interest in
the Onshore Asset Gas Management project that is designed to
restore approximately 125 million cubic feet per day of
natural gas production from certain onshore fields that have
been shut in since 2003 due to civil unrest. Construction
activities continued through 2011, and
start-up is
scheduled for late 2012.
In deepwater exploration, the company has 20 percent and
27 percent nonoperated working interests in Oil Prospecting
License (OPL) 214 and OPL 223, respectively. Drilling of two
exploration wells commenced in fourth quarter 2011 in OPL 214,
and one exploration well is planned in OPL 223 for second-half
2012. In addition, Chevron operates and holds a 95 percent
interest in the deepwater Nsiko discovery in OML 140 where
further exploration activities are planned.
15
Shallow-water exploration activities in 2011 included
reprocessing
3-D seismic
data from OML 86 and OML 88. In November 2011, the company began
drilling a well in OML 86. In January 2012, while drilling the
well, there was a release of natural gas that led to a fire.
Drilling of a relief well commenced in February 2012. A root
cause investigation is under way.
Chevron is the largest shareholder, with a 37 percent
interest, in the West African Gas Pipeline Company Limited
affiliate, which constructed, owns and operates the
421-mile
West African Gas Pipeline. The pipeline supplies Nigerian
natural gas to customers in Benin, Ghana and Togo for industrial
applications and power generation and has the capacity to
transport 170 million cubic feet per day.
Liberia: In 2010, Chevron acquired a 70 percent
interest and operatorship in three deepwater blocks off the
coast of Liberia. Exploration drilling prospects were identified
during 2011 based on
3-D seismic
data. Two exploration wells are planned to be drilled in 2012.
In Asia, the company is engaged in upstream activities in
Azerbaijan, Bangladesh, Cambodia, China, Indonesia, Kazakhstan,
Myanmar, the Partitioned Zone located between Saudi Arabia and
Kuwait, the Philippines, Russia, Thailand, Turkey, and Vietnam.
During 2011, net oil-equivalent production averaged
1,029,000 barrels per day.
|
|
|
|
|
|
|
|
|
Azerbaijan: Chevron holds an 11.3 percent nonoperated working interest in the Azerbaijan International Operating Company (AIOC), which produces crude oil in the Caspian Sea from the Azeri-Chirag-Gunashli (ACG) project. The companys daily net production from AIOC averaged 28,000 barrels of oil-equivalent in 2011. AIOC operations are conducted under a PSC that expires in 2024.
During 2011, construction progressed on the next development phase of the ACG project, which will further develop the deepwater Gunashli Field. Production is expected to begin in 2013. Proved reserves have been recognized for this project. The total estimated cost of the project is $6 billion, with maximum total daily production of 140,000 barrels of oil-equivalent.
Chevron also has an 8.9 percent interest in the Baku-Tbilisi-Ceyhan (BTC) affiliate, which owns and operates a crude oil export pipeline from Baku, Azerbaijan, through Georgia to Mediterranean deepwater port facilities at Ceyhan, Turkey. The BTC Pipeline has a capacity of 1.2 million barrels per day and transports the majority of ACG production. Another production export route for crude oil is the Western Route Export Pipeline,
|
wholly owned by AIOC, with capacity to transport
100,000 barrels per day from Baku, Azerbaijan, to a marine
terminal at Supsa, Georgia.
Kazakhstan: Chevron participates in two major
upstream developments in western Kazakhstan. The company holds a
50 percent interest in the Tengizchevroil (TCO) affiliate,
which is operating and developing the Tengiz and Korolev crude
oil fields under a concession that expires in 2033.
Chevrons net oil-equivalent production in 2011 from these
fields averaged 296,000 barrels per day, composed of
244,000 barrels of crude oil and natural gas liquids and
312 million cubic feet of natural gas. During 2011, the
majority of TCOs crude oil production was exported through
the Caspian Pipeline Consortium (CPC) pipeline that runs from
Tengiz in Kazakhstan to tanker-loading facilities at
Novorossiysk on the Russian coast of the Black Sea. The balance
was exported via rail to Black Sea ports.
Also during 2011, TCO continued to evaluate alternatives for
another expansion project to increase total daily crude oil
production between 250,000 and 300,000 barrels. The
expansion project will rely on sour gas injection technology
utilized in current operations. Approval of FEED is anticipated
in 2012. As of year-end 2011, proved reserves had not been
recognized for this expansion project.
16
Chevron holds a 20 percent nonoperated working interest in
the Karachaganak project, which is conducted under a
PSC that expires in 2038. During 2011, Karachaganak net
oil-equivalent production averaged 62,000 barrels per day,
composed of 38,000 barrels of liquids and 144 million
cubic feet of natural gas. In 2011, access to the CPC and
Atyrau-Samara
(Russia) pipelines enabled approximately 204,000 barrels
per day (34,000 net barrels) of Karachaganak liquids to be
sold at world-market prices. The remaining liquids were sold
into local and Russian markets. During 2011, a fourth train
entered production and increased total liquids-stabilization
capacity by 56,000 barrels per day, allowing increased
sales of condensate into world markets. Karachaganak project
partners have reached an agreement allowing the government of
Kazakhstan to become a 10 percent equity owner in the
Karachaganak project. The transfer of equity to the government
is anticipated to occur in June 2012 and will result in
Chevrons working interest being reduced to 18 percent.
During 2011, Chevron and its partners continued to evaluate
alternatives for a Phase III development of Karachaganak.
The timing of the project remains uncertain until a project
design is finalized. At the end of 2011, proved reserves had not
been recognized for the project.
Kazakhstan/Russia: Chevron has a 15 percent
interest in the CPC affiliate. During 2011, CPC transported an
average of approximately 684,000 barrels of crude oil per
day, including 608,000 barrels per day from Kazakhstan and
76,000 barrels per day from Russia. During 2011, the
partners began construction on a project to increase pipeline
capacity by 670,000 barrels per day. The total estimated
cost of the project is $5.4 billion. The project is
expected to be implemented in three phases, with capacity
increasing progressively until reaching maximum capacity of
1.4 million barrels per day in 2016.
Turkey: In 2010, Chevron signed a Joint Operating
Agreement for a 50 percent working interest in a
5.6 million acre exploration block located in the Black
Sea. The initial exploration well completed in 2010 was
unsuccessful. Future plans are under evaluation.
Bangladesh: Chevron holds a 98 percent interest
in two operated PSCs covering Blocks 12, 13 and 14. Net
oil-equivalent production from these operations in 2011 averaged
74,000 barrels per day, composed of 434 million cubic
feet of natural gas and 2,000 barrels of liquids. In 2011,
the Muchai compression project achieved mechanical completion
and is expected to support additional production starting in
second quarter 2012 from the Bibiyana, Jalalabad and Moulavi
Bazar natural gas fields. Proved reserves have been recognized
for this project. The Bibiyana Expansion Project entered FEED in
July 2011. Project scope includes expansion of the gas plant,
additional development drilling and an enhanced liquids recovery
unit, with an estimated total maximum daily production of
57,000 barrels of oil equivalent. A final investment
decision is expected in mid-2012. At the end of 2011, proved
reserves had not been recognized for this project. Also in 2011,
the company relinquished its interest in Block 7 subsequent
to the completion of an unsuccessful exploratory well.
|
|
|
|
|
|
|
|
|
Cambodia: Chevron owns a 30 percent interest and operates the 1.2 million-acre Block A, located in the Gulf of Thailand. In 2011, the company progressed discussions on the production permit. Government approval and a final investment decision are expected by the end of 2012. At the end of 2011, proved reserves had not been recognized for the project.
Myanmar: Chevron has a 28.3 percent nonoperated working interest in a PSC for the production of natural gas from the Yadana and Sein fields, within Blocks M5 and M6, in the Andaman Sea. The PSC expires in 2028. The company also has a 28.3 percent nonoperated interest in a pipeline company that transports the natural gas to the Myanmar-Thailand border for delivery to power plants in Thailand. The companys average net natural gas production in 2011 was 86 million cubic feet per day.
|
17
Thailand: Chevron has operated and nonoperated
working interests in multiple offshore blocks. The
companys net
oil-equivalent
production in 2011 averaged 209,000 barrels per day,
composed of 65,000 barrels of crude oil and condensate and
867 million cubic feet of natural gas. All of the
companys natural gas production is sold to PTT Public
Company Limited, Thailands national oil company, under
long-term sales contracts.
Operated interests are in the Pattani Basin with ownership
interests ranging from 35 percent to 80 percent.
Concessions for producing areas within this basin expire between
2020 and 2035. Chevron has a 16 percent nonoperated working
interest in the Arthit and North Arthit fields located in the
Malay Basin. Concessions for the producing areas within this
basin expire between 2036 and 2040.
Start-up of
the 69.9 percent-owned and operated Platong II natural
gas project occurred in October 2011, and total average daily
production ramped up to 377 million cubic feet of natural
gas and 11,000 barrels of condensate as of the end of 2011.
Proved reserves have been recognized for this project.
During 2011, the company drilled nine exploration wells in the
Pattani Basin. All of the wells were successful and development
alternatives are being evaluated. The company also holds
exploration interests in a number of blocks that are inactive,
pending resolution of border issues between Thailand and
Cambodia.
Vietnam: Chevron is the operator of two PSCs in the
Malay Basin off the southwest coast of Vietnam. The company has
a 42.4 percent interest in a PSC that includes Blocks B and
48/95, and a 43.4 percent interest in a PSC for
Block 52/97.
In the blocks off the southwest coast, the Block B Gas
Development is designed to produce natural gas from the Malay
Basin for delivery to state-owned Petrovietnam. The project
includes installation of wellhead and hub platforms, a floating
storage and offloading vessel, a central processing platform and
a pipeline to shore. FEED continued during 2011. Maximum total
daily production is expected to be 490 million cubic feet
of natural gas and 4,000 barrels of condensate. A final
investment decision is expected to be reached in 2012. At the
end of 2011, proved reserves had not been recognized for the
development project.
During the year, work continued on preparations for a 2012
exploration drilling program to further evaluate the potential
of the three company-operated blocks in the Malay Basin. The
company also completed the evaluation of
Block 122 offshore eastern Vietnam and reached a
decision to exit the block.
|
|
|
|
|
|
|
|
|
China: Chevron has operated and nonoperated working interests in several areas in China. The companys net oil-equivalent production in 2011 averaged 22,000 barrels per day, composed of 20,000 barrels of crude oil and condensate and 10 million cubic feet of natural gas.
The company operates and holds a 49 percent interest in the Chuandongbei PSC, located in the onshore Sichuan Basin. The project includes two sour-gas processing plants with an aggregate design capacity of 740 million cubic feet per day connected by a natural gas gathering system to five fields. During 2011, the company continued construction on the first natural gas processing plant. In 2012, construction is expected to start at the second natural gas processing plant. Start-up of the initial phase of the project is expected in 2013, with planned maximum total natural gas production of 558 million cubic feet per day. Proved reserves have been recognized for this project. The PSC for Chuandongbei expires in 2037.
The company holds operating interests in three deepwater exploration blocks in the South China Sea. During the exploration phase, the company has a 100 percent
|
18
working interest in Blocks 53/30 and 64/18, and a
59.2 percent working interest in Block 42/05 under three
separate PSCs. The three deepwater blocks cover approximately
4.8 million acres. During 2011, a
3-D seismic
acquisition program was completed for Blocks 64/18 and 53/30 and
a three-well exploration program was initiated. The first well
was unsuccessful. The second and third wells are expected to be
completed by mid-2012.
The company signed a joint study agreement to explore for
natural gas from shale resources in the Qiannan Basin in April
2011 and commenced seismic operations in July 2011.
The company also has nonoperated working interests of
32.7 percent in Blocks 16/08 and 16/19 in the Pearl River
Mouth Basin and nonoperated working interests of
24.5 percent in the QHD
32-6 Field
and 16.2 percent in Block 11/19 in the Bohai Bay.
|
|
|
|
|
|
|
|
|
Indonesia: Chevron holds operated and nonoperated
working interests in Indonesia. The company has
100 percent-owned and operated interests in the
Rokan and Siak PSCs onshore Sumatra. Chevron also operates
four PSCs in the Kutei Basin, located offshore East Kalimantan.
These interests range from 62 percent to 92.5 percent.
Chevron also has a 51 percent operated working interests in
two exploration blocks in western Papua, West Papua I and West
Papua III, and a 25 percent nonoperated working interest in
a joint venture in Block B in the South Natuna Sea.
|
The companys net oil-equivalent production in 2011 from
its interests in Indonesia averaged 208,000 barrels per
day, composed of 166,000 barrels of liquids and
253 million cubic feet of natural gas. The largest
producing field is Duri, located in the Rokan PSC. Duri has been
under steamflood since 1985 and is one of the worlds
largest steamflood developments. The North Duri Development is
divided into multiple expansion areas. Government approval of
the construction contract bid awards for North Duri Area 13
expansion project is expected in mid-2012 with
start-up
scheduled for 2013. The Rokan PSC expires in 2021.
During 2011, two deepwater development projects in the Kutei
Basin progressed under a single plan of development. In the
first of these projects, Chevron advanced FEED for the
Gendalo-Gehem deepwater natural gas project. The project
includes two separate hub developments, natural gas and
condensate pipelines, and an onshore receiving facility. Maximum
daily total production from the project is expected to be about
1.1 billion cubic feet of natural gas and 31,000 barrels of
condensate. Gas from the project is expected to be used
domestically and for LNG export. The companys working
interest is approximately 63 percent. At the end of 2011, proved
reserves had not been recognized for this project.
In the second of these projects, FEED was completed in December
2011 for the Bangka deepwater natural gas project and the
contracting approval process began with the government of
Indonesia. The project scope includes a subsea tie back to a
floating production unit. The companys working interest is
62 percent. At year-end 2011, proved reserves had not been
recognized for this project.
Exploration activities continued in the Central Sumatra Basin
where six successful appraisal wells were drilled in the
Bekasap, Duri and Kulin fields in 2011, and evaluation of a well
drilled in the Jorang Field continued in 2012. Also in 2011,
seismic data acquisition was completed for West Papua I and is
under way for West Papua III. Processing of the seismic data is
planned for 2012.
In West Java, Chevron operates the wholly owned Salak geothermal
field with a total power-generation capacity of
377 megawatts and holds a 95 percent interest in a
power generation company that operates the Darajat geothermal
contract area with a total capacity of 259 megawatts. Chevron
also operates a 95 percent-owned 300-megawatt cogeneration
facility in support of the companys operation in Duri,
Sumatra. In the Suoh-Sekincau prospect area of Sumatra, the
company holds a 95 percent-owned and operated interest in a
license to explore and develop a geothermal prospect.
19
|
|
|
|
|
|
|
|
|
Partitioned Zone (PZ): Chevron holds a concession with the Kingdom of Saudi Arabia to operate the kingdoms 50 percent interest in the petroleum resources of the onshore area of the PZ between Saudi Arabia and Kuwait. Under the agreement, the company has rights to this 50 percent interest in the hydrocarbon resource until 2039.
During 2011, the companys average net oil-equivalent production was 91,000 barrels per day, composed of 88,000 barrels of crude oil and 20 million cubic feet of natural gas. During 2011, the company continued a steam injection pilot project in the First Eocene carbonate reservoir that was initiated in 2009. A project to expand the steam injection pilot to the Second Eocene reservoir
|
progressed during 2011 and is expected to enter FEED in
second-half 2012. At the end of 2011, proved reserves had not
been recognized for these projects.
Also in 2011, the Central Gas Utilization Project entered FEED.
The project is intended to increase natural gas utilization and
eliminate routine flaring. A final investment decision is
expected in 2013. At year-end 2011, proved reserves had not been
recognized for this project.
Philippines: The company holds a 45 percent
nonoperated working interest in the Malampaya natural gas field
located 50 miles offshore Palawan Island. Net
oil-equivalent production in 2011 averaged 25,000 barrels
per day, composed of 126 million cubic feet of natural gas
and 4,000 barrels of condensate. During 2011, studies were
progressed to maintain capacity.
Chevron also develops and produces geothermal resources under an
agreement with the Philippine government. During 2011, efforts
continued to seek a new
25-year
contract with the government for the continued operation of the
steam fields, which supply geothermal resources to third-party,
637-megawatt power generation facilities in southern Luzon.
Chevron also has a 90 percent-owned and operated interest
in the Kalinga geothermal prospect area in northern Luzon and is
in the early phase of geological and geophysical assessments.
In Australia, the companys exploration and production
efforts are concentrated off the northwest coast. During 2011,
the average net oil-equivalent production from Australia was
101,000 barrels per day.
|
|
|
|
|
|
|
|
|
Chevron has a 16.7 percent nonoperated working interest in the North West Shelf (NWS) Venture offshore Western Australia. Daily net production from the project during 2011 averaged 18,000 barrels of crude oil and condensate, 445 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 Asia, primarily under long-term contracts. The remaining natural gas was sold to the Western Australia domestic market. The concession for the NWS Venture expires in 2034.
The NWS Venture continues to progress two major capital projects North Rankin 2 and NWS Oil Redevelopment. The North Rankin 2 project is designed to recover remaining low-pressure natural gas from the North Rankin and Perseus natural gas fields to meet gas supply needs and maintain production capacity of NWS. The North Rankin B platform was completed and installed during 2011. Maximum total daily production is expected to be about
|
2 billion cubic feet of natural gas and 39,000 barrels
of condensate. Total estimated projects costs are
$5.4 billion and
start-up is
expected in 2013. Proved reserves have been recognized for the
project.
20
The NWS Oil Redevelopment Project recommenced production from
the Cossack, Hermes, Lambert and Wanaea fields in September
2011. The project included replacement of an FPSO vessel and a
portion of existing subsea infrastructure. The project is
expected to extend production from these fields beyond 2020.
Chevron holds a 47.3 percent ownership interest across most
of the Greater Gorgon Area and is the operator of the Gorgon
Project, which combines the development of the Gorgon and nearby
Io/Jansz natural gas field. The projects scope includes a
three-train, 15 million-metric-ton-per-year LNG facility, a
carbon sequestration project and a domestic natural gas plant.
Maximum total daily production from the project is expected to
reach about 2.6 billion cubic feet of natural gas and
20,000 barrels of condensate. Total estimated project costs
for the first phase of development are $37 billion.
Work on the Gorgon Project progressed on schedule. As of
year-end 2011, more than one-third of the construction
activities across numerous fronts on Barrow Island and in
fabrication yards in various countries had been completed. The
development drilling program also commenced in July 2011.
Through year-end 2011, Chevron has signed binding LNG Sales and
Purchase Agreements (SPAs) with six Asian customers for delivery
of about 4.7 million metric tons of LNG per year, which
brings delivery commitments to about 70 percent of
Chevrons share of LNG from this project. Discussions
continue with potential customers to increase long-term sales to
85 to 90 percent of Chevrons net LNG off-take.
Binding SPAs were also signed in 2011 for delivery of about
55 million cubic feet per day of natural gas to two Western
Australian state-owned utilities starting in 2015. Proved
reserves have been recognized for the Greater Gorgon Area fields
included in the project, and first production of natural gas
from the fields is expected in late 2014. The projects
estimated economic life exceeds 40 years from the time of
start-up.
A project for development of a fourth train at the Gorgon LNG
facility is expected to enter FEED in late 2012. At the end of
2011, proved reserves had not been recognized for the fields
associated with this expansion.
Chevron and its joint-venture partners are proceeding with
development of the Wheatstone Project. In September 2011, the
company announced the final investment decision. Construction
started in late 2011. Chevron holds a 72.1 percent interest
in the foundation natural gas processing facilities, which
include a two-train, 8.9 million-metric-ton-per-year LNG
facility and a separate domestic gas plant located at Ashburton
North, along the northwest coast of Australia. The company plans
to supply natural gas to the foundation project from the
company-operated and 90.2 percent-owned Wheatstone and Iago
fields. Maximum total daily production is expected to be about
1.4 billion cubic feet of natural gas and
25,000 barrels of condensate. The LNG facilities will also
be a destination for third-party natural gas. Total estimated
project costs for the first phase of development are
$29 billion.
Through the end of 2011, Chevron has signed binding SPAs with
two Asian customers for the delivery of about 60 percent of
Chevrons net LNG off-take from the Wheatstone Project.
Discussions continue with potential customers to increase
long-term sales to 85 to 90 percent of Chevrons net
LNG off-take and to sell down equity.
Start-up of
the first LNG train is expected in 2016. During 2011, the
company recognized proved reserves for this project.
In the Browse Basin, the Browse LNG development participants
entered FEED in 2011, undertaking environmental, geophysical,
geotechnical and engineering and design studies for the
Brecknock, Calliance and Torosa fields. At the end of 2011,
proved reserves had not been recognized for any of the Browse
Basin fields.
During 2011, the company announced a natural gas discovery at
the 50 percent-owned and operated Orthrus Deep prospect in
Block WA-24-R. The company also announced natural gas
discoveries at the 50 percent-owned and operated Vos
prospect in WA-439-P and the 67 percent-owned and operated
Acme West prospect in Block WA-205-P in 2011, and at the
50 percent-owned and operated Satyr-3 prospect in WA-374-P
in January 2012. These discoveries are expected to support
potential expansion opportunities at company-operated LNG
facilities.
21
In Europe, the company is engaged in exploration and production
activities in Bulgaria, Denmark, the Netherlands, Norway,
Poland, Romania and the United Kingdom. Net oil-equivalent
production in Europe averaged 139,000 barrels per day
during 2011.
|
|
|
|
|
|
|
|
|
Denmark: Chevron has a 15 percent working interest in the partner-operated Danish Underground Consortium (DUC), which produces crude oil and natural gas from 13 fields in the Danish North Sea. Net oil-equivalent production in 2011 from DUC averaged 44,000 barrels per day, composed of 29,000 barrels of crude oil and 91 million cubic feet of natural gas.
Netherlands: Chevron operates and holds interests ranging from 34.1 percent to 80 percent in 10 blocks in the Dutch sector of the North Sea. In 2011, the companys net oil-equivalent production from the producing blocks was 7,000 barrels per day, composed of 2,000 barrels of crude oil and 31 million cubic feet of natural gas. In fourth quarter 2011, the second stage of the A/B Gas Project achieved first gas.
Norway: The company holds a 7.6 percent nonoperated working interest in the Draugen Field. The companys net production averaged 3,000 barrels of oil-equivalent per day during 2011. Chevron is the operator and has a 40 percent working interest in exploration license PL 527. In 2011, Chevron was awarded a 40 percent-owned and operated interest in exploration license PL 598. Both licenses are in the deepwater portion of the Norwegian Sea.
United Kingdom: The companys average net oil-equivalent production in 2011 from 10 offshore fields was 85,000 barrels per day, composed of 59,000 barrels of crude oil and natural gas liquids and 155 million cubic feet of natural gas. Most of the production was from the 85 percent-owned and operated Captain Field, the 23.4 percent-owned
|
and operated Alba Field, and the 32.4 percent-owned and
jointly operated Britannia Field.
The final investment decision was reached in fourth quarter 2011
for the Clair Ridge Project, located west of the Shetland
Islands, in which the company has a 19.4 percent
nonoperated working interest. Total design capacity is planned
to be 120,000 barrels of crude oil per day, and total
estimated projects costs are $7 billion. Production is
scheduled to begin in 2016. Initial proved reserves were
recognized for this phase of the project in 2011.
At the 70 percent-owned and operated Alder discovery, FEED
activities progressed during 2011 and a final investment
decision is planned for late 2012. In the 40 percent-owned
and operated Rosebank area northwest of the Shetland Islands,
seismic, geophysical, geotechnical and environmental surveys
were completed during 2011, and FEED is expected to begin in the
second-half 2012. At the end of 2011, proved reserves have not
been recognized for these projects.
Also west of the Shetland Islands, a three-well exploration and
appraisal drilling program continued through 2011 and was
completed in early 2012. This program comprised exploration
wells on the Lagavulin and Aberlour prospects and appraisal
drilling and well testing of the Cambo discovery. The Lagavulin
well was unsuccessful and the results from the other wells are
under evaluation. Licenses P1196 (Lagavulin) and P1165
(Talisker) were relinquished in November 2011 at the termination
of the license period.
In addition, the company entered into a master regasification
agreement for access to available capacity at the South Hook LNG
terminal in southwest Wales in 2011.
22
|
|
|
|
|
|
|
|
|
Bulgaria: In June 2011, the Bulgarian government advised that Chevron had submitted a winning tender for a permit for exploration in a 1.1 million-acre area in northeast Bulgaria. In January 2012, prior to execution of the license agreement, the Bulgarian government announced the withdrawal of the decision awarding the permit and the Bulgarian parliament imposed a ban on hydraulic fracturing, a technology commonly used for shale exploration and production. Chevron is continuing to work closely with the government of Bulgaria to provide the necessary assurances to the government and the public that hydrocarbons from shale can be developed safely and responsibly.
Poland: Chevron holds four shale concessions in southeast Poland (Grabowiec, Zwierzyniec, Krasnik and Frampol). All four exploration licenses are 100 percent-owned and operated and comprise a total of 1.1 million acres. In 2011, Chevron focused on processing data from a 2-D seismic survey. The data is being used to plan a multiwell drilling program that commenced in fourth quarter 2011.
|
Romania: The company holds a 100 percent
interest in the EV-2 Barlad shale concession. This license,
located in northeast Romania, covers 1.6 million acres. In
2011, the company acquired
2-D seismic
data across the EV-2 Barlad concession. A multiwell drilling
program is expected to begin in late 2012. Also during 2011, the
company continued negotiations on license agreements for three
shale exploration blocks in southeast Romania, Blocks 17,
18 and 19, which comprise approximately 670,000 acres.
Sales of
Natural Gas and Natural Gas Liquids
The company sells natural gas and natural gas liquids from its
producing operations under a variety of contractual
arrangements. In addition, the company also makes third-party
purchases and sales of natural gas and natural gas liquids in
connection with its trading activities.
During 2011, U.S. and international sales of natural gas
were 5.8 billion and 4.4 billion cubic feet per day,
respectively, which includes the companys share of equity
affiliates sales. Outside the United States, substantially
all of the natural gas sales from the companys producing
interests are from operations in Australia, Bangladesh, Europe,
Kazakhstan, Indonesia, Latin America, the Philippines and
Thailand.
U.S. and international sales of natural gas liquids were
161 thousand and 87 thousand barrels per day, respectively, in
2011. Substantially all of the international sales of natural
gas liquids are from company operations in Africa, Kazakhstan,
Indonesia and the United Kingdom.
Refer to Selected Operating Data, on
page FS-10
in Managements Discussion and Analysis of Financial
Condition and Results of Operations, for further information on
the companys sales volumes of natural gas and natural gas
liquids. Refer also to Delivery Commitments on
page 7 for information related to the companys
delivery commitments for the sale of crude oil and natural gas.
23
Downstream
Refining
Operations
At the end of 2011, the company had a refining network capable
of processing about 2 million barrels of crude oil per day.
Operable capacity at December 31, 2011, and daily refinery
inputs for 2009 through 2011 for the company and affiliate
refineries were as follows:
Petroleum
Refineries: Locations, Capacities and Inputs
(Crude-unit
capacities and crude oil inputs in thousands of barrels per day;
includes equity share in affiliates)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operable
|
|
|
Refinery Inputs
|
|
Locations
|
|
Number
|
|
|
Capacity
|
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
Pascagoula
|
|
Mississippi
|
|
|
1
|
|
|
|
330
|
|
|
|
327
|
|
|
|
325
|
|
|
|
345
|
|
El Segundo
|
|
California
|
|
|
1
|
|
|
|
269
|
|
|
|
244
|
|
|
|
250
|
|
|
|
247
|
|
Richmond
|
|
California
|
|
|
1
|
|
|
|
257
|
|
|
|
192
|
|
|
|
228
|
|
|
|
218
|
|
Kapolei
|
|
Hawaii
|
|
|
1
|
|
|
|
54
|
|
|
|
47
|
|
|
|
46
|
|
|
|
49
|
|
Salt Lake City
|
|
Utah
|
|
|
1
|
|
|
|
45
|
|
|
|
44
|
|
|
|
41
|
|
|
|
40
|
|
Perth
Amboy1
|
|
New Jersey
|
|
|
1
|
|
|
|
80
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Consolidated Companies United
States
|
|
|
6
|
|
|
|
1,035
|
|
|
|
854
|
|
|
|
890
|
|
|
|
899
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pembroke2
|
|
United Kingdom
|
|
|
|
|
|
|
|
|
|
|
122
|
|
|
|
211
|
|
|
|
205
|
|
Cape Town3
|
|
South Africa
|
|
|
1
|
|
|
|
110
|
|
|
|
77
|
|
|
|
70
|
|
|
|
72
|
|
Burnaby, B.C.
|
|
Canada
|
|
|
1
|
|
|
|
55
|
|
|
|
43
|
|
|
|
40
|
|
|
|
49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Consolidated Companies
International
|
|
|
2
|
|
|
|
165
|
|
|
|
242
|
|
|
|
321
|
|
|
|
326
|
|
Affiliates4
|
|
Various Locations
|
|
|
7
|
|
|
|
767
|
|
|
|
691
|
|
|
|
683
|
|
|
|
653
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Including Affiliates
International
|
|
|
9
|
|
|
|
932
|
|
|
|
933
|
|
|
|
1,004
|
|
|
|
979
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Including Affiliates Worldwide
|
|
|
15
|
|
|
|
1,967
|
|
|
|
1,787
|
|
|
|
1,894
|
|
|
|
1,878
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
Perth Amboy has been idled since
early 2008 and is operated as a terminal.
|
2 |
|
Pembroke was sold in August 2011.
|
3 |
|
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 2012.
|
4 |
|
Includes 1,000, 2,000 and
4,000 barrels per day of refinery inputs in 2011, 2010 and
2009, respectively, for interests in refineries that were sold
during those periods.
|
Average crude oil distillation capacity utilization during 2011
was 89 percent, compared with 92 percent in 2010. At
the U.S. fuel refineries, crude oil distillation capacity
utilization averaged 89 percent in 2011, compared with
95 percent in 2010. Chevron processes both imported and
domestic crude oil in its U.S. refining operations.
Imported crude oil accounted for about 85 percent and
84 percent of Chevrons U.S. refinery inputs in
2011 and 2010, respectively.
At the Pascagoula Refinery, construction progressed on a
facility to produce approximately 25,000 barrels per day of
premium base oil for use in manufacturing high-performance
finished lubricants, such as motor oils for consumer and
commercial applications. Project completion is expected by
year-end 2013. In February 2012, the company signed an agreement
to sell its idled 80,000-barrel-per-day refinery, which is
operating as a terminal, at Perth Amboy. The sale is expected to
close in second quarter 2012.
At the refinery in El Segundo, construction progressed on a new
processing unit designed to further improve the facilitys
overall reliability, enhance high-value product yield and
provide additional flexibility to process a broad range of crude
slates. Project completion is expected in third quarter 2012. At
the Richmond Refinery, the company filed an application for a
conditional use permit for a revised project and the City of
Richmond published its Notice of Preparation of the revised
Environmental Impact Report in second quarter 2011. The project
is designed to improve the refinerys ability to process
higher sulfur crudes, without changing the refinerys
capacity to process crude blends in the intermediate-light
gravity range. Improved ability to process higher sulfur crudes
is expected to provide increased flexibility to process lower
API-gravity crudes within the refinerys existing capacity
range. Refer also to a discussion of contingencies related to
this project in Note 24 to the Consolidated Financial
Statements on
page FS-57.
24
Outside the United States, GS Caltex, the companys
50 percent-owned affiliate, progressed the construction of
a
53,000-barrel-per-day
gas oil fluid catalytic cracking unit at the Yeosu Refinery in
South Korea. The unit is scheduled for
start-up in
2013. The unit is designed to increase high-value product yield
and lower feedstock costs. Construction continued on
modifications to the 64 percent-owned Star Petroleum
Refinery in Thailand to meet regional specifications for cleaner
fuels. Project completion is scheduled for 2012. During August
2011, the company completed the sale of the Pembroke Refinery in
the United Kingdom. Also in 2011, Caltex Australia Ltd., the
companys 50 percent-owned affiliate, initiated a
review of its refining operations in Australia, which is ongoing.
Marketing
Operations
The company markets petroleum products under the principal
brands of Chevron, Texaco and
Caltex throughout many parts of the world. The table
below identifies the companys and affiliates refined
products sales volumes, excluding intercompany sales, for the
three years ended December 31, 2011.
Refined
Products Sales Volumes
(Thousands
of Barrels per Day)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline
|
|
|
649
|
|
|
|
700
|
|
|
|
720
|
|
Jet Fuel
|
|
|
209
|
|
|
|
223
|
|
|
|
254
|
|
Gas Oil and Kerosene
|
|
|
213
|
|
|
|
232
|
|
|
|
226
|
|
Residual Fuel Oil
|
|
|
87
|
|
|
|
99
|
|
|
|
110
|
|
Other Petroleum
Products1
|
|
|
99
|
|
|
|
95
|
|
|
|
93
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total United States
|
|
|
1,257
|
|
|
|
1,349
|
|
|
|
1,403
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International2
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline
|
|
|
447
|
|
|
|
521
|
|
|
|
555
|
|
Jet Fuel
|
|
|
269
|
|
|
|
271
|
|
|
|
264
|
|
Gas Oil and Kerosene
|
|
|
543
|
|
|
|
583
|
|
|
|
647
|
|
Residual Fuel Oil
|
|
|
233
|
|
|
|
197
|
|
|
|
209
|
|
Other Petroleum
Products1
|
|
|
200
|
|
|
|
192
|
|
|
|
176
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total International
|
|
|
1,692
|
|
|
|
1,764
|
|
|
|
1,851
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Worldwide2
|
|
|
2,949
|
|
|
|
3,113
|
|
|
|
3,254
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 Principally
naphtha, lubricants, asphalt and coke.
|
|
|
|
|
2 Includes
share of equity affiliates sales:
|
|
|
556
|
|
|
|
562
|
|
|
|
516
|
|
In the United States, the company markets under the Chevron and
Texaco brands. At year-end 2011, the company supplied directly
or through retailers and marketers approximately 8,170 Chevron-
and Texaco-branded motor vehicle service stations, primarily in
the southern and western states. Approximately 490 of these
outlets are company-owned or -leased stations.
Outside the United States, Chevron supplied directly or through
retailers and marketers approximately 9,660 branded service
stations, including affiliates. In British Columbia, Canada, the
company markets under the Chevron brand. The company markets in
Latin America and the Caribbean using the Texaco brand. In the
Asia-Pacific region, southern Africa, Egypt and Pakistan, the
company uses the Caltex brand. The company also operates through
affiliates under various brand names. In South Korea, the
company operates through its 50 percent-owned affiliate, GS
Caltex, and in Australia through its 50 percent-owned
affiliate, Caltex Australia Limited.
The company continued its ongoing effort to concentrate
downstream resources and capital on strategic assets. In 2011,
the company completed the sale of its fuels marketing and
aviation businesses in 16 countries in the Caribbean and Latin
America and certain marketing businesses in five countries in
Africa. In August 2011, the company also completed the sale of
its marketing businesses in Ireland and the United Kingdom. In
2012, the company expects to complete the sale of its fuels
marketing, finished lubricants and aviation fuels businesses in
Spain as well as certain fuels marketing and aviation businesses
in the central Caribbean, following receipt of required local
regulatory and government approvals. In addition, the company
converted more than 240 company-operated service stations
into retailer-owned sites in various countries outside the
United States.
25
Chevron markets commercial aviation fuel at approximately 170
airports worldwide. The company also markets an extensive line
of lubricant and coolant products under the brand names
Havoline, Delo, Ursa, Meropa and Taro.
Chemicals
Operations
Chevron owns a 50 percent interest in its Chevron Phillips
Chemical Company LLC (CPChem) affiliate. At the end of 2011,
CPChem owned or had joint-venture interests in 38 manufacturing
facilities and four research and technical centers around the
world.
CPChems 35 percent-owned Saudi Polymers Company
expects to commence commercial operations on a new petrochemical
project in Al Jubail, Saudi Arabia, in 2012. The joint-venture
project includes olefins, polyethylene, polypropylene, 1-hexene
and polystyrene units.
In the United States, CPChem continued with plans to construct a
1-hexene plant at the companys Cedar Bayou complex in
Baytown, Texas, capable of producing in excess of 200,000 tons
per year.
Start-up is
expected in 2014. The plant is expected to be the largest
1-hexene unit in the world and will utilize CPChems
proprietary 1-hexene technology. CPChem is also conducting a
feasibility study to evaluate a potential U.S. Gulf Coast
ethylene cracker and derivatives complex to capitalize on
advantaged feedstock sourced from emerging shale gas development
in North America.
Chevrons Oronite brand lubricant and fuel additives
business is a leading developer, manufacturer and marketer of
performance additives for lubricating oils and fuels. The
company owns and operates facilities in Brazil, France, Japan,
the Netherlands, Singapore and the United States and has equity
interests in facilities in India and Mexico. Oronite lubricant
additives are blended into refined base oil to produce finished
lubricant packages used primarily in engine applications such as
passenger car, heavy-duty diesel, marine, locomotive and
motorcycle engines, and additives for fuels that are blended to
improve engine performance and extend engine life. In February
2012, the company reached a final investment decision to
significantly increase the capacity of the existing additives
plant in Singapore.
Transportation
Pipelines: Chevron owns and operates an extensive
network of crude oil, refined product, chemical, natural gas
liquid and natural gas pipelines and other infrastructure assets
in the United States. The company also has direct and indirect
interests in other U.S. and international pipelines. The
companys ownership interests in pipelines are summarized
in the following table.
Pipeline
Mileage at December 31, 2011
|
|
|
|
|
|
|
Net
Mileage1,2
|
|
United States:
|
|
|
|
|
Crude Oil
|
|
|
2,115
|
|
Natural Gas
|
|
|
2,282
|
|
Petroleum Products
|
|
|
6,125
|
|
|
|
|
|
|
Total United States
|
|
|
10,522
|
|
International:
|
|
|
|
|
Crude Oil
|
|
|
700
|
|
Natural Gas
|
|
|
699
|
|
Petroleum Products
|
|
|
311
|
|
|
|
|
|
|
Total International
|
|
|
1,710
|
|
|
|
|
|
|
Worldwide
|
|
|
12,232
|
|
|
|
|
|
|
|
|
1
|
Includes companys share of pipeline mileage owned by
equity affiliates.
|
|
2
|
Excludes gathering pipelines relating to the crude oil and
natural gas production function.
|
26
Work was completed in first quarter 2012 to return the Cal-Ky
Pipeline to crude oil service as a supply line for the
Pascagoula Refinery. This crude oil pipeline is also expected to
provide additional outlets for the companys equity
production. The company is leading the construction of a
136 mile,
24-inch
pipeline from the Jack/St. Malo facility to Green Canyon 19 in
the U.S. Gulf of Mexico, where there is an interconnect to
pipelines delivering crude oil into Texas and Louisiana.
Refer to pages 14, 16 and 17 in the Upstream section for
information on the Chad/Cameroon pipeline, the West Africa Gas
Pipeline, the Baku-Tbilisi-Ceyhan Pipeline, the Western Route
Export Pipeline and the Caspian Pipeline Consortium.
Tankers: All tankers in Chevrons controlled
seagoing fleet were utilized during 2011. During 2011, the
company had 48 deep-sea vessels chartered on a voyage basis, or
for a period of less than one year. The table below summarizes
the capacity of the companys controlled fleet.
Controlled
Tankers at December 31,
20111
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Flag
|
|
|
Foreign Flag
|
|
|
|
|
|
|
Cargo Capacity
|
|
|
|
|
|
Cargo Capacity
|
|
|
|
Number
|
|
|
(Millions of Barrels)
|
|
|
Number
|
|
|
(Millions of Barrels)
|
|
|
Owned
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
1.1
|
|
Bareboat-Chartered
|
|
|
4
|
|
|
|
1.4
|
|
|
|
17
|
|
|
|
25.0
|
|
Time-Chartered2
|
|
|
|
|
|
|
|
|
|
|
13
|
|
|
|
10.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
4
|
|
|
|
1.4
|
|
|
|
31
|
|
|
|
36.6
|
|
|
|
1
|
Consolidated companies only. Excludes tankers chartered on a
voyage basis, those with dead-weight tonnage less than 25,000
and those used exclusively for storage.
|
|
2
|
Tankers chartered for more than one year.
|
The companys
U.S.-flagged
fleet is engaged primarily in transporting refined products
between the Gulf Coast and the East Coast and from California
refineries to terminals on the West Coast and in Alaska and
Hawaii. The company retired one
U.S.-flagged
product tanker in 2011.
The foreign-flagged vessels are engaged primarily in
transporting crude oil from the Middle East, Southeast Asia, the
Black Sea, South America, Mexico and West Africa to ports in the
United States, Europe, Australia and Asia. The companys
foreign-flagged vessels also transport refined products to and
from various locations worldwide.
In addition to the vessels described above, the company has
contracts in place to build LNG carriers and a
dynamic-positioning shuttle tanker to support future upstream
projects. The company also owns a one-sixth interest in each of
seven LNG carriers transporting cargoes for the North West Shelf
Venture in Australia.
Other
Businesses
Mining
Chevrons
U.S.-based
mining company continues its efforts to divest its remaining
coal mining operations. The company completed the sale of the
North River Mine and other coal-related assets in Alabama in
second quarter 2011, and the sale of its Kemmerer, Wyoming,
surface coal mine in first quarter 2012. The company is pursuing
the sale of its 50 percent interest in Youngs Creek Mining
Company, LLC, which was formed to develop a coal mine in
northern Wyoming. Activities related to final reclamation
continued in 2011 at the company-operated surface coal mine in
McKinley, New Mexico, which ceased coal production at the
end of 2009.
At year-end 2011, Chevron had 153 million tons of proven
and probable coal reserves in the United States, including
reserves of low-sulfur coal. Coal sales from wholly owned mines
in 2011 were 6 million tons, down about 2 million tons
from 2010.
27
In addition to the coal operations, Chevron owns and operates
the Questa molybdenum mine in New Mexico. At year-end 2011,
Chevron had 53 million pounds of proven molybdenum reserves
at Questa. Production and underground development at Questa
continued at reduced levels in 2011 in response to weak prices
for molybdenum.
Power
Generation
Chevrons Global Power Company manages interests in 13
power assets with a total operating capacity of more than 3,100
megawatts, primarily through joint ventures in the United States
and Asia. Twelve of these are efficient combined-cycle and
gas-fired cogeneration facilities that utilize recovered waste
heat to produce electricity and support industrial thermal
hosts. The 13th facility is a wind farm, located in Casper,
Wyoming, that is designed to optimize the use of a
decommissioned refinery site for delivery of clean, renewable
energy to the local utility.
The company has major geothermal operations in Indonesia and the
Philippines and is investigating several advanced solar
technologies for use in oil field operations as part of its
renewable energy strategy. For additional information on the
companys geothermal operations and renewable energy
projects, refer to pages 19 and 20 and Research and
Technology below.
Chevron
Energy Solutions (CES)
CES is a wholly owned subsidiary that develops and builds
sustainable energy projects that increase energy efficiency and
production of renewable power, reduce energy costs, and ensure
reliable, high-quality energy for government, education and
business facilities. Since 2000, CES has developed hundreds of
projects that have helped customers reduce their energy costs
and environmental impact. Projects announced in 2011 include the
City of Dinuba solar project in California; the Houston
Independent School District renewable and energy efficiency
project in Texas; the Eglin Air Force Base energy management
systems upgrade project in Florida; and the Oceanic Time Warner
solar project in Hawaii.
Research
and Technology
The companys energy technology organization supports
Chevrons upstream and downstream businesses by providing
technology, services and competency development in earth
sciences; reservoir and production engineering; drilling and
completions; facilities engineering; manufacturing; process
technology; catalysis; technical computing; and health,
environment and safety disciplines. The information technology
organization integrates computing, telecommunications, data
management, security and network technology to provide a
standardized digital infrastructure and enable Chevrons
global operations and business processes.
Chevron Technology Ventures (CTV) manages investments and
projects in emerging energy technologies and their integration
into Chevrons core businesses. As of the end of 2011, CTV
continued to explore technologies such as next-generation
biofuels and advanced solar. In 2011, the company completed
construction and commissioned the worlds largest
solar-to-steam generation project for use in
enhanced-oil-recovery operations in Coalinga, California. The
project will test the viability of using solar power to produce
steam to improve oil recovery.
Chevrons research and development expenses were
$627 million, $526 million and $603 million for
the years 2011, 2010 and 2009, respectively.
Some of the investments the company makes in the areas described
above are in new or unproven technologies and business
processes, and ultimate technical or commercial successes are
not certain.
Environmental
Protection
The company designs, operates and maintains its facilities to
avoid potential spills or leaks and minimize the impact of those
that may occur. Chevron requires its facilities and operations
to have operating standards and processes and emergency response
plans that address all credible and significant risks identified
by site-specific risk and impact assessments. Chevron also
requires that sufficient resources be available to execute these
plans. In the unlikely event that a major spill or leak occurs,
Chevron also maintains a Worldwide Emergency Response Team
comprised of employees who are trained in various aspects of
emergency response, including post-incident remediation.
28
To complement the companys capabilities, Chevron maintains
active membership in international oil spill response
cooperatives, including the Marine Spill Response Corporation,
which operates in U.S. territorial waters, and Oil Spill
Response, Ltd. (OSRL), which operates globally. The company is a
founding member of the Marine Well Containment Company, whose
primary mission is to expediently deploy containment equipment
and systems to capture and contain crude oil in the unlikely
event of a future loss of control of a deepwater well in the
Gulf of Mexico. In addition, the company is a member of the
Subsea Well Response Project (SWRP). SWRPs objective is to
further develop the industrys capability to contain and
shut in subsea well control incidents in different regions of
the world. In late 2011, upon detection of ocean floor oil seeps
in the deepwater Frade Field in Brazil, Chevron rapidly deployed
capabilities and processes in coordination with OSRL. In early
2012, the company rapidly deployed response capabilities to
address a natural gas well control incident in Nigeria.
Virtually all aspects of the companys businesses are
subject to various U.S. federal, state and local
environmental, health and safety laws and regulations and to
similar laws and regulations in other countries. These
regulatory requirements continue to change and increase in both
number and complexity and to govern not only the manner in which
the company conducts its operations, but also the products it
sells. Most of the costs of complying with the many laws and
regulations pertaining to the companys operations are, or
are expected to become, embedded in the normal costs of
conducting business.
In 2011, the companys U.S. capitalized environmental
expenditures were $345 million, representing about
3 percent of the companys total consolidated
U.S. capital and exploratory expenditures. These
environmental expenditures include capital outlays to retrofit
existing facilities as well as those associated with new
facilities. The expenditures relate mostly to air- and
water-quality projects and activities at the companys
refineries, oil and gas producing facilities, and marketing
facilities. For 2012, the company estimates U.S. capital
expenditures for environmental control facilities will be
approximately $410 million. The future annual capital costs
are uncertain and will be governed by several factors, including
future changes to regulatory requirements.
Regulations intended to protect the environment, including those
intended to address concerns about greenhouse gas emissions and
global climate change, continue to evolve. Legislation,
regulations and market-based programs that could affect the
companys operations exist at the international or
multinational (such as the Kyoto Protocol and the European
Unions Emissions Trading System), national (such as the
U.S. Environmental Protection Agencys rules for
stricter emission standards and increased renewable fuel content
for transportation fuels), and regional (such as
Californias Global Warming Solutions Act) levels.
Refer to Managements Discussion and Analysis of Financial
Condition and Results of Operations on pages FS-14 through FS-16
for additional information on environmental matters and their
impact on Chevron and on the companys 2011 environmental
expenditures, remediation provisions and year-end environmental
reserves. Refer also to Item 1A. Risk Factors on pages 29
through 31 for a discussion of greenhouse gas regulation and
climate change.
Web Site
Access to SEC Reports
The companys Internet Web site is www.chevron.com.
Information contained on the companys Internet Web site is
not part of this Annual Report on
Form 10-K.
The companys Annual Reports on
Form 10-K,
Quarterly Reports on
Form 10-Q,
Current Reports on
Form 8-K
and any amendments to these reports filed or furnished pursuant
to Section 13(a) or 15(d) of the Securities Exchange Act of
1934 are available free of charge on the companys Web site
soon after such reports are filed with or furnished to the
Securities and Exchange Commission (SEC). The reports are also
available on the SECs Web site at www.sec.gov.
Chevron is a global energy company with a diversified business
portfolio, a strong balance sheet, and a history of generating
sufficient cash to pay dividends and fund capital and
exploratory expenditures. Nevertheless, some inherent risks
could materially impact the companys financial results of
operations or financial condition.
Chevron
is exposed to the effects of changing commodity
prices.
Chevron is primarily in a commodities business with a history of
price volatility. The single largest variable that affects the
companys results of operations is the price of crude oil,
which can be influenced by general 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 geopolitical risk.
Chevron accepts the risk of changing commodity prices as part of
its business planning process. As such, an investment in the
company carries significant exposure to fluctuations in crude
oil prices.
29
During extended periods of historically low prices for crude
oil, the companys upstream earnings and capital and
exploratory expenditure programs will be negatively affected.
Upstream assets may also become impaired. The impact on
downstream earnings is dependent upon the supply and demand for
refined products and the associated margins on refined product
sales.
The
scope of Chevrons business will decline if the company
does not successfully develop resources.
The company is in an extractive business; therefore, if Chevron
is not successful in replacing the crude oil and natural gas it
produces with good prospects for future production or through
acquisitions, the companys business will decline. Creating
and maintaining an inventory of projects depends on many
factors, including obtaining and renewing rights to explore,
develop and produce hydrocarbons; drilling success; ability to
bring long-lead-time, capital-intensive projects to completion
on budget and on schedule; and efficient and profitable
operation of mature properties.
The
companys operations could be disrupted by natural or human
factors.
Chevron operates in both urban areas and remote and sometimes
inhospitable regions. The companys operations and
facilities are therefore subject to disruption from either
natural or human causes beyond its control, including
hurricanes, floods and other forms of severe weather, war, civil
unrest and other political events, fires, earthquakes, system
failures, cyber threats and terrorist acts, any of which could
result in suspension of operations or harm to people or the
natural environment.
The
companys operations have inherent risks and hazards that
require significant and continuous oversight.
Chevrons results depend on its ability to identify and
mitigate the risks and hazards inherent to operating in the
crude oil and natural gas industry. The company seeks to
minimize these operational risks by carefully designing and
building its facilities and conducting its operations in a safe
and reliable manner. However, failure to manage these risks
effectively could result in unexpected incidents, including
releases, explosions or mechanical failures resulting in
personal injury, loss of life, environmental damage, loss of
revenues, legal liability
and/or
disruption to operations. Chevron has implemented and maintains
a system of corporate policies, behaviors and compliance
mechanisms to manage safety, health, environmental, reliability
and efficiency risks; to verify compliance with applicable laws
and policies; and to respond to and learn from unexpected
incidents. Nonetheless, in certain situations where Chevron is
not the operator, the company may have limited influence and
control over third parties, which may limit its ability to
manage and control such risks.
Chevrons
business subjects the company to liability risks from litigation
or government action.
The company produces, transports, refines and markets materials
with potential toxicity, and it purchases, handles and disposes
of other potentially toxic materials in the course of its
business. Chevron operations also produce byproducts, which may
be considered pollutants. Often these operations are conducted
through joint ventures over which the company may have limited
influence and control. Any of these activities could result in
liability or significant delays in operations arising from
private litigation or government action, either as a result of
an accidental, unlawful discharge or as a result of new
conclusions on the effects of the companys operations on
human health or the environment. In addition, to the extent that
societal pressures or political or other factors are involved,
it is possible that such liability could be imposed without
regard to the companys causation of or contribution to the
asserted damage, or to other mitigating factors.
The
company does not insure against all potential losses, which
could result in significant financial exposure.
The company does not have commercial insurance or third-party
indemnities to cover fully all operational risks or potential
liability in the event of a significant incident or series of
incidents causing catastrophic loss. As a result the company is,
to a substantial extent, self-insured for such events. The
company relies on existing liquidity, financial resources and
borrowing capacity to meet short-term obligations that would
arise from such an event or series of events. The occurrence of
a significant incident or unforeseen liability for which the
company is not fully insured or for which insurance recovery is
significantly delayed could have a material adverse effect on
the companys results of operations or financial condition.
Political
instability and significant changes in the regulatory
environment could harm Chevrons business.
The companys operations, particularly exploration and
production, can be affected by changing economic, regulatory and
political environments in the various countries in which it
operates. As has occurred in the past, actions could be
30
taken by governments to increase public ownership of the
companys partially or wholly owned businesses or to impose
additional taxes or royalties.
In certain locations, governments have imposed or proposed
restrictions on the companys operations, export and
exchange controls, burdensome taxes, and public disclosure
requirements that might harm the companys competitiveness
or relations with other governments or third parties. In other
countries, political conditions have existed that may threaten
the safety of employees and the companys continued
presence in those countries and internal unrest, acts of
violence or strained relations between a government and the
company or other governments may adversely affect the
companys operations. Those developments have, at times,
significantly affected the companys related operations and
results and are carefully considered by management when
evaluating the level of current and future activity in such
countries. At December 31, 2011, 22 percent of the
companys net proved reserves were located in Kazakhstan.
The company also has significant interests in OPEC-member
countries, including Angola, Nigeria and Venezuela and in the
Partitioned Zone between Saudi Arabia and Kuwait. Twenty-two
percent of the companys net proved reserves, including
affiliates, were located in OPEC countries at December 31,
2011.
Regulation
of greenhouse gas emissions could increase Chevrons
operational costs and reduce demand for Chevrons
products.
Continued political attention to issues concerning climate
change, the role of human activity in it, and potential
mitigation through regulation could have a material impact on
the companys operations and financial results.
International agreements and national or regional legislation
and regulatory measures to limit greenhouse emissions are
currently in various stages of discussion or implementation.
These and other greenhouse gas emissions-related laws, policies
and regulations may result in substantial capital, compliance,
operating and maintenance costs. The level of expenditure
required to comply with these laws and regulations is uncertain
and is expected to vary depending on the laws enacted in each
jurisdiction, the companys activities in it and market
conditions. Greenhouse gas emissions that could be regulated
include those arising from the companys exploration and
production of crude oil and natural gas; the upgrading of
production from oil sands into synthetic oil; power generation;
the conversion of crude oil and natural gas into refined
products; the processing, liquefaction and regasification of
natural gas; the transportation of crude oil, natural gas and
related products and consumers or customers use of
the companys products. Some of these activities, such as
consumers and customers use of the companys
products, as well as actions taken by the companys
competitors in response to such laws and regulations, are beyond
the companys control.
The effect of regulation on the companys financial
performance will depend on a number of factors including, among
others, the sectors covered, the greenhouse gas emissions
reductions required by law, the extent to which Chevron would be
entitled to receive emission allowance allocations or would need
to purchase compliance instruments on the open market or through
auctions, the price and availability of emission allowances and
credits, and the impact of legislation or other regulation on
the companys ability to recover the costs incurred through
the pricing of the companys products. Material price
increases or incentives to conserve or use alternative energy
sources could reduce demand for products the company currently
sells and adversely affect the companys sales volumes,
revenues and margins.
Changes
in managements estimates and assumptions may have a
material impact on the companys consolidated financial
statements and financial or operations performance in any given
period.
In preparing the companys periodic reports under the
Securities Exchange Act of 1934, including its financial
statements, Chevrons management is required under
applicable rules and regulations to make estimates and
assumptions as of a specified date. These estimates and
assumptions are based on managements best estimates and
experience as of that date and are subject to substantial risk
and uncertainty. Materially different results may occur as
circumstances change and additional information becomes known.
Areas requiring significant estimates and assumptions by
management include measurement of benefit obligations for
pension and other postretirement benefit plans; estimates of
crude oil and natural gas recoverable reserves; accruals for
estimated liabilities, including litigation reserves; and
impairments to property, plant and equipment. Changes in
estimates or assumptions or the information underlying the
assumptions, such as changes in the companys business
plans, general market conditions or changes in commodity prices,
could affect reported amounts of assets, liabilities or expenses.
|
|
Item 1B.
|
Unresolved
Staff Comments
|
None.
31
The location and character of the companys crude oil,
natural gas and mining properties and its refining, marketing,
transportation and chemicals facilities are described on
page 3 under Item 1. Business. Information required by
Subpart 1200 of
Regulation S-K
(Disclosure by Registrants Engaged in Oil and Gas
Producing Activities) is also contained in Item 1 and
in Tables I through VII on pages FS-62 through FS-76.
Note 13, Properties, Plant and Equipment, to
the companys financial statements is on
page FS-41.
|
|
Item 3.
|
Legal
Proceedings
|
Ecuador
Information related to Ecuador matters is included in
Note 14 to the Consolidated Financial Statements under the
heading Ecuador, beginning on
page FS-41.
Certain
Governmental Proceedings
In November 2008, the California Air Resources Board (CARB)
proposed a civil penalty against Chevrons Sacramento,
California, terminal for alleged violations between August and
December 2007 of CARBs regulations governing the minimum
concentration of additives in gasoline. Due to a computer
programming error, the Sacramento terminals automatic
dispensers allegedly failed to inject additive detergent into a
gasoline line. It appears that the resolution of these notices
of violation may result in the payment of a civil penalty
exceeding $100,000.
In November 2008, CARB proposed a civil penalty against
Chevrons Richmond, California, refinery for a notice of
violation relating to gasoline that was not properly certified
as to composition. The composition certificates for the gasoline
were corrected without requiring any change to the composition
of the gasoline. In July 2009, CARB issued the refinery a notice
of violation relating to an error in gasoline blending that
caused the product composition certifications to be in error.
The composition certifications were corrected without requiring
any change to the gasoline. Discussions with CARB officials
relating to all of these matters continue. It appears that the
resolution of these notices of violation may result in the
payment of a civil penalty exceeding $100,000.
In July 2009, CARB issued a notice of violation against Chevron
Products Company for alleged violations of CARBs
regulations governing the certification of gasoline that
occurred during storage at a third-party facility and which had
been self-reported by Chevron on discovery. Chevron believes
that this matter will not result in the payment of a civil
penalty exceeding $100,000.
In 2011, CARB made penalty demands with respect to four notices
of violation against Chevron for alleged violations of
CARBs fuel blend regulations at certain California
terminals and refineries. It appears that the resolution of
these notices of violation may result in the payment of a civil
penalty exceeding $100,000.
In July 2009, the Hawaii Department of Health (DOH) alleged that
Chevron is obligated to pay stipulated civil penalties exceeding
$100,000 in conjunction with commitments Chevron undertook to
install and operate certain air emission control equipment at
its Hawaii Refinery pursuant to a Clean Air Act settlement with
the United States Environmental Protection Agency (EPA) and DOH.
Chevron has disputed many of the allegations.
Chevron has entered into negotiations with the EPA with respect
to alleged air quality violations at Chevrons Perth Amboy,
New Jersey refinery identified in a September 16, 2008
Compliance Order issued by the EPA. The alleged violations
relate to certain management and reporting requirements set
forth in the EPAs Leak Detection and Repair regulations
(these regulations pertain to the control and monitoring of
fugitive emissions from refinery process equipment). Based on
discussions with the EPA, it appears that the resolution of this
matter may result in the payment of a civil penalty exceeding
$100,000.
The EPA indicated that it would assess Chevrons Salt Lake
City Refinery a civil penalty for alleged violations of federal
requirements and Utahs air pollution laws. These alleged
violations were the subject of an August 20, 2008 EPA
Notice of Violation (NOV) for which no penalty was assessed at
the time. It appears that the resolution of this NOV may result
in the payment of a civil penalty exceeding $100,000.
The South Coast Air Quality Management District (SCAQMD) issued
a NOV to Chevrons Huntington Beach, California, terminal
seeking a civil penalty for alleged violations involving the
repair of two holes in the roof of a tank at the terminal. Based
on a July 8, 2011, settlement communication with the
SCAQMD, it appears that the resolution of this NOV may result in
the payment of a civil penalty exceeding $100,000.
32
Chevron reached a final resolution of an administrative penalty
proceeding brought by the Utah Department of Environmental
Quality by agreeing to pay the State of Utah a civil penalty of
$500,000 as the result of two crude oil releases. The first
release occurred in June 2010 and the second occurred in
December 2010. In addition, Chevron agreed to pay the State of
Utah and the Salt Lake City Corporation $4 million in
damages and restoration projects. The public review period
passed and the penalty has been paid.
|
|
Item 4.
|
Mine
Safety Disclosures
|
Information concerning mine safety violations or other
regulatory matters required by Section 1503(a) of the
Dodd-Frank
Wall Street Reform and Consumer Protection Act and Item 104
of
Regulation S-K
(17 C.F.R. § 229.104) is included in
Exhibit 95 of this Annual Report on
Form 10-K.
PART II
Item 5. Market
for the Registrants Common Equity, Related Stockholder
Matters and Issuer Purchases of Equity Securities
The information on Chevrons common stock market prices,
dividends, principal exchanges on which the stock is traded and
number of stockholders of record is contained in the Quarterly
Results and Stock Market Data tabulations, on
page FS-20.
CHEVRON
CORPORATION
ISSUER PURCHASES OF EQUITY SECURITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
Period
|
|
Purchased(1)(2)
|
|
|
per Share
|
|
|
Announced Program
|
|
|
the
Program(2)
|
|
|
Oct. 1 Oct. 31, 2011
|
|
|
4,379,887
|
|
|
|
99.86
|
|
|
|
4,378,905
|
|
|
|
|
|
Nov. 1 Nov. 30, 2011
|
|
|
4,173,725
|
|
|
|
102.18
|
|
|
|
4,170,000
|
|
|
|
|
|
Dec. 1 Dec. 31, 2011
|
|
|
3,738,606
|
|
|
|
103.63
|
|
|
|
3,730,500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Oct. 1 Dec. 31, 2011
|
|
|
12,292,218
|
|
|
|
101.80
|
|
|
|
12,279,405
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Pertains to common shares repurchased during the three-month
period ended December 31, 2011, from company employees for
required personal income tax withholdings on the exercise of the
stock options issued to management under long-term incentive
plans and former Texaco Inc. and Unocal stock option plans. Also
includes 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, 2011. |
|
(2) |
|
In July 2010, the Board of Directors approved an ongoing share
repurchase program with no set term or monetary limits, under
which common shares would be acquired by the company through
open market purchases (some pursuant to a
Rule 10b5-1
plan) at prevailing prices, as permitted by securities laws and
other legal requirements and subject to market conditions and
other factors. As of December 31, 2011,
51,064,679 shares had been acquired under this program for
$5.0 billion. |
|
|
Item 6.
|
Selected
Financial Data
|
The selected financial data for years 2007 through 2011 are
presented on
page FS-61.
|
|
Item 7.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
|
The index to Managements Discussion and Analysis of
Financial Condition and Results of Operations, Consolidated
Financial Statements and Supplementary Data is presented on
page FS-1.
|
|
Item 7A.
|
Quantitative
and Qualitative Disclosures About Market Risk
|
The companys discussion of interest rate, foreign currency
and commodity price market risk is contained in
Managements Discussion and Analysis of Financial Condition
and Results of Operations Financial and
Derivative
33
Instruments, beginning on
page FS-13
and in Note 10 to the Consolidated Financial Statements,
Financial and Derivative Instruments, beginning on
page FS-36.
|
|
Item 8.
|
Financial
Statements and Supplementary Data
|
The index to Managements Discussion and Analysis,
Consolidated Financial Statements and Supplementary Data is
presented on
page FS-1.
|
|
Item 9.
|
Changes
in and Disagreements With Accountants on Accounting and
Financial Disclosure
|
None.
|
|
Item 9A.
|
Controls
and Procedures
|
|
|
(a)
|
Evaluation
of Disclosure Controls and Procedures
|
The companys management has evaluated, with the
participation of the Chief Executive Officer and the Chief
Financial Officer, the effectiveness of the companys
disclosure controls and procedures (as defined in
Rule 13a-15(e)
and
15d-15(e)
under the Securities Exchange Act of 1934 (the Exchange
Act)) as of the end of the period covered by this report.
Based on this evaluation, the Chief Executive Officer and the
Chief Financial Officer concluded that the companys
disclosure controls and procedures were effective as of
December 31, 2011.
|
|
(b)
|
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 the 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, 2011.
The effectiveness of the companys internal control over
financial reporting as of December 31, 2011, has been
audited by PricewaterhouseCoopers LLP, an independent registered
public accounting firm, as stated in its report included on
page FS-22.
|
|
(c)
|
Changes
in Internal Control Over Financial Reporting
|
During the quarter ended December 31, 2011, there were no
changes in the companys internal control over financial
reporting that have materially affected, or are reasonably
likely to materially affect, the companys internal control
over financial reporting.
|
|
Item 9B.
|
Other
Information
|
None.
34
PART III
Item 10. Directors,
Executive Officers and Corporate Governance
Executive
Officers of the Registrant at February 23, 2012
The Executive Officers of the Corporation consist of the
Chairman of the Board, the Vice Chairman of the Board and such
other officers of the Corporation who are members of the
Executive Committee.
|
|
|
|
|
|
|
Name and Age
|
|
Current and Prior Positions (up to five years)
|
|
Current Areas of Responsibility
|
|
J.S. Watson
|
|
55
|
|
Chairman of the Board and Chief Executive Officer (since 2010)
|
|
Chief Executive Officer
|
|
|
|
|
Vice Chairman of the Board (2009)
|
|
|
|
|
|
|
Executive Vice President (2008 to 2009)
|
|
|
|
|
|
|
Vice President and President of Chevron International Exploration and Production Company (2005 through 2007)
|
|
|
|
|
|
|
|
|
|
G.L. Kirkland
|
|
61
|
|
Vice Chairman of the Board and Executive Vice President (since 2010)
|
|
Worldwide Exploration and
Production Activities and Global
|
|
|
|
|
Executive Vice President (2005 through 2009)
|
|
Gas Activities, including Natural
|
|
|
|
|
|
|
Gas Trading
|
|
|
|
|
|
|
|
J.R. Blackwell
|
|
53
|
|
Executive Vice President (since 2011)
President of Chevron Asia Pacific Exploration and Production Company (2008 through 2011)
Managing Director of Chevron Southern Africa Strategic Business Unit (2003 to 2007)
|
|
Technology; Mining; Project
Resources Company;
Procurement
|
|
|
|
|
|
|
|
M.K. Wirth
|
|
51
|
|
Executive Vice President (since 2006)
|
|
Worldwide Refining, Marketing,
|
|
|
|
|
President of Global Supply and Trading
|
|
Lubricants, and Supply and
|
|
|
|
|
(2004 to 2006)
|
|
Trading Activities, excluding
|
|
|
|
|
|
|
Natural Gas Trading; Chemicals
|
|
|
|
|
|
|
|
R.I. Zygocki
|
|
54
|
|
Executive Vice President (since 2011)
|
|
Strategy and Planning; Health,
|
|
|
|
|
Vice President, Policy, Government and Public Affairs (2007 through 2011)
Vice President, Health, Environment and Safety (2003 through 2007)
|
|
Environment and Safety; Policy,
Government and Public Affairs
|
|
|
|
|
|
|
|
P.E. Yarrington
|
|
55
|
|
Vice President and Chief Financial Officer
(since 2009)
|
|
Finance
|
|
|
|
|
Vice President and Treasurer (2007 through 2008)
Vice President, Policy, Government and Public Affairs (2002 to 2007)
|
|
|
|
|
|
|
|
|
|
R.H. Pate
|
|
49
|
|
Vice President and General Counsel (since 2009)
Partner and Head of Global Competition Practice of Hunton & Williams LLP, a major U.S. law firm (2005 to 2009)
|
|
Law, Governance and Compliance
|
The information about directors required by Item 401(a),
(d), (e) and (f) of
Regulation S-K
and contained under the heading Election of
Directors in the Notice of the 2012 Annual Meeting and
2012 Proxy Statement, to be filed pursuant to
Rule 14a-6(b)
under the Securities Exchange Act of 1934 (the Exchange
Act), in connection with the companys 2012 Annual
Meeting of Stockholders (the 2012 Proxy Statement),
is incorporated by reference into this Annual Report on
Form 10-K.
The information required by Item 405 of
Regulation S-K
and contained under the heading Stock Ownership
Information Section 16(a) Beneficial Ownership
Reporting Compliance in the 2012 Proxy Statement is
incorporated by reference into this Annual Report on
Form 10-K.
The information required by Item 406 of
Regulation S-K
and contained under the heading Board
Operations Business Conduct and Ethics Code in
the 2012 Proxy Statement is incorporated by reference into this
Annual Report on
Form 10-K.
35
The information required by Item 407(d)(4) and (5) of
Regulation S-K
and contained under the heading Board
Operations Board Committee Membership and
Functions in the 2012 Proxy Statement is incorporated by
reference into this Annual Report on
Form 10-K.
There were no changes to the process by which stockholders may
recommend nominees to the Board of Directors during the last
fiscal year.
|
|
Item 11.
|
Executive
Compensation
|
The information required by Item 402 of
Regulation S-K
and contained under the headings Executive
Compensation and Director Compensation in the
2012 Proxy Statement is incorporated by reference into this
Annual Report on
Form 10-K.
The information required by Item 407(e)(4) of
Regulation S-K
and contained under the heading Board
Operations Board Committee Membership and
Functions in the 2012 Proxy Statement is incorporated by
reference into this Annual Report on
Form 10-K.
The information required by Item 407(e)(5) of
Regulation S-K
and contained under the heading Board
Operations Management Compensation Committee
Report in the 2012 Proxy Statement is incorporated herein
by reference into this Annual Report on
Form 10-K.
Pursuant to the rules and regulations of the SEC under the
Exchange Act, the information under such caption incorporated by
reference from the 2012 Proxy Statement shall not be deemed to
be solicited material, or to be filed
with the Commission, or subject to Regulation 14A or 14C or
the liabilities of Section 18 of the Exchange Act nor shall
it be deemed incorporated by reference into any filing under the
Securities Act of 1933.
|
|
Item 12.
|
Security
Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
|
The information required by Item 403 of
Regulation S-K
and contained under the heading Stock Ownership
Information Security Ownership of Certain Beneficial
Owners and Management in the 2012 Proxy Statement is
incorporated by reference into this Annual Report on
Form 10-K.
The information required by Item 201(d) of
Regulation S-K
and contained under the heading Equity Compensation Plan
Information in the 2012 Proxy Statement is incorporated by
reference into this Annual Report on
Form 10-K.
|
|
Item 13.
|
Certain
Relationships and Related Transactions, and Director
Independence
|
The information required by Item 404 of
Regulation S-K
and contained under the heading Board
Operations Transactions with Related Persons
in the 2012 Proxy Statement is incorporated by reference into
this Annual Report on
Form 10-K.
The information required by Item 407(a) of
Regulation S-K
and contained under the heading Election of
Directors Independence of Directors in the
2012 Proxy Statement is incorporated by reference into this
Annual Report on
Form 10-K.
|
|
Item 14.
|
Principal
Accounting Fees and Services
|
The information required by Item 9(e) of Schedule 14A
and contained under the heading Proposal to Ratify the
Appointment of the Independent Registered Public Accounting
Firm in the 2012 Proxy Statement is incorporated by
reference into this Annual Report on
Form 10-K.
36
PART IV
|
|
Item 15.
|
Exhibits,
Financial Statement Schedules
|
(a) The following documents are filed as part of this
report:
(1) Financial
Statements:
|
|
|
|
|
Page(s)
|
|
|
|
FS-22
|
|
|
FS-23
|
|
|
FS-24
|
|
|
FS-25
|
|
|
FS-26
|
|
|
FS-27
|
|
|
FS-28 to FS-59
|
(2) Financial
Statement Schedules:
|
|
|
|
|
Included on page 38 is Schedule II
Valuation and Qualifying Accounts.
|
(3) Exhibits:
|
|
|
|
|
The Exhibit Index on pages
E-1 through
E-2 lists
the exhibits that are filed as part of this report.
|
37
Schedule
SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
Millions of Dollars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31
|
|
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
Employee Termination Benefits:
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1
|
|
$
|
145
|
|
|
$
|
13
|
|
|
$
|
44
|
|
Additions (deductions) charged (credited) to expense
|
|
|
|
|
|
|
235
|
|
|
|
(12
|
)
|
Payments
|
|
|
(82
|
)
|
|
|
(103
|
)
|
|
|
(19
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31
|
|
$
|
63
|
|
|
$
|
145
|
|
|
$
|
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for Doubtful Accounts:
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1
|
|
$
|
239
|
|
|
$
|
293
|
|
|
$
|
275
|
|
Additions (reductions) to expense
|
|
|
4
|
|
|
|
(13
|
)
|
|
|
92
|
|
Bad debt write-offs
|
|
|
(76
|
)
|
|
|
(41
|
)
|
|
|
(74
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31
|
|
$
|
167
|
|
|
$
|
239
|
|
|
$
|
293
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred Income Tax Valuation Allowance:*
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1
|
|
$
|
9,185
|
|
|
$
|
7,921
|
|
|
$
|
7,535
|
|
Additions to deferred income tax expense
|
|
|
2,216
|
|
|
|
1,454
|
|
|
|
2,204
|
|
Reduction of deferred income tax expense
|
|
|
(305
|
)
|
|
|
(190
|
)
|
|
|
(1,818
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31
|
|
$
|
11,096
|
|
|
$
|
9,185
|
|
|
$
|
7,921
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
See also Note 15 to the
Consolidated Financial Statements, beginning on
page FS-43.
|
38
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized, on the 23rd day of February,
2012.
Chevron Corporation
John S. Watson, Chairman of the Board
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the Registrant and in the capacities indicated on
the 23rd day of February, 2012.
|
|
|
Principal Executive Officers
|
|
|
(and Directors)
|
|
Directors
|
|
/s/John S. Watson
John S. Watson, Chairman of the
Board and Chief Executive Officer
|
|
Linnet F. Deily*
Linnet F. Deily
|
|
|
|
/s/George L.
Kirkland
George L. Kirkland, Vice Chairman
of the Board
|
|
Robert E. Denham*
Robert E. Denham
|
|
|
|
|
|
Robert J. Eaton*
Robert J. Eaton
|
|
|
|
|
|
Chuck Hagel*
Chuck Hagel
|
|
|
|
Principal Financial Officer
/s/Patricia E. Yarrington Patricia E. Yarrington, Vice President and Chief Financial Officer
Principal Accounting Officer
/s/Matthew J. Foehr Matthew J. Foehr, Vice President and Comptroller
|
|
Enrique Hernandez, Jr.* Enrique Hernandez, Jr.
Donald B. Rice* Donald B. Rice
Kevin W. Sharer* Kevin W. Sharer
Charles R. Shoemate* Charles R. Shoemate
John G. Stumpf* John G. Stumpf
|
|
|
|
*By: /s/Lydia I.
Beebe
Lydia I. Beebe,
Attorney-in-Fact
|
|
Ronald D. Sugar* Ronald D. Sugar
Carl Ware* Carl Ware
|
39
Financial Table of Contents
FS-2
FS-22
|
Consolidated Financial Statements |
|
|
|
|
|
|
|
FS-1
Managements Discussion and Analysis of
Financial Condition and Results of Operations
Key Financial Results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars, except per-share amounts |
|
2011 |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
Net Income Attributable to
Chevron Corporation |
|
$ |
26,895 |
|
|
|
$ |
19,024 |
|
|
$ |
10,483 |
|
Per Share Amounts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Attributable to |
|
|
|
|
|
|
|
|
|
|
|
|
|
Chevron Corporation |
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
13.54 |
|
|
|
$ |
9.53 |
|
|
$ |
5.26 |
|
Diluted |
|
$ |
13.44 |
|
|
|
$ |
9.48 |
|
|
$ |
5.24 |
|
Dividends |
|
$ |
3.09 |
|
|
|
$ |
2.84 |
|
|
$ |
2.66 |
|
Sales and Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues |
|
$ |
244,371 |
|
|
|
$ |
198,198 |
|
|
$ |
167,402 |
|
Return on: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Employed |
|
|
21.6 |
% |
|
|
|
17.4 |
% |
|
|
10.6 |
% |
Stockholders Equity |
|
|
23.8 |
% |
|
|
|
19.3 |
% |
|
|
11.7 |
% |
|
|
|
|
|
Earnings by Major Operating Area
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2011 |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
Upstream1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
6,512 |
|
|
|
$ |
4,122 |
|
|
$ |
2,262 |
|
International |
|
|
18,274 |
|
|
|
|
13,555 |
|
|
|
8,670 |
|
|
|
|
|
Total Upstream |
|
|
24,786 |
|
|
|
|
17,677 |
|
|
|
10,932 |
|
|
|
|
|
Downstream1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
1,506 |
|
|
|
|
1,339 |
|
|
|
(121 |
) |
International |
|
|
2,085 |
|
|
|
|
1,139 |
|
|
|
594 |
|
|
|
|
|
Total Downstream |
|
|
3,591 |
|
|
|
|
2,478 |
|
|
|
473 |
|
|
|
|
|
All Other |
|
|
(1,482 |
) |
|
|
|
(1,131 |
) |
|
|
(922 |
) |
|
|
|
|
Net Income Attributable to
Chevron Corporation2,3 |
|
$ |
26,895 |
|
|
|
$ |
19,024 |
|
|
$ |
10,483 |
|
|
|
|
|
|
1 2009 information has
been revised to conform with
the 2011 and 2010 segment
presentation. |
2 Includes foreign
currency effects: |
|
$ |
121 |
|
|
|
$ |
(423 |
) |
|
$ |
(744 |
) |
3 Also referred to as earnings in the discussions that follow. |
Refer to the Results of Operations section beginning on page FS-6 for a discussion of
financial results by major operating area for the three years ended December 31, 2011.
Business Environment and Outlook
Chevron is a global energy company with substantial business activities in the following
countries: Angola, Argentina, Australia, Azerbaijan, Bangladesh, Brazil, Cambodia, Canada, Chad,
China, Colombia, Democratic Republic of the Congo, Denmark, Indonesia, Kazakhstan, Myanmar, the
Netherlands, Nigeria, Norway, the Partitioned Zone between Saudi Arabia and Kuwait, the
Philippines, Republic of the Congo, Singapore, South Africa, South Korea, Thailand, Trinidad and
Tobago, the United Kingdom, the United States, Venezuela and Vietnam.
Earnings of the company depend mostly on the profitability of its upstream and downstream
business segments. The single biggest factor that affects the results of operations for the company
is movement in the price of crude oil. In the downstream business, crude oil is the largest cost
component
of refined products. Seasonality is not a primary driver of changes in the companys quarterly
earnings during the year.
To sustain its long-term competitive position in the upstream business, the company must
develop and replenish an inventory of projects that offer attractive financial returns for the
investment required. Identifying promising areas for exploration, acquiring the necessary rights to
explore for and to produce crude oil and natural gas, drilling successfully, and handling the many
technical and operational details in a safe and cost-effective manner are all important factors in
this effort. Projects often require long lead times and large capital commitments.
The companys operations, especially upstream, can also be affected by changing economic,
regulatory and political environments in the various countries in which it operates, including the
United States. From time to time, certain governments have sought to renegotiate contracts or
impose additional costs on the company. Governments may attempt to do so in the future. Civil
unrest, acts of violence or strained relations between a government and the company or other
governments may impact the companys operations or investments. Those developments have at times
significantly affected the companys operations and results and are carefully considered by
management when evaluating the level of current and future activity in such countries.
The company also continually evaluates opportunities to dispose of assets that are not
expected to provide sufficient long-term value or to acquire assets or operations complementary to
its asset base to help augment the companys financial performance and growth. Refer to the
Results of Operations section beginning on page FS-6 for discussions of net gains on asset sales
during 2011. Asset dispositions and restructurings may also occur in future periods and could
result in significant gains or losses.
The company closely monitors developments in the financial and credit markets, the level of
worldwide economic activity, and the implications for the company of movements in prices for crude
oil and natural gas. Management takes these developments into account in the conduct of daily
operations and for business planning.
Comments related to earnings trends for the companys major business areas are as follows:
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
FS-2
may be caused by military conflicts, civil unrest or political uncertainty. 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 seeks to
manage risks in operating its facilities and businesses. The longer-term trend in earnings for the
upstream segment is also a function of other factors, including the companys ability to find or
acquire and efficiently produce crude oil and natural gas, changes in fiscal terms of contracts,
and changes in tax laws and regulations.
The company continues to actively manage its schedule of work, contracting, procurement and
supply-chain activities to effectively manage costs. However, price levels for capital and
exploratory costs and operating expenses associated with the production of crude oil and natural
gas can be subject to external factors beyond the companys control. External factors include not
only the general level of inflation, but also commodity prices and prices charged by the industrys
material and service providers, which can be affected by the volatility of the industrys own
supply-and-demand conditions for such materials and services. Capital and exploratory expenditures
and operating expenses can also be affected by damage to production facilities caused by severe
weather or civil unrest.
The chart above shows the trend in benchmark prices for West Texas Intermediate (WTI) crude
oil, Brent crude oil and U.S. Henry Hub natural gas. The WTI price averaged $95 per barrel for the
full-year 2011, compared to $79 in 2010. As of mid-February 2012, the WTI price was about $99 per
barrel. The Brent price averaged $111 per barrel for the full-year 2011, compared to $80 in 2010.
As of mid-February 2012, the Brent price was about $118 per barrel. The majority of the companys
equity crude production is priced based on the Brent benchmark. WTI traded at a discount to Brent
throughout 2011 due to excess crude supply in the U.S. Midcontinent market. The discount narrowed
in fourth quarter 2011 as crude inventories declined.
A differential in crude oil prices exists between high quality (high-gravity, low-sulfur)
crudes and those of lower
quality (low-gravity, high-sulfur). The amount of the differential in any period is associated with
the supply of heavy crude available versus the demand, which is a function of the capacity of
refineries that are able to process this lower quality feedstock into light products (motor
gasoline, jet fuel, aviation gasoline and diesel fuel). The differential widened during 2011
primarily due to rising diesel prices and lower availability of light, sweet crude oil due to
supply disruptions in Libya.
Chevron produces or shares in the production of heavy crude oil in California, Chad,
Indonesia, the Partitioned Zone between Saudi Arabia and Kuwait, Venezuela and in certain fields in
Angola, China and the United Kingdom sector of the North Sea. (See page FS-10 for the companys
average U.S. and international crude oil realizations.)
In contrast to price movements in the global market for crude oil, price changes for natural
gas in many regional markets are more closely aligned with supply-and-demand conditions in those
markets. In the United States, prices at Henry Hub averaged about $4.00 per thousand cubic feet
(MCF) during 2011, compared with about $4.50 during 2010. As of mid-February 2012, the Henry Hub
spot price was about $2.50 per MCF. Fluctuations in the price for natural gas in the United States
are closely associated with customer demand relative to the volumes
produced in North America.
Outside the United States, price changes for natural gas depend on a wide range of supply,
demand and regulatory circumstances. In some locations, Chevron is investing in long-term projects
to install infrastructure to produce and liquefy natural gas for transport by tanker to other
markets. International natural gas realizations averaged about $5.40 per MCF during 2011, compared
with about $4.60 per MCF during 2010. (See page FS-10 for the companys average natural gas
realizations for the U.S. and international regions.)
FS-3
Managements Discussion and Analysis of
Financial Condition and Results of Operations
The companys worldwide net oil-equivalent production in 2011 averaged 2.673 million
barrels per day. About one-fifth of the companys net oil-equivalent production in 2011 occurred in
the OPEC-member countries of Angola, Nigeria, Venezuela and the Partitioned Zone between Saudi
Arabia and Kuwait. OPEC quotas had no effect on the companys net crude oil production in 2011 or
2010. At their December 2011 meeting, members of OPEC supported maintaining the current production
level of 30 million barrels per day and made no change to the production quotas in effect since
December 2008.
The company estimates that oil-equivalent production in 2012 will average approximately 2.680
million barrels per day based on the average Brent price of $111 per barrel for the full-year 2011.
This estimate is subject to many factors and uncertainties, including quotas that may be imposed by
OPEC, price effects on entitlement volumes, changes in fiscal terms or restrictions on the scope of
company operations, delays in project startups, fluctuations in demand for natural gas in various
markets, weather conditions that may shut in production, civil unrest, changing geopolitics, delays
in completion of maintenance turnarounds, greater-than-expected declines in production from mature
fields, or other disruptions to operations. The outlook for future production levels is also
affected by the size and number of economic investment opportunities and, for new large-scale
projects, the time lag between initial exploration and the beginning of production. Investments in
upstream projects generally begin well in advance of the start of the associated crude oil and
natural gas production. A significant majority of Chevrons upstream investment is made outside the
United States.
Refer to the Results of Operations section on pages FS-6 through FS-7 for additional
discussion of the companys upstream business.
Refer to Table V beginning on page FS-67 for a tabulation of the companys proved net oil and
gas reserves by geographic area, at the beginning of 2009 and each year-end from 2009 through 2011,
and an accompanying discussion of major changes to proved reserves by geographic area for the
three-year period ending December 31, 2011.
In early November 2011, while drilling a development well in the deepwater Frade Field in
Brazil, an unanticipated pressure spike caused oil to migrate from the well bore through a series
of fissures to the sea floor, emitting approximately 2,400 barrels of oil. The
resulting surface sheen has since dissipated and there have been no
coastal or wildlife impacts.
Upon detection, the company immediately took steps to stop the
release. Chevrons emergency plan,
approved by the Brazilian environment and natural resources regulatory agency IBAMA, was
implemented according to the law and industry standards. The
source of the seep was contained
within four days. As of December 31, 2011 the financial impact of the incident was not material to the companys annual net
income. However, the companys ultimate exposure related to fines and penalties is not currently
determinable, and could be significant to net income in any one period.
Downstream Earnings for the downstream segment are closely tied to margins on the refining,
manufacturing and marketing of products that include gasoline, diesel, jet fuel, lubricants, fuel
oil, fuel and lubricant additives, and petrochemicals. Industry margins are sometimes volatile and
can be affected by the global and regional supply-and-demand balance for refined products and
petrochemicals and by changes in the price of crude oil, other refinery and petrochemical
feedstocks, and natural gas. Industry margins can also be influenced by inventory levels,
geopolitical events, costs of materials and services, refinery or chemical plant capacity
utilization, maintenance programs, and disruptions at refineries or chemical plants resulting from
unplanned outages due to severe weather, fires or other operational events.
Other factors affecting profitability for downstream operations include the reliability and
efficiency of the companys refining, marketing and petrochemical assets, the effectiveness of its
crude oil and product supply functions, and 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 refining, marketing and petrochemical assets.
The companys most significant marketing areas are the West Coast of North America, the U.S.
Gulf Coast, Asia, and southern Africa. Chevron operates or has significant ownership interests in
refineries in each of these areas. In 2011, the companys margins improved over 2010, supported by
higher global product demand and tighter global refined product supplies. The company made further
progress during 2011 implementing the previously-announced restructuring of its downstream
businesses, including the employee-reduction programs for the United States and international
operations. Approximately 2,300 employees in the downstream operations are currently expected to be
released under these programs. About 2,100 employees have been released through December 31, 2011,
with the programs being substantially completed. Substantially all of the remaining employees
designated for release under the programs are expected to leave in 2012. About 900 of the affected
employees were located in the United States. Refer to Note 23 of the Consolidated Financial
Statements, on pages FS-55 through FS-56, for further discussion.
FS-4
The company progressed its ongoing effort to concentrate downstream resources and capital on
strategic assets. On August 1, 2011, the company completed the sale of its 220,000-barrel-per-day
Pembroke Refinery and its fuels marketing and aviation assets in the United Kingdom and Ireland.
Through year-end 2011, the company had also completed the sale of 13 U.S. terminals, certain
marketing businesses in Africa, LPG storage and distribution operations in China, and its fuels
marketing and aviation businesses in 16 countries in the Caribbean and Latin America regions. In
2012, the company also expects to complete the sale of its fuels, finished lubricants and aviation
businesses in Spain and certain fuels marketing and aviation businesses in the central Caribbean,
pending customary regulatory approvals.
Also in 2011, Caltex Australia Ltd. (CAL), the companys 50 percent-owned affiliate, initiated
a review of its refining operations in Australia, which is ongoing. Upon completion, should the
review result in a decision to significantly alter the operational role of CALs refineries,
Chevron may recognize a loss that could be significant to net income in any one period.
Refer to the Results of Operations section on pages FS-7 through FS-8 for additional
discussion of the companys downstream operations.
All Other consists of mining operations, power generation businesses, worldwide cash
management and debt financing activities, corporate administrative functions, insurance operations,
real estate activities, energy services, alternative fuels, and technology companies. In first
quarter 2010, employee-reduction programs were announced for the corporate staffs. As of 2011
year-end, 400 employees from the corporate staffs were released under the programs. Refer to Note
23 of the Consolidated Financial Statements, beginning on page FS-55, for further discussion.
Operating Developments
Key operating developments and other events during 2011 and early 2012 included the
following:
Upstream
Australia Chevron and its joint-venture partners reached the final investment decision to proceed
with development of the Wheatstone Project. Construction started in late 2011. Chevron holds a 72.1
percent interest in the foundation natural gas processing facilities, which are located at
Ashburton North, along the northwest coast of Australia. The company plans to supply natural gas to
the foundation project from the Chevron-operated and 90.2 percent-owned Wheatstone and Iago fields.
The LNG facilities will also be a destination for third-party natural gas.
Through the end of 2011, Chevron has signed binding Sales and Purchase Agreements with two
Asian customers for the delivery of about 60 percent of
Chevrons net LNG off-take from the
Wheatstone Project. Discussions continue with potential customers to increase sales to 85 to 90
percent of Chevrons net LNG off-take and to sell down equity.
During 2011, the company announced natural gas discoveries at the 50 percent-owned and
operated Orthrus Deep prospect in Block WA-24-R, the 50 percent-owned and operated Vos prospect in
Block WA-439-P, and the 67 percent-
owned and operated Acme West prospect in Block WA-205-P. In January 2012, the company also
announced a natural gas discovery at the 50 percent-owned and operated Satyr-3 prospect in Block
WA-374-P. These discoveries are expected to contribute to potential expansion at company-operated
LNG projects.
Kazakhstan/Russia During 2011, the Caspian Pipeline Consortium began construction on a project
to increase the pipeline design capacity by 670,000 barrels per day. The project is expected to be
implemented in three phases, with capacity increasing progressively until reaching maximum capacity
of 1.4 million barrels per day in 2016.
Nigeria In December 2011, a final investment decision was reached to develop the 40
percent-owned and operated Sonam natural gas field in the Escravos area. The project is designed
to deliver 215 million cubic feet of natural gas per day to the domestic market and produce
30,000 barrels of liquids per day.
Thailand In October 2011, the 69.9 percent-owned and operated Platong II natural gas project
commenced production. The project ramped up to total average daily production of 377 million cubic
feet of natural gas and 11,000 barrels of condensate as of the end of 2011.
United Kingdom In fourth quarter 2011, the company reached a final investment decision for the
Clair Ridge Project, located west of the Shetland Islands. Chevron has a 19.4 percent nonoperated
working interest in the project.
United States In fourth quarter 2011, a final investment decision was made for the Tubular
Bells project in the deepwater Gulf of Mexico. The development includes a 42.9 percent nonoperated
working interest in the Tubular Bells unitized area.
Drilling operations at the 43.8 percent-owned and operated Moccasin prospect resulted in a new
discovery of crude oil. The company also drilled a successful appraisal well at the 55
percent-owned Buckskin prospect. Both prospects are in the deepwater Gulf of Mexico.
In February 2011, Chevron acquired Atlas Energy, Inc. The acquisition provided a natural gas
resource position in the Marcellus Shale and Utica Shale, primarily located in southwestern
Pennsylvania and Ohio. The acquisition also provided a 49 percent interest in Laurel Mountain
Midstream, LLC, an affiliate that owns more than 1,000 miles of natural gas gathering lines
servicing the Marcellus. In addition, the acquisition provided assets in Michigan, which include
Antrim Shale producing assets and approximately
FS-5
Managements Discussion and Analysis of
Financial Condition and Results of Operations
350,000 total acres in the Antrim and Collingwood/Utica Shale formations. Additional asset
acquisitions in 2011 expanded the companys holdings in the Marcellus and Utica to approximately
700,000 and 600,000 total acres, respectively.
Downstream
Africa During 2011, the company completed the sale of certain marketing businesses in five
countries in Africa.
Caribbean and Latin America In 2011, the company completed the sale of its fuels marketing and
aviation businesses in 16 countries in the Caribbean and Latin America. In fourth quarter 2011, the
company signed agreements to sell certain fuels marketing and aviation businesses in the Central
Caribbean. The company expects to complete these sales in 2012 following receipt of required local
regulatory and government approvals.
Europe In August 2011, the company completed the sale of its refining and marketing assets in
the United Kingdom and Ireland, including the Pembroke Refinery.
Singapore In February 2012, the company reached a final investment decision to significantly
increase the capacity of the existing additives plant in Singapore.
United States In January 2011, the company announced the final investment decision on a $1.4
billion project to construct a base oil manufacturing facility at the Pascagoula,
Mississippi, refinery. The facility is expected to produce approximately 25,000 barrels per
day of premium base oil.
Other
Common Stock Dividends The quarterly common stock dividend increased by 8.3 percent in April
2011 and by 3.8 percent in October 2011, to $0.81 per common share, making 2011 the 24th
consecutive year that the company increased its annual dividend payment.
Common Stock Repurchase Program The company purchased $4.25 billion of its common stock in
2011 under its share repurchase program. The program began in 2010 and has no set term or monetary
limits.
Results of Operations
Major Operating Areas The following section presents the results of operations for the
companys business segments Upstream and Downstream as well as for All Other. Earnings are
also presented for the U.S. and international geographic areas of the Upstream and Downstream
business segments. (Refer to Note 11, beginning on page FS-37, for a discussion of the companys
reportable segments, as defined in accounting standards for segment reporting (Accounting
Standards Codification (ASC) 280). This section should also be read in conjunction with the
discussion in Business Environment and Outlook on pages
FS-2
through FS-5.
U.S. Upstream
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2011 |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
Earnings |
|
$ |
6,512 |
|
|
|
$ |
4,122 |
|
|
$ |
2,262 |
|
|
|
|
|
U.S. upstream earnings of $6.51 billion in 2011 increased $2.4 billion from 2010. The
benefit of higher crude oil realizations increased earnings by $2.8 billion between periods. Partly
offsetting this effect were lower net oil-equivalent production which decreased earnings by about
$400 million and higher operating expenses of $200 million.
U.S. upstream earnings of $4.1 billion in 2010 increased $1.9 billion from 2009. Higher prices
for crude oil and natural gas increased earnings by $2.1 billion between periods. Partly offsetting
these effects were higher operating expenses of $200 million, in part due to the Gulf of Mexico
drilling moratorium. Lower exploration expenses were essentially offset by higher tax items and
higher depreciation expenses.
The companys average realization for U.S. crude oil and natural gas liquids in 2011 was
$97.51 per barrel, compared with $71.59 in 2010 and $54.36 in 2009. The average natural gas
realization was $4.04 per thousand cubic feet in 2011, compared with $4.26 and $3.73 in 2010 and
2009, respectively.
Net oil-equivalent production in 2011 averaged 678,000 barrels per day, down 4 percent from
2010 and 5 percent from 2009. Between 2011 and 2010, the decrease in production was associated with
normal field declines and maintenance-related downtime. Partially offsetting this decrease were new
production from acquisitions in the Marcellus Shale and increases at the Perdido project in the
Gulf of Mexico. Natural field declines between 2010 and 2009 were
FS-6
mostly offset by increased production from the Tahiti Field. The net liquids component of
oil-equivalent production for 2011 averaged 465,000 barrels per day, down 5 percent from 2010 and 4
percent from 2009. Net natural gas production averaged about 1.3 billion cubic feet per day in
2011, down approximately 3 percent from 2010 and about 9 percent from 2009. Refer to the Selected
Operating Data table on page FS-10 for a three-year comparative of production volumes in the
United States.
International Upstream
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2011 |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
Earnings* |
|
$ |
18,274 |
|
|
|
$ |
13,555 |
|
|
$ |
8,670 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*Includes foreign currency effects: |
|
|
$ 211 |
|
|
|
|
$ (293 |
) |
|
|
$ (578 |
) |
International upstream earnings of $18.3 billion in 2011 increased $4.7 billion from
2010. Higher prices for crude oil increased earnings by $7.1 billion. This benefit was partly
offset by higher tax items of about $1.7 billion and higher operating expenses, including fuel, of
about $1.0 billion. Foreign currency effects increased earnings by $211 million in 2011, compared
with a decrease of $293 million a year earlier.
Earnings of $13.6 billion in 2010 increased $4.9 billion from 2009. Higher prices for crude
oil and natural gas increased earnings by $4.3 billion, and an increase in net oil-equivalent
production in the 2010 period benefited income by about $1.2 billion. This net benefit was partly
offset by higher operating expenses of $500 million. A favorable change in tax items of about $450
million was mostly offset by higher depreciation expenses. The 2009 period included gains of about
$500 million on asset sales and tax items related to the Gorgon Project in Australia. Foreign
currency effects decreased earnings by $293 million in the 2010 period, compared with a reduction
of $578 million a year earlier, primarily reflecting noncash losses on balance sheet remeasurement.
The companys average realization for international crude oil and natural gas liquids in 2011
was $101.53 per barrel, compared with $72.68 in 2010 and $55.97 in 2009. The average natural gas
realization was $5.39 per thousand cubic feet in 2011, compared with $4.64 and $4.01 in 2010 and
2009, respectively.
International net oil-equivalent production of 2.0 million barrels per day in 2011 decreased
about 3 percent from
2010 and remained relatively flat with 2009. The volumes in 2011 and 2010 include synthetic oil that was
reported in 2009 as production from oil sands in Canada. Absent price effects on entitlement
volumes, net oil-equivalent production decreased 1 percent in 2011 and increased 5 percent in 2010,
when compared with the prior years production.
The net liquids component of international oil-equivalent production was about 1.4 million
barrels per day in 2011, a decrease of approximately 3 percent from 2010 and an increase of
approximately 2 percent from 2009. International net natural gas production of 3.7 billion cubic
feet per day in 2011 was down 2 percent from 2010 and up 2 percent from 2009.
Refer to the Selected Operating Data table, on page FS-10, for a three-year comparative of
international production volumes.
U.S. Downstream
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2011 |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
Earnings |
|
$ |
1,506 |
|
|
|
$ |
1,339 |
|
|
$ |
(121 |
) |
|
|
|
|
U.S. downstream operations earned $1.5 billion in 2011, compared with $1.3 billion in
2010. Earnings benefited by $300 million from improved margins on refined products, $200 million
from higher earnings from the 50 percent-owned Chevron Phillips Chemical Company LLC (CPChem), and
$50 million from the absence of 2010 charges related to employee reductions. These benefits were
partly offset by the absence of a $400 million gain on the sale of the companys ownership interest
in the Colonial Pipeline Company recognized in 2010.
Earnings increased $1.5 billion in 2010 from 2009. Improved margins on refined products
increased earnings by about $550 million. Also contributing to the increase was the nearly $400
million gain on the sale of the companys ownership interest in the Colonial Pipeline Company.
Higher earnings from chemicals operations increased earnings by about $300 million, largely from
improved margins at CPChem.
Refined product sales of 1.26 million barrels per day in 2011 declined 7 percent, mainly due
to lower gasoline, gas oil, and kerosene sales. Sales volumes of refined products were 1.35 million
barrels per day in 2010, a decrease of 4 percent from 2009. The decline was mainly in gasoline and
jet fuel sales. U.S. branded gasoline sales decreased to 514,000 barrels per day in 2011,
representing approximately 10 percent and 17 percent declines from 2010 and 2009, respectively. The
decline in 2011, relative to 2010 and 2009, was primarily
FS-7
Managements Discussion and Analysis of
Financial Condition and Results of Operations
due to weaker demand and previously completed exits from selected eastern U.S. retail
markets.
Refer to the Selected Operating Data table on page FS-10 for a three-year comparison of
sales volumes of gasoline and other refined products and refinery input volumes.
International Downstream
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2011 |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
Earnings* |
|
$ |
2,085 |
|
|
|
$ |
1,139 |
|
|
$ |
594 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*Includes foreign currency effects: |
|
$ |
(65 |
) |
|
|
$ |
(135 |
) |
|
$ |
(191 |
) |
International downstream earned $2.1 billion in 2011, compared with $1.1 billion in
2010. Gains on asset sales benefited earnings by $700 million, primarily from the sale of the
Pembroke Refinery and related marketing assets in the United Kingdom and Ireland. Also contributing
to earnings were improved margins of $200 million and the absence of 2010 charges of $90 million
related to employee reductions. These benefits were partly offset by unfavorable mark-to-market
effects of derivative instruments of about $180 million. Foreign currency effects decreased
earnings by $65 million in 2011, compared with a decrease of $135 million a year earlier.
Earnings of $1.1 billion in 2010 increased $545 million from 2009. Higher margins on the
manufacture and sale of gasoline and other refined products increased earnings by about $1.0
billion, and a favorable swing in mark-to-market
effects on derivative instruments benefited
earnings by about $300 million. Partially offsetting these items was the absence of 2009 gains on
asset sales of about $550 million and higher expenses of about $200 million, primarily related to
employee reductions and transportation costs. Foreign currency effects reduced earnings by $135
million in 2010, compared with a reduction of $191 million in 2009.
Total refined product sales of 1.69 million barrels per day in 2011
declined 4 percent, primarily due to the sale of the companys refining
and marketing assets in the United Kingdom and Ireland. Excluding the
impact of 2011 asset
sales, sales volumes were up 3 percent between the comparative periods. International refined
product sales volumes of 1.76 million barrels per day in 2010 were 5 percent lower than in 2009,
mainly due to asset sales in certain countries in Africa and Latin America.
Refer to the Selected Operating Data table, on page FS-10, for a three-year comparison of
sales volumes of gasoline and other refined products and refinery input volumes.
All Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2011 |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
Net charges* |
|
$ |
(1,482 |
) |
|
|
$ |
(1,131 |
) |
|
$ |
(922 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*Includes foreign currency effects: |
|
$ |
(25 |
) |
|
|
$ |
5 |
|
|
$ |
25 |
|
All Other includes mining operations, power generation businesses, worldwide cash
management and debt financing activities, corporate administrative functions, insurance operations,
real estate activities, energy services, alternative fuels, and technology companies.
Net charges in 2011 increased $351 million from 2010, mainly due to higher expenses for
employee compensation and benefits, and higher net corporate tax expenses.
Net charges in 2010 increased $209 million from 2009, mainly due to higher expenses for
employee compensation and benefits, and higher corporate tax expenses, partly offset by lower
provisions for environmental remediation at sites that previously had been closed or sold.
Consolidated Statement of Income
Comparative amounts for certain income statement categories are shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2011 |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
Sales and other operating revenues |
|
$ |
244,371 |
|
|
|
$ |
198,198 |
|
|
$ |
167,402 |
|
|
|
|
|
Sales and other operating revenues increased in 2011, mainly due to higher prices for
crude oil and refined products. Higher 2010 prices resulted in increased revenues compared with
2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2011 |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
Income from equity affiliates |
|
$ |
7,363 |
|
|
|
$ |
5,637 |
|
|
$ |
3,316 |
|
|
|
|
|
Income from equity affiliates increased in 2011 from 2010 mainly due to higher
upstream-related earnings from Tengizchevroil (TCO) in Kazakhstan as a result of higher prices for
crude oil. Downstream-related earnings were also higher between the comparative periods, primarily
due to higher earnings from CPChem as a result of higher margins on sales of commodity chemicals.
Income from equity affiliates increased in 2010 from 2009 largely due to higher
upstream-related earnings from
FS-8
TCO in Kazakhstan and Petropiar in Venezuela, principally related to higher prices for crude oil
and increased crude oil production. Downstream-related affiliate earnings were also higher between
the comparative periods, primarily due to higher earnings from CPChem, as a result of higher
margins on sales of commodity chemicals. Improved margins on refined products and a favorable swing
in foreign currency effects at GS Caltex in South Korea also contributed to the increase in
downstream affiliate earnings in the 2010 period. Refer to Note 12, beginning on page FS-39, for a
discussion of Chevrons investments in affiliated companies.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2011 |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
Other income |
|
$ |
1,972 |
|
|
|
$ |
1,093 |
|
|
$ |
918 |
|
|
|
|
|
Other income of $2.0 billion in 2011 included net gains of approximately $1.5 billion on
asset sales. Other income in both 2010 and 2009 included net gains from asset sales of $1.1 billion
and $1.3 billion, respectively. Interest income was
approximately $145 million in 2011, $120 million
in 2010 and $95 million in 2009. Foreign currency effects increased other income by $103 million in
2011, while decreasing other income by $251 million and $466 million in 2010 and 2009,
respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2011 |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
Purchased crude oil and products |
|
$ |
149,923 |
|
|
|
$ |
116,467 |
|
|
$ |
99,653 |
|
|
|
|
|
Crude oil and product purchases in 2011 and 2010 increased by $33.5 billion and $16.8
billion from prior years due to higher prices for crude oil, natural gas and refined products.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2011 |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
Operating, selling, general and
administrative expenses |
|
$ |
26,394 |
|
|
|
$ |
23,955 |
|
|
$ |
22,384 |
|
|
|
|
|
Operating, selling, general and administrative expenses increased $2.4 billion between
2011 and 2010. This increase was primarily related to higher fuel expenses of $1.5 billion and
higher employee compensation and benefits of $700 million. In part, increased fuel purchases
reflected a new commercial arrangement that replaced a prior product exchange agreement for
upstream operations in Indonesia.
Total expenses in 2010 were about $1.6 billion higher than 2009, primarily due to $600 million
of higher fuel expenses; $500 million for employee compensation and benefits; $200 million of
increased construction, repair and maintenance expense; and an increase of about $200 million
associated with higher tanker charter rates. In addition, charges of $234 million related to
employee reductions were included in the 2010 period.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2011 |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
Exploration expense |
|
$ |
1,216 |
|
|
|
$ |
1,147 |
|
|
$ |
1,342 |
|
|
|
|
|
Exploration expenses in 2011 increased from 2010 mainly due to higher geological and
geophysical costs, partly offset by lower well write-offs.
Exploration expenses in 2010 declined from 2009 mainly due to lower amounts for geological and
geophysical costs and well write-offs.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2011 |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
Depreciation,
depletion and
amortization |
|
$ |
12,911 |
|
|
|
$ |
13,063 |
|
|
$ |
12,110 |
|
|
|
|
|
The decrease in 2011 from 2010 mainly reflected lower production levels and the sale of
the Pembroke Refinery, partially offset by higher depreciation rates for certain oil and gas
producing fields. The increase in 2010 from 2009 was largely due to higher depreciation rates and
higher production for certain oil and gas fields, partly offset by lower impairments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2011 |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
Taxes other than on income |
|
$ |
15,628 |
|
|
|
$ |
18,191 |
|
|
$ |
17,591 |
|
|
|
|
|
Taxes other than on income decreased in 2011 from 2010 primarily due to lower import
duties in the United Kingdom reflecting the sale of the Pembroke Refinery and other downstream
assets, partly offset by higher excise taxes in the companys South Africa downstream operations.
Taxes other than on income increased in 2010 from 2009 mainly due to higher excise taxes in Canada
and the United Kingdom.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2011 |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
Interest and debt expense |
|
$ |
|
|
|
|
$ |
50 |
|
|
$ |
28 |
|
|
|
|
|
Interest and debt expense, net of capitalized interest, decreased in 2011 from 2010 due
to lower average effective interest rates. The increase in 2010 from 2009 was primarily due
to slightly higher average effective interest rates.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2011 |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
Income tax expense |
|
$ |
20,626 |
|
|
|
$ |
12,919 |
|
|
$ |
7,965 |
|
|
|
|
|
Effective income tax rates were 43 percent in 2011, 40 percent in 2010 and 43 percent in
2009. The rate was higher in 2011 than in 2010 primarily due to higher effective tax rates in
certain international upstream jurisdictions. The higher international upstream effective tax rates
were driven primarily by lower utilization of non-U.S. tax credits in 2011 and the effect of changes
in income tax rates between periods, which were partially offset by foreign currency remeasurement
impacts. The rate was lower in 2010 than in 2009 primarily due to international upstream effects,
including an increased utilization of tax credits, which had a greater impact on the rate than
one-time deferred tax benefits and relatively low tax rates on asset sales in 2009. Also, a smaller
portion of company income was earned in higher tax rate international upstream jurisdictions in
2010 than in 2009. Finally, foreign currency remeasurement impacts caused a reduction in the
effective tax rate between periods.
FS-9
Managements Discussion and Analysis of
Financial Condition and Results of Operations
Selected Operating Data1,2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011 |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
U.S. Upstream |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Crude Oil and Natural Gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
Liquids Production (MBPD) |
|
|
465 |
|
|
|
|
489 |
|
|
|
484 |
|
Net Natural Gas Production (MMCFPD)3 |
|
|
1,279 |
|
|
|
|
1,314 |
|
|
|
1,399 |
|
Net Oil-Equivalent Production (MBOEPD) |
|
|
678 |
|
|
|
|
708 |
|
|
|
717 |
|
Sales of Natural Gas (MMCFPD) |
|
|
5,836 |
|
|
|
|
5,932 |
|
|
|
5,901 |
|
Sales of Natural Gas Liquids (MBPD) |
|
|
15 |
|
|
|
|
22 |
|
|
|
17 |
|
Revenues From Net Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
Liquids ($/Bbl) |
|
$ |
97.51 |
|
|
|
$ |
71.59 |
|
|
$ |
54.36 |
|
Natural Gas ($/MCF) |
|
$ |
4.04 |
|
|
|
$ |
4.26 |
|
|
$ |
3.73 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International Upstream |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Crude Oil and Natural Gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
Liquids Production (MBPD)4 |
|
|
1,384 |
|
|
|
|
1,434 |
|
|
|
1,362 |
|
Net Natural Gas Production (MMCFPD)3 |
|
|
3,662 |
|
|
|
|
3,726 |
|
|
|
3,590 |
|
Net Oil-Equivalent |
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (MBOEPD)5 |
|
|
1,995 |
|
|
|
|
2,055 |
|
|
|
1,987 |
|
Sales of Natural Gas (MMCFPD) |
|
|
4,361 |
|
|
|
|
4,493 |
|
|
|
4,062 |
|
Sales of Natural Gas Liquids (MBPD) |
|
|
24 |
|
|
|
|
27 |
|
|
|
23 |
|
Revenues From Liftings |
|
|
|
|
|
|
|
|
|
|
|
|
|
Liquids ($/Bbl) |
|
$ |
101.53 |
|
|
|
$ |
72.68 |
|
|
$ |
55.97 |
|
Natural Gas ($/MCF) |
|
$ |
5.39 |
|
|
|
$ |
4.64 |
|
|
$ |
4.01 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Worldwide Upstream |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Oil-Equivalent Production
(MBOEPD)3,5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
678 |
|
|
|
|
708 |
|
|
|
717 |
|
International |
|
|
1,995 |
|
|
|
|
2,055 |
|
|
|
1,987 |
|
|
|
|
|
|
|
Total |
|
|
2,673 |
|
|
|
|
2,763 |
|
|
|
2,704 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Downstream |
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline Sales (MBPD)6 |
|
|
649 |
|
|
|
|
700 |
|
|
|
720 |
|
Other Refined Product Sales (MBPD) |
|
|
608 |
|
|
|
|
649 |
|
|
|
683 |
|
|
|
|
|
|
|
Total Refined Product Sales (MBPD) |
|
|
1,257 |
|
|
|
|
1,349 |
|
|
|
1,403 |
|
Sales of Natural Gas Liquids (MBPD) |
|
|
146 |
|
|
|
|
139 |
|
|
|
144 |
|
Refinery Input (MBPD) |
|
|
854 |
|
|
|
|
890 |
|
|
|
899 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International Downstream |
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline Sales (MBPD)6 |
|
|
447 |
|
|
|
|
521 |
|
|
|
555 |
|
Other Refined Product Sales (MBPD) |
|
|
1,245 |
|
|
|
|
1,243 |
|
|
|
1,296 |
|
|
|
|
|
|
|
Total Refined Product Sales (MBPD)7 |
|
|
1,692 |
|
|
|
|
1,764 |
|
|
|
1,851 |
|
Sales of Natural Gas Liquids (MBPD) |
|
|
63 |
|
|
|
|
78 |
|
|
|
88 |
|
Refinery Input (MBPD) |
|
|
933 |
|
|
|
|
1,004 |
|
|
|
979 |
|
|
|
|
|
|
|
|
1 |
|
Includes company share of equity affiliates. |
|
2 |
|
MBPD thousands of barrels per day; MMCFPD
millions of cubic feet per day; MBOEPD
thousands of barrels of oil-equivalents per day; Bbl Barrel; MCF = Thousands of cubic feet.
Oil-equivalent gas (OEG) conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of
oil. |
|
3 |
|
Includes natural gas consumed in operations (MMCFPD): |
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
69 |
|
|
|
62 |
|
|
|
58 |
|
International |
|
|
513 |
|
|
|
475 |
|
|
|
463 |
|
4 Includes: Canada synthetic oil |
|
|
40 |
|
|
|
24 |
|
|
|
|
|
Venezuela affiliate synthetic oil |
|
|
32 |
|
|
|
28 |
|
|
|
|
|
5 Includes Canada oil sands |
|
|
|
|
|
|
|
|
|
|
26 |
|
6 Includes branded and unbranded gasoline. |
|
|
|
|
|
|
|
|
|
|
|
|
7 Includes sales of affiliates (MBPD): |
|
|
556 |
|
|
|
562 |
|
|
|
516 |
|
Liquidity and Capital Resources
Cash, cash equivalents, time deposits and marketable securities Total balances were $20.1 billion
and $17.1 billion at December 31, 2011 and 2010, respectively. Cash provided by operating
activities in 2011 was $41.1 billion, compared with $31.4 billion in 2010 and $19.4 billion in
2009. Cash provided by operating activities was net of contributions to employee pension plans of
approximately $1.5 billion, $1.4 billion and $1.7 billion in 2011, 2010 and 2009, respectively.
Cash provided by operating activities during 2011 was more than sufficient to fund the $27.4
billion cash component of the companys capital and exploratory program and pay $6.1 billion of
dividends to shareholders. In addition, the company completed the $4.5 billion acquisition of Atlas
Energy, Inc., funded from the companys operating cash flows. Cash provided by investing activities
included proceeds and deposits related to asset sales of $3.5 billion in 2011, $2.0 billion in
2010, and $2.6 billion in 2009.
Restricted cash of $1.2 billion and $855 million associated with various capital-investment
projects, acquisitions pending tax deferred exchanges, and Upstream abandonment activities at
December 31, 2011 and 2010, respectively, was invested in short-term marketable securities and
recorded as Deferred charges and other assets on the Consolidated Balance Sheet.
Dividends Dividends paid to common stockholders were approximately $6.1 billion in 2011, $5.7
billion in 2010 and $5.3 billion in 2009. In October 2011, the company increased its quarterly
dividend by 3.8 percent to 81 cents per common share. This followed an increase of 8.3 percent
announced in second quarter 2011.
FS-10
Capital and Exploratory Expenditures
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011 |
|
|
|
2010 |
|
|
|
2009 |
|
Millions of dollars |
|
U.S. |
|
|
Intl. |
|
|
Total |
|
|
|
U.S. |
|
|
Intl. |
|
|
Total |
|
|
|
U.S. |
|
|
Intl. |
|
|
Total |
|
|
|
|
|
|
|
|
Upstream1 |
|
$ |
8,318 |
|
|
$ |
17,554 |
|
|
$ |
25,872 |
|
|
|
$ |
3,450 |
|
|
$ |
15,454 |
|
|
$ |
18,904 |
|
|
|
$ |
3,294 |
|
|
$ |
15,002 |
|
|
$ |
18,296 |
|
Downstream |
|
|
1,461 |
|
|
|
1,150 |
|
|
|
2,611 |
|
|
|
|
1,456 |
|
|
|
1,096 |
|
|
|
2,552 |
|
|
|
|
2,087 |
|
|
|
1,449 |
|
|
|
3,536 |
|
All Other |
|
|
575 |
|
|
|
8 |
|
|
|
583 |
|
|
|
|
286 |
|
|
|
13 |
|
|
|
299 |
|
|
|
|
402 |
|
|
|
3 |
|
|
|
405 |
|
|
|
|
|
|
|
|
Total |
|
$ |
10,354 |
|
|
$ |
18,712 |
|
|
$ |
29,066 |
|
|
|
$ |
5,192 |
|
|
$ |
16,563 |
|
|
$ |
21,755 |
|
|
|
$ |
5,783 |
|
|
$ |
16,454 |
|
|
$ |
22,237 |
|
|
|
|
|
|
|
|
Total, Excluding Equity in Affiliates |
|
$ |
10,077 |
|
|
$ |
17,294 |
|
|
$ |
27,371 |
|
|
|
$ |
4,934 |
|
|
$ |
15,433 |
|
|
$ |
20,367 |
|
|
|
$ |
5,558 |
|
|
$ |
15,094 |
|
|
$ |
20,652 |
|
|
|
|
|
|
|
|
1
Excludes the acquisition of Atlas Energy, Inc. in 2011.
Debt and capital lease obligations Total debt and capital lease
obligations were $10.2 billion at December 31, 2011, down from $11.5 billion at year-end 2010.
The $1.3 billion decrease in total debt and capital lease obligations during 2011 included the
early redemption of a $1.5 billion bond due to mature in March 2012. The companys debt and capital
lease obligations due within one year, consisting primarily of commercial paper, redeemable
long-term obligations and the current portion of long-term debt, totaled $5.9 billion at December
31, 2011, compared with $5.6 billion at year-end 2010. Of these amounts, $5.6 billion and $5.4
billion were reclassified to long-term at the end of each period, respectively. At year-end 2011,
settlement of these obligations was not expected to require the use of working capital in 2012, as
the company had the intent and the ability, as evidenced by committed credit facilities, to
refinance them on a long-term basis.
At December 31, 2011, the company had $6.0 billion in committed credit facilities with various
major banks, expiring in December 2016, which enable the refinancing of short-term obligations on a
long-term basis. These facilities support commercial paper borrowing and can also be used for
general corporate purposes. The companys practice has been to continually replace expiring
commitments with new commitments on substantially the same terms, maintaining levels management
believes appropriate. Any borrowings under the facilities would be unsecured indebtedness at
interest rates based on the London Interbank Offered Rate or an average of base lending rates
published by specified banks and on terms reflecting the companys strong credit rating. No
borrowings were outstanding under these facilities at December 31, 2011. In addition, the company
has an automatic shelf registration statement that expires in March 2013 for an unspecified amount
of nonconvertible debt securities issued or guaranteed by the company.
The major debt rating agencies routinely evaluate the companys debt, and the companys cost
of borrowing can increase or decrease depending on these debt ratings. The company has outstanding
public bonds issued by Chevron Corporation, Chevron Corporation Profit Sharing/Savings Plan Trust
Fund and Texaco Capital Inc. All of these securities are the obligations of, or guaranteed by,
Chevron Corporation and are rated AA by Standard and Poors
Corporation and Aa1 by Moodys
Investors Service. The companys U.S. commercial paper is rated A-1+ by Standard and Poors and P-l
by Moodys. All of these ratings denote high-quality, investment-grade securities.
The companys future debt level is dependent primarily on results of operations, the capital
program and cash that
may be generated from asset dispositions. Based on its high-quality
debt ratings, the company believes that it has substantial borrowing capacity to meet unanticipated
cash requirements. The company also can modify capital spending plans during any extended periods
of low prices for crude oil and natural gas and narrow margins for refined products and commodity
chemicals to provide flexibility to continue paying the common stock dividend and maintain the
companys high-quality debt ratings.
Common stock repurchase program In July 2010, the Board of Directors approved an
ongoing share repurchase program with no set term or monetary limits. The company expects to
repurchase between $500 million and $2 billion of its common shares per quarter, at prevailing
prices, as permitted by securities laws and other legal requirements and subject to market
conditions and other factors. During 2011, the company purchased 42.3 million common shares for
$4.25 billion. From the inception of the program through 2011, the company had purchased 51.1
million shares for $5.0 billion.
Capital and exploratory expenditures Total expenditures for 2011 were $29.1
billion, including $1.7 billion for the companys share of equity-affiliate expenditures.
In 2010
and 2009,
expenditures were $21.8 billion and $22.2 billion, respectively, including the companys
share of affiliates expenditures of $1.4 billion and $1.6 billion, respectively.
Of the $29.1 billion of expenditures in 2011, 89 percent, or $25.9
billion, was related to upstream activities. Approximately 87 percent
and 80 percent were expended for upstream operations in 2010 and 2009.
International upstream accounted for about 68 percent of the worldwide
upstream investment in 2011, about 82 percent in 2010 and about 80
percent in 2009. These amounts exclude the acquisition of Atlas Energy,
Inc. in 2011.
The company estimates that in 2012 capital and exploratory expenditures will be $32.7 billion,
including $3.0 billion of spending
FS-11
Managements Discussion and Analysis of
Financial Condition and Results of Operations
by affiliates. Approximately 87 percent of the total, or $28.5 billion, is budgeted for exploration
and production activities. Approximately $22.3 billion, or 78 percent, of this amount is for
projects outside the United States. Spending in 2012 is primarily focused on major development
projects in Angola, Australia, Brazil, Canada, China, Kazakhstan, Nigeria, Russia, the United
Kingdom and the U.S. Gulf of Mexico. Also included is funding for enhancing recovery and mitigating
natural field declines for currently-producing assets, and for focused exploration and appraisal
activities.
Worldwide downstream spending in 2012 is estimated at $3.6 billion, with about $2.1 billion
for projects in the United States. Major capital outlays include projects under construction at
refineries in the United States and South Korea, expansion of additives production capacity in
Singapore, and chemicals projects in the United States and Saudi Arabia.
Investments in technology, power generation and other corporate businesses in 2012 are
budgeted at $600 million.
Noncontrolling interests The company had noncontrolling interests of $799 million
and $730 million at December 31, 2011 and 2010, respectively. Distributions to noncontrolling
interests totaled $71 million and $72 million in 2011 and 2010, respectively.
Pension Obligations Information related to pension plan contributions is included
on page FS-54 in Note 21 to the Consolidated Financial Statements under the heading Cash
Contributions and Benefit Payments. Refer also to the discussion of pension accounting in
Critical Accounting Estimates and Assumptions, beginning on page FS-16.
Financial Ratios
Financial Ratios
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31 |
|
|
|
2011 |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
Current Ratio |
|
|
1.6 |
|
|
|
|
1.7 |
|
|
|
1.4 |
|
Interest Coverage Ratio |
|
|
165.4 |
|
|
|
|
101.7 |
|
|
|
62.3 |
|
Debt Ratio |
|
|
7.7 |
% |
|
|
|
9.8 |
% |
|
|
10.3 |
% |
|
|
|
|
Current Ratio current assets divided by current liabilities, which indicates
the companys ability to repay its short-term liabilities with short-term assets. 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 2011, the book value of inventory was lower than replacement
costs, based on average acquisition costs during the year, by approximately $9.0 billion.
Interest Coverage Ratio income before income tax
expense, plus interest and debt expense and amortization of capitalized
interest, less net income attributable to noncontrolling interests,
divided by before-tax interest costs. This
ratio indicates the
companys ability to pay interest on outstanding debt. The companys
interest coverage ratio in 2011 was higher than 2010 and 2009 due to
higher before-tax income.
Debt Ratio total debt as a percentage of total debt
plus Chevron Corporation Stockholders Equity, which indicates the
companys leverage. The decrease between 2011 and 2010 was due to lower
debt and a higher Chevron Corporation stockholders equity balance. The
decrease between 2010 and 2009 was due to a higher Chevron Corporation
stockholders equity balance.
Guarantees, Off-Balance-Sheet Arrangements and Contractual Obligations, and Other
Contingencies
Direct Guarantee
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
Commitment Expiration by Period |
|
|
|
|
|
|
|
|
|
|
|
2013 |
|
|
2015 |
|
|
After |
|
|
|
Total |
|
|
2012 |
|
|
2014 |
|
|
2016 |
|
|
2016 |
|
|
Guarantee of
non-
consolidated affiliate or joint-venture obligation |
|
$ |
601 |
|
|
$ |
38 |
|
|
$ |
77 |
|
|
$ |
77 |
|
|
$ |
409 |
|
|
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 commenced
operations in third quarter 2011. Over the approximate 16-year term of the guarantee, the maximum
guarantee amount will be reduced 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
amounts paid under the guarantee. Chevron has recorded no liability for its obligation under this
guarantee.
Indemnifications Information related to indemnifications is included on page
FS-56 in Note 24 to the Consolidated Financial Statements under the heading Indemnifications.
Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and
Take-or-Pay Agreements The company and its subsidiaries have certain other contingent
liabilities with respect to long-term unconditional purchase obligations and commitments, including
throughput and take-or-pay agreements, some of which relate to suppliers
FS-12
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: 2012 $6.0 billion; 2013 $4.0 billion; 2014 $3.9
billion; 2015 $3.2 billion; 2016 $1.9 billion; 2017 and after $7.4 billion. A portion of
these commitments may ultimately be shared with project partners. Total payments under the
agreements were approximately $6.6 billion in 2011, $6.5 billion in 2010 and $8.1 billion in 2009.
The following table summarizes the companys significant contractual obligations:
Contractual Obligations1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
Payments Due by Period |
|
|
|
|
|
|
|
|
|
|
|
2013 |
|
|
2015 |
|
|
After |
|
|
|
Total |
|
|
2012 |
|
|
2014 |
|
|
2016 |
|
|
2016 |
|
|
On Balance Sheet:2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-Term Debt3 |
|
$ |
340 |
|
|
$ |
340 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Long-Term Debt3 |
|
|
9,684 |
|
|
|
|
|
|
|
7,641 |
|
|
|
|
|
|
|
2,043 |
|
Noncancelable Capital Lease Obligations |
|
|
251 |
|
|
|
70 |
|
|
|
79 |
|
|
|
34 |
|
|
|
68 |
|
Interest |
|
|
1,764 |
|
|
|
223 |
|
|
|
366 |
|
|
|
264 |
|
|
|
911 |
|
Off Balance Sheet: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncancelable Operating Lease Obligations |
|
|
3,509 |
|
|
|
693 |
|
|
|
1,155 |
|
|
|
868 |
|
|
|
793 |
|
Throughput and Take-or-Pay Agreements4
|
|
|
21,664 |
|
|
|
4,912 |
|
|
|
5,382 |
|
|
|
4,218 |
|
|
|
7,152 |
|
Other Unconditional Purchase Obligations4 |
|
|
4,759 |
|
|
|
1,102 |
|
|
|
2,524 |
|
|
|
906 |
|
|
|
227 |
|
|
|
|
|
1 |
| Excludes contributions for pensions and other postretirement benefit plans.
Information on employee benefit plans is contained in Note 21 beginning on page FS-49. |
|
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 |
|
$5.6 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 20132014 period. |
|
4 |
|
Does not include commodity purchase obligations that are not fixed or determinable.
These obligations are generally monetized in a relatively short period of time through sales
transactions or similar agreements with third parties. Examples include obligations to
purchase LNG, regasified natural gas and refinery products at indexed prices. |
Financial and Derivative Instruments
The market risk associated with the companys portfolio of financial and derivative instruments is
discussed below. The estimates of financial exposure to market risk do not represent the companys
projection of future market changes. The actual impact of future market changes could differ
materially due to factors discussed elsewhere in this report, including those set forth under the
heading Risk Factors in Part I, Item 1A, of the companys 2011 Annual Report on Form 10-K.
Derivative Commodity Instruments Chevron is exposed to market risks related to
the price volatility of crude oil, refined products, natural gas, natural gas liquids, liquefied
natural gas and refinery feedstocks.
The company uses derivative commodity instruments to manage these exposures on a portion of its
activity, including firm commitments and anticipated transactions for
the pur-
chase, sale
and storage of crude oil, refined products, natural gas, natural gas liquids and feedstock for
company refineries. The company also uses derivative commodity instruments for limited trading
purposes. The results of these activities were not material to the companys financial position,
results of operations or cash flows in 2011.
The companys market exposure positions are monitored and managed on a daily basis by an
internal Risk Control group in accordance with the companys risk management policies, which have
been approved by the Audit Committee of the companys Board of Directors.
The derivative commodity instruments used in the companys risk management and trading
activities consist mainly of futures, options and swap contracts traded on the New York Mercantile
Exchange and on electronic platforms of the Inter-Continental Exchange and Chicago Mercantile
Exchange. In addition, crude oil, natural gas and refined product swap contracts and option
contracts are entered into principally with major financial institutions and other oil and gas
companies in the over-the-counter markets.
Derivatives beyond those designated as normal purchase and normal sale contracts are recorded
at fair value on the Consolidated Balance Sheet in accordance with accounting standards for
derivatives (ASC 815), with resulting gains and losses reflected in income. Fair values are derived
principally from published market quotes and other independent third-party quotes. The change in
fair value of Chevrons derivative commodity instruments in 2011 was a quarterly average increase
of $22 million in total assets and a quarterly average decrease of $17 million in total
liabilities.
The company uses a Value-at-Risk (VaR) model to estimate the potential loss in fair value on a
single day from the effect of adverse changes in market conditions on derivative commodity
instruments held or issued. VaR is the maximum projected loss not to be exceeded within a given
probability or confidence level over a given period of time. The companys VaR model uses the Monte
Carlo simulation method that involves generating hypothetical scenarios from the specified
probability distributions and constructing a full distribution of a portfolios potential values.
The VaR model utilizes an exponentially weighted moving average for computing historical
volatilities and correlations, a 95 percent confidence level, and a one-day holding period. That
is, the companys 95 percent, one-day VaR corresponds to the unrealized loss in portfolio value
that would not be exceeded on average more than one in every 20 trading days, if the portfolio were
held constant for one day.
The one-day holding period is based on the assumption that market-risk positions can be liquidated
or hedged within one day. For hedging and risk management, the company uses conventional
exchange-traded instruments such as futures and options as well as non-exchange-traded swaps, most
of which can be liquidated or hedged effectively within one day. The following table presents the
95 percent/one-day VaR for each of the companys primary risk exposures in the area of derivative
commodity instruments at December 31, 2011 and 2010.
FS-13
Managements Discussion and Analysis of
Financial Condition and Results of Operations
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2011 |
|
|
|
2010 |
|
|
|
|
|
Crude Oil |
|
$ |
22 |
|
|
|
$ |
15 |
|
Natural Gas |
|
|
4 |
|
|
|
|
4 |
|
Refined Products |
|
|
11 |
|
|
|
|
14 |
|
|
|
|
|
Foreign Currency The company may enter into foreign currency derivative contracts
to manage some of its foreign currency exposures. These exposures include revenue and anticipated
purchase transactions, including foreign currency capital expenditures and lease commitments. The
foreign currency derivative contracts, if any, are recorded at fair value on the balance sheet with
resulting gains and losses reflected in income. There were no open foreign currency derivative
contracts at December 31, 2011.
Interest Rates The company may enter into interest rate swaps from time to time
as part of its overall strategy to manage the interest rate risk on its debt. Interest rate swaps,
if any, are recorded at fair value on the balance sheet with resulting gains and losses reflected
in income. At year-end 2011, the company had no interest rate swaps.
Transactions With Related Parties
Chevron enters into a number of business arrangements with related parties, principally its equity
affiliates. These arrangements include long-term supply or offtake agreements and long-term
purchase agreements. Refer to Other Information in Note 12 of the Consolidated Financial
Statements, page FS-40, for further discussion. Management believes these agreements have been
negotiated on terms consistent with those that would have been negotiated with an unrelated party.
Litigation and Other Contingencies
MTBE Information related to methyl tertiary butyl ether (MTBE) matters is included
on page FS-41 in Note 14 to the Consolidated Financial Statements under the heading MTBE.
Ecuador Information related to Ecuador matters is included in Note 14 to the
Consolidated Financial Statements under the heading Ecuador, beginning on page FS-41.
Environmental The company is subject to loss contingencies
pursuant to laws, regulations, private claims and legal proceedings
related to environmental matters that are subject to legal settlements
or that in the future may require the company to take action to correct
or ameliorate the effects on the environment of prior release of
chemicals or petroleum substances, including MTBE, by the company or
other parties. Such contingencies may exist for various 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 following table displays the annual changes to the companys before-tax environmental
remediation reserves, including those for federal Superfund sites and analogous sites under state
laws.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2011 |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
Balance at January 1 |
|
$ |
1,507 |
|
|
|
$ |
1,700 |
|
|
$ |
1,818 |
|
Net Additions |
|
|
343 |
|
|
|
|
220 |
|
|
|
351 |
|
Expenditures |
|
|
(446 |
) |
|
|
|
(413 |
) |
|
|
(469 |
) |
|
|
|
|
Balance at December 31 |
|
$ |
1,404 |
|
|
|
$ |
1,507 |
|
|
$ |
1,700 |
|
|
|
|
|
Included in the $1,404 million year-end 2011 reserve balance were remediation activities at
approximately 180 sites for which 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 2011 was $185 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 results of operations, consolidated financial
position or liquidity.
FS-14
Of the remaining year-end 2011 environmental reserves balance of $1,219 million,
$675 million related to the companys U.S. downstream operations, including refineries and other
plants, marketing locations (i.e., service stations and terminals), chemical facilities, and
pipelines. The remaining $544 million was associated with various sites in international downstream
($95 million), upstream ($368 million) and other businesses ($81 million). Liabilities at all
sites, whether operating, closed or divested, were primarily associated with the companys plans
and activities to remediate soil or groundwater contamination or both. These and other activities
include one or more of the following: site assessment; soil excavation; offsite disposal of
contaminants; onsite containment, remediation and/or extraction of petroleum hydrocarbon liquid
and vapor from soil; groundwater extraction and treatment; and monitoring of the natural
attenuation of the contaminants.
The company manages environmental liabilities under specific sets of regulatory requirements,
which in the United States include the Resource Conservation and Recovery Act and various state and
local regulations. No single remediation site at year-end 2011 had a recorded liability that was
material to the companys results of operations, consolidated financial position or liquidity.
It is likely that the company will continue to incur additional liabilities, beyond those
recorded, for environmental remediation relating to past operations. 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.
The company records asset retirement obligations when there is a legal obligation associated
with the retirement of long-lived assets and the liability can be reasonably estimated. These asset
retirement obligations include costs related to environmental issues. The liability balance of
approximately $12.8 billion for asset retirement obligations at year-end 2011 related primarily to
upstream properties.
For the companys other ongoing operating assets, such as refineries and chemicals facilities,
no provisions are made for exit or cleanup costs that may be required when such assets reach the
end of their useful lives unless a decision to sell or otherwise abandon the facility has been
made, as the indeterminate settlement dates for the asset retirements prevent estimation of the
fair value of the asset retirement obligation.
Refer also to Note 25 on page FS-58, related to the companys asset retirement obligations and
the discussion of Environmental Matters beginning on page FS-15.
Suspended Wells The company suspends the costs of exploratory wells pending a
final determination of the commercial potential of the related crude oil and natural gas
fields. The ultimate disposition of these well costs is dependent on the results of future
drilling activity or development decisions or both. At December 31, 2011, the company had
approximately $2.4 billion of suspended exploratory wells included in properties, plant and
equipment, a decrease
of $284 million from 2010. The 2010 balance reflected an
increase of $283 million from 2009.
The future trend of the companys exploration expenses can be affected by amounts associated
with well write-offs, including wells that had been previously suspended pending determination as
to whether the well had found reserves that could be classified as proved. The effect on
exploration expenses in future periods of the $2.4 billion of suspended wells at year-end 2011 is
uncertain pending future activities, including normal project evaluation and additional drilling.
Refer to Note 19, beginning on page FS-47, for additional discussion of suspended wells.
Income Taxes Information related to income tax contingencies is included on pages
FS-43 through FS-45 in Note 15 and page FS-56 in Note 24 to the Consolidated Financial Statements
under the heading Income Taxes.
Other Contingencies Information related to other contingencies is included on
pages FS-57 through FS-58 in Note 24 to the Consolidated Financial Statements under the heading
Other Contingencies.
Environmental Matters
Virtually all aspects of the businesses in which the company engages are subject to various
federal, state and local environmental, health and safety laws and regulations. These regulatory
requirements continue to increase in both number and complexity over time and govern not only the
manner in which the company conducts its operations, but also the products it sells. Most of the
costs of complying with laws and regulations pertaining to company operations and products are
embedded in the normal costs of doing business.
Accidental leaks and spills requiring cleanup may occur in the ordinary course of business. In
addition to the costs for environmental protection associated with its ongoing operations and
products, the company may incur expenses for corrective actions at various owned and previously
owned facilities and at third-party-owned waste disposal sites used by the company. An obligation
may arise when operations are closed or sold or at non-Chevron sites where company products have
been handled or disposed of. Most of the expenditures to fulfill these obligations relate to
facilities and sites where past operations followed practices and procedures that were considered
acceptable at the time but now require investigative or remedial work or both to meet current
standards.
Using definitions and guidelines established by the American Petroleum Institute, Chevron
estimated its worldwide environmental spending in 2011 at approximately $2.7 billion for its
consolidated companies. Included in these expenditures were approximately $1.0 billion of
environmental capital expenditures and $1.7 billion of costs associated with the prevention,
control, abatement or elimination of hazardous substances and pollutants from operating, closed or
divested sites, and the abandonment and restoration of sites.
For 2012, total worldwide environmental capital expenditures are estimated at $1.0 billion. These
capital costs are in addition to the ongoing costs of complying with environmental regulations and
the costs to remediate previously contaminated sites.
FS-15
Managements Discussion and Analysis of
Financial Condition and Results of Operations
It is not possible to predict with certainty the amount of additional
investments in new or existing facilities or amounts of incremental operating costs to be incurred
in the future to: prevent, control, reduce or eliminate releases of hazardous materials into the
environment; comply with existing and new environmental laws or regulations; or remediate and
restore areas damaged by prior releases of hazardous materials. Although these costs may be
significant to the results of operations in any single period, the company does not expect them to
have a material effect on the companys liquidity or financial position.
Critical Accounting Estimates and Assumptions
Management makes many estimates and assumptions in the application of generally accepted accounting
principles (GAAP) that may have a material impact on the companys consolidated financial
statements and related disclosures and on the comparability of such information over different
reporting periods. All such estimates and assumptions affect reported amounts of assets,
liabilities, revenues and expenses, as well as disclosures of contingent assets and liabilities.
Estimates and assumptions are based on managements experience and other information available
prior to the issuance of the financial statements. Materially different results can occur as
circumstances change and additional information becomes known.
The discussion in this section of critical accounting estimates and assumptions is according
to the disclosure guidelines of the Securities and Exchange Commission (SEC), wherein:
|
1. |
|
the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment
necessary to account for highly uncertain matters or the susceptibility of such matters to change; and |
|
|
2. |
|
the impact of the estimates and assumptions on the
companys financial condition or operating performance is material. |
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.
For example, the recording of deferred tax assets requires an assessment under the accounting
rules that the future realization of the associated tax benefits be more likely than not. Another
example is the estimation of crude oil and natural gas reserves under SEC rules, which require
... by analysis of geosciences and engineering data, (the reserves) can be estimated with
reasonable certainty to be economi-
cally
producible... under existing economic
conditions where existing economic conditions include prices based on the average price during the
12-month period prior to the end of the reporting period. Refer to Table V, Reserve Quantity
Information, beginning on page FS-67, for the changes in these estimates for the three years
ending December 31, 2011, and to Table VII, Changes in the Standardized Measure of Discounted
Future Net Cash Flows From Proved Reserves on page FS-76 for estimates of proved-reserve values
for each of the three years ended December 31, 2011. Note 1 to the Consolidated Financial
Statements, beginning on page FS-28, includes a description of the successful efforts method of
accounting for oil and gas exploration and production activities. The estimates of crude oil and
natural gas reserves are important to the timing of expense recognition for costs incurred.
The discussion of the critical accounting policy for Impairment of Properties, Plant and
Equipment and Investments in Affiliates, beginning on page FS-18, includes reference to conditions
under which downward revisions of proved-reserve quantities could result in impairments of oil and
gas properties. This commentary should be read in conjunction with disclosures elsewhere in this
discussion and in the Notes to the Consolidated Financial Statements related to estimates,
uncertainties, contingencies and new accounting standards. Significant accounting policies are
discussed in Note 1 to the Consolidated Financial Statements, beginning on page FS-28. The
development and selection of accounting estimates and assumptions, including those deemed
critical, and the associated disclosures in this discussion have been discussed by management
with the Audit Committee of the Board of Directors.
The areas of accounting and the associated critical estimates and assumptions made by the
company are as follows:
Pension and Other Postretirement Benefit Plans The determination of pension plan
obligations and expense is based on a number of actuarial assumptions. Two critical assumptions are
the expected long-term rate of return on plan assets and the discount rate applied to pension plan
obligations. For other postretirement benefit (OPEB) plans, which provide for certain health care
and life insurance benefits for qualifying retired employees and which are not funded, critical
assumptions in determining OPEB obligations and expense are the discount rate and the assumed
health care cost-trend rates.
Note 21, beginning on page FS-49, includes information on the funded status of the companys
pension and OPEB plans at the end of 2011 and 2010; the components of pension and OPEB expense for
the three years ended December 31, 2011; and the underlying assumptions for those periods.
FS-16
Pension and OPEB expense is reported on the Consolidated Statement of Income as
Operating expenses or Selling, general and administrative expenses and applies to all business
segments. The year-end 2011 and 2010 funded status, measured as the difference between plan assets
and obligations, of each of the companys pension and OPEB plans is recognized on the Consolidated
Balance Sheet. The differences related to overfunded pension plans are reported as a long-term
asset in Deferred charges and other assets. The differences associated with underfunded or
unfunded pension and OPEB plans are reported as Accrued liabilities or Reserves for employee
benefit plans. Amounts yet to be recognized as components of pension or OPEB expense are reported
in Accumulated other comprehensive loss.
To estimate the long-term rate of return on pension assets, the company uses a process that
incorporates actual historical asset-class returns and an assessment of expected future performance
and takes into consideration external actuarial advice and asset-class factors. Asset allocations
are periodically updated using pension plan asset/liability studies, and the determination of the
companys estimates of long-term rates of return are consistent with these studies. The expected
long-term rate of return on U.S. pension plan assets, which account for 70 percent of the companys
pension plan assets, has remained at 7.8 percent since 2002. For the 10 years ending December 31,
2011, actual asset returns averaged 5.0 percent for this plan. The actual return for 2011 was
slightly negative and was associated with the broad decline in the financial markets in the second
half of the year. Additionally, with the exception of two other years within this 10 year period,
actual asset returns for this plan equaled or exceeded 7.8 percent.
The year-end market-related value of assets of the major U.S. pension plan used in the
determination of pension expense was based on the market value in the preceding three months, as
opposed to the maximum allowable period of five years under U.S. accounting rules. Management
considers the three-month period long enough to minimize the effects of distortions from day-to-day
market volatility and still be contemporaneous to the end of the year. For other plans, market
value of assets as of year-end is used in calculating the pension expense.
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, 2011, the company selected a 3.8
percent discount rate for the major U.S. pension plan and 4.0 percent for its OPEB plan. These
rates were selected based on a cash flow analysis that matched estimated future benefit payments to
the Citigroup Pension Discount Yield Curve as of year-end 2011. The discount rates at the end of
2010 and 2009 were 4.8 percent and 5.3 percent, respectively, for the major U.S. pension plan, and
5.0 percent and 5.8 percent, respectively, for the companys U.S. OPEB plan.
An increase in the expected long-term return on plan assets or the discount rate would reduce
pension plan expense, and vice versa. Total pension expense for 2011 was
$1.2 billion. As
an indication of the sensitivity of pension expense to the long-term rate of return assumption, a 1
percent increase in the expected rate of return on assets of the companys primary U.S. pension
plan would have reduced total pension plan expense for 2011 by approximately $75 million. A 1
percent increase in the discount rate for this same plan, which accounted for about 63 percent of
the companywide pension obligation, would have reduced total pension plan expense for 2011 by
approximately $145 million.
An increase in the discount rate would decrease the pension obligation, thus changing the
funded status of a plan reported on the Consolidated Balance Sheet. The aggregate funded status
recognized on the Consolidated Balance Sheet at December 31, 2011, was a net liability of
approximately $5.4 billion. As an indication of the sensitivity of pension liabilities to the
discount rate assumption, a 0.25 percent increase in the discount rate applied to the companys
primary U.S. pension plan would have reduced the plan obligation by approximately $375 million,
which would have decreased the plans underfunded status from approximately $2.5 billion to $2.1
billion. Other plans would be less underfunded as discount rates increase. The actual rates of
return on plan assets and discount rates may vary significantly from estimates because of
unanticipated changes in the worlds financial markets.
In 2011, the companys pension plan contributions were $1.5 billion (including $1.2 billion to
the U.S. plans). In 2012, the company estimates contributions will be approximately $900 million.
Actual contribution amounts are dependent upon 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.
For
the companys OPEB plans, expense for 2011 was $220 million, and the total liability,
which reflected the unfunded status of the plans at the end of 2011, was $3.8 billion.
As an indication of discount rate sensitivity to the determination of OPEB expense in 2011, a
1 percent increase in the discount rate for the companys primary U.S. OPEB plan, which accounted
for about 76 percent of the companywide OPEB expense, would have decreased OPEB expense by
approximately $10 million. A 0.25 percent increase in the discount rate for the same plan, which
accounted for about 81 percent of the companywide OPEB liabilities, would have decreased total OPEB
liabilities at the end of 2011 by approximately $75 million.
For the main U.S. postretirement medical plan, the annual increase to company contributions is
limited to 4 percent per year. For active employees and retirees under age 65 whose claims
experiences are combined for rating purposes, the assumed health care cost-trend rates start with 8
percent in 2012 and gradually drop to 5 percent for 2023 and beyond. As an indication of the health
care cost-trend rate sensitivity to the determination of OPEB expense in 2011, a 1 percent increase
in the rates for the main U.S. OPEB plan, which accounted for 81 percent of the companywide OPEB
liabilities, would have increased OPEB expense by $8 million.
FS-17
Managements Discussion and Analysis of
Financial Condition and Results of Operations
Differences between the various assumptions used to determine expense and
the funded status of each plan and actual experience are not included in benefit plan costs in the
year the difference occurs. Instead, the differences are included in actuarial gain/loss and
unamortized amounts have been reflected in Accumulated other comprehensive loss on the
Consolidated Balance Sheet. Refer to Note 21, beginning on page FS-49, for information on the $9.6
billion of before-tax actuarial losses recorded by the company as of December 31, 2011; a
description of the method used to amortize those costs; and an estimate of the costs to be
recognized in expense during 2012.
Impairment of Properties, Plant and Equipment and Investments in Affiliates The
company assesses its properties, plant and equipment (PP&E) for possible impairment whenever events
or changes in circumstances indicate that the carrying value of the assets may not be recoverable.
Such indicators include changes in the companys business plans, changes in commodity prices and,
for crude oil and natural gas properties, significant downward revisions of estimated 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.
Determination as to whether and how much an asset is impaired involves management estimates on
highly uncertain matters, such as future commodity prices, the effects of inflation and technology
improvements on operating expenses, production profiles, and the outlook for global or regional
market supply-and-demand conditions for crude oil, natural gas, commodity chemicals and refined
products. However, the impairment reviews and calculations are based on assumptions that are
consistent with the companys business plans and long-term investment decisions. Refer also to the
discussion of impairments of properties, plant and equipment in Note 9 beginning on page FS-34.
No major individual impairments of PP&E and Investments were recorded for the three years
ending December 31, 2011. A sensitivity analysis of the impact on earnings for these periods if
other assumptions had been used in impairment reviews and impairment calculations is not
practicable, given the broad range of the companys PP&E and the number of assumptions involved in
the estimates. That is, favorable changes to some assumptions might have avoided the need to impair
any assets in these periods, whereas unfavorable changes might have caused an additional unknown
number of other assets to become impaired.
Investments in common stock of affiliates that
are accounted for under the equity method, as well as investments in other securities of these
equity investees, are reviewed for impairment when the fair value of the investment falls below the
companys carrying value. When such a decline is deemed to be other than temporary, an impairment
charge is recorded to the income statement for the difference between the investments carrying
value and its estimated fair value at the time.
In making the determination as to whether a decline is other than temporary, the company
considers such factors as the duration and extent of the decline, the investees financial
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.
Differing assumptions could affect whether an investment is impaired in any period or the amount of
the impairment, and are not subject to sensitivity analysis.
From time to time, the company performs impairment reviews and determines whether any
write-down in the carrying value of an asset or asset group is required. For example, when
significant downward revisions to crude oil and natural gas reserves are made for any single field
or concession, an impairment review is performed to determine if the carrying value of the asset
remains recoverable. Also, if the expectation of sale of a particular asset or asset group in any
period has been deemed more likely than not, an impairment review is performed, and if the
estimated net proceeds exceed the carrying value of the asset or asset group, no impairment charge
is required. Such calculations are reviewed each period until the asset or asset group is disposed
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.
Goodwill Goodwill resulting from a business combination is not subject to
amortization. As required by accounting standards for goodwill (ASC 350), 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.
Contingent Losses Management also makes judgments and estimates in recording
liabilities for claims, litigation, tax matters and environmental remediation. Actual costs can
frequently vary from estimates for a variety of reasons. For
FS-18
example, the costs from settlement of claims and litigation can vary from estimates
based on differing interpretations of laws, opinions on culpability and assessments on the amount
of damages. Similarly, liabilities for environmental remediation are subject to change because of
changes in laws, regulations and their interpretation, the determination of additional information
on the extent and nature of site contamination, and improvements in technology.
Under the accounting rules, a liability is generally recorded for these types of contingencies if
management determines the loss to be both probable and estimable. The company generally reports
these losses as Operating expenses or Selling, general and administrative expenses on the
Consolidated Statement of Income. An exception to this handling is for income tax matters, for
which benefits are recognized only if management determines the tax position is more likely than
not (i.e., likelihood greater than 50 percent) to be allowed by the tax jurisdiction. For
additional
discussion of income tax uncertainties, refer to Note 15 beginning on page
FS-43. Refer also to the business segment discussions elsewhere in this section for the effect on
earnings from losses associated with certain litigation, environmental remediation and tax matters
for the three years ended December 31, 2011.
An estimate as to the sensitivity to earnings for these periods if other assumptions had been
used in recording these liabilities is not practicable because of the number of contingencies that
must be assessed, the number of underlying assumptions and the wide range of reasonably possible
outcomes, both in terms of the probability of loss and the estimates of such loss.
New Accounting Standards
Refer to Note 18, on page FS-47 in the Notes to Consolidated Financial Statements, for information
regarding new accounting standards.
FS-19
Quarterly Results and Stock Market Data
Unaudited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011 |
|
|
|
2010 |
|
Millions of dollars, except per-share amounts |
|
4th Q |
|
|
3rd Q |
|
|
2nd Q |
|
|
1st Q |
|
|
|
4th Q |
|
|
3rd Q |
|
|
2nd Q |
|
|
1st Q |
|
|
|
|
|
Revenues and Other Income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales and other operating revenues1 |
|
$ |
58,027 |
|
|
$ |
61,261 |
|
|
$ |
66,671 |
|
|
$ |
58,412 |
|
|
|
$ |
51,852 |
|
|
$ |
48,554 |
|
|
$ |
51,051 |
|
|
$ |
46,741 |
|
Income from equity affiliates |
|
|
1,567 |
|
|
|
2,227 |
|
|
|
1,882 |
|
|
|
1,687 |
|
| |
|
1,510 |
|
|
|
1,242 |
|
|
|
1,650 |
|
|
|
1,235 |
|
Other income |
|
|
391 |
|
|
|
944 |
|
|
|
395 |
|
|
|
242 |
|
|
|
|
665 |
|
|
|
(78 |
) |
|
|
303 |
|
|
|
203 |
|
|
Total Revenues and Other Income |
|
|
59,985 |
|
|
|
64,432 |
|
|
|
68,948 |
|
|
|
60,341 |
|
|
|
|
54,027 |
|
|
|
49,718 |
|
|
|
53,004 |
|
|
|
48,179 |
|
|
Costs and Other Deductions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased crude oil and products |
|
|
36,363 |
|
|
|
37,600 |
|
|
|
40,759 |
|
|
|
35,201 |
|
|
|
|
30,109 |
|
|
|
28,610 |
|
|
|
30,604 |
|
|
|
27,144 |
|
Operating expenses |
|
|
5,948 |
|
|
|
5,378 |
|
|
|
5,260 |
|
|
|
5,063 |
|
|
|
|
5,343 |
|
|
|
4,665 |
|
|
|
4,591 |
|
|
|
4,589 |
|
Selling, general and administrative expenses |
|
|
1,330 |
|
|
|
1,115 |
|
|
|
1,200 |
|
|
|
1,100 |
|
|
|
|
1,408 |
|
|
|
1,181 |
|
|
|
1,136 |
|
|
|
1,042 |
|
Exploration expenses |
|
|
386 |
|
|
|
240 |
|
|
|
422 |
|
|
|
168 |
|
|
| |
335 |
|
|
|
420 |
|
|
|
212 |
|
|
|
180 |
|
Depreciation, depletion and amortization |
|
|
3,313 |
|
|
|
3,215 |
|
|
|
3,257 |
|
|
|
3,126 |
|
|
|
|
3,439 |
|
|
|
3,401 |
|
|
|
3,141 |
|
|
|
3,082 |
|
Taxes other than on income1 |
|
|
2,680 |
|
|
|
3,544 |
|
|
|
4,843 |
|
|
|
4,561 |
|
|
|
|
4,623 |
|
|
|
4,559 |
|
|
|
4,537 |
|
|
|
4,472 |
|
Interest and debt expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4 |
|
|
|
9 |
|
|
|
17 |
|
|
|
20 |
|
|
Total Costs and Other Deductions |
|
|
50,020 |
|
|
|
51,092 |
|
|
|
55,741 |
|
|
|
49,219 |
|
|
|
|
45,261 |
|
|
|
42,845 |
|
|
|
44,238 |
|
|
|
40,529 |
|
|
Income Before Income Tax Expense |
|
|
9,965 |
|
|
|
13,340 |
|
|
|
13,207 |
|
|
|
11,122 |
|
|
|
|
8,766 |
|
|
|
6,873 |
|
|
|
8,766 |
|
|
|
7,650 |
|
Income Tax Expense |
|
|
4,813 |
|
|
|
5,483 |
|
|
|
5,447 |
|
|
|
4,883 |
|
|
|
|
3,446 |
|
|
|
3,081 |
|
|
|
3,322 |
|
|
|
3,070 |
|
|
Net Income |
|
$ |
5,152 |
|
|
$ |
7,857 |
|
|
$ |
7,760 |
|
|
$ |
6,239 |
|
|
|
$ |
5,320 |
|
|
$ |
3,792 |
|
|
$ |
5,444 |
|
|
$ |
4,580 |
|
|
Less: Net
income attributable to noncontrolling interests |
|
|
29 |
|
|
|
28 |
|
|
|
28 |
|
|
|
28 |
|
|
|
|
25 |
|
|
|
24 |
|
|
|
35 |
|
|
|
28 |
|
|
Net Income Attributable to Chevron Corporation |
|
$ |
5,123 |
|
|
$ |
7,829 |
|
|
$ |
7,732 |
|
|
$ |
6,211 |
|
|
|
$ |
5,295 |
|
|
$ |
3,768 |
|
|
$ |
5,409 |
|
|
$ |
4,552 |
|
|
Per Share of Common Stock |
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
Attributable to Chevron Corporation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
2.61 |
|
|
$ |
3.94 |
|
|
$ |
3.88 |
|
|
$ |
3.11 |
|
|
|
$ |
2.65 |
|
|
$ |
1.89 |
|
|
$ |
2.71 |
|
|
$ |
2.28 |
|
Diluted |
|
$ |
2.58 |
|
|
$ |
3.92 |
|
|
$ |
3.85 |
|
|
$ |
3.09 |
|
|
|
$ |
2.64 |
|
|
$ |
1.87 |
|
|
$ |
2.70 |
|
|
$ |
2.27 |
|
|
Dividends |
|
$ |
0.81 |
|
|
$ |
0.78 |
|
|
$ |
0.78 |
|
|
$ |
0.72 |
|
|
|
$ |
0.72 |
|
|
$ |
0.72 |
|
|
$ |
0.72 |
|
|
$ |
0.68 |
|
Common Stock Price Range High2 |
|
$ |
110.01 |
|
|
$ |
109.75 |
|
|
$ |
109.94 |
|
|
$ |
109.65 |
|
|
|
$ |
92.39 |
|
|
$ |
82.19 |
|
|
$ |
83.41 |
|
|
$ |
81.09 |
|
Low2 |
|
$ |
86.68 |
|
|
$ |
87.30 |
|
|
$ |
97.00 |
|
|
$ |
90.12 |
|
|
|
$ |
80.41 |
|
|
$ |
66.83 |
|
|
$ |
67.80 |
|
|
$ |
69.55 |
|
|
1 Includes excise, value-added and similar taxes: |
|
$ |
1,713 |
|
|
$ |
1,974 |
|
|
$ |
2,264 |
|
|
$ |
2,134 |
|
|
|
$ |
2,136 |
|
|
$ |
2,182 |
|
|
$ |
2,201 |
|
|
$ |
2,072 |
|
2 Intraday price. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The companys common stock is listed on the New York Stock Exchange (trading symbol: CVX). As of
February 13, 2012, stockholders of record numbered approximately 178,000. There are no restrictions
on the companys ability to pay dividends.
FS-20
Managements Responsibility for Financial Statements
To the Stockholders of Chevron Corporation
Management of Chevron is responsible for preparing the accompanying consolidated financial
statements and the related information appearing in this report. The statements were prepared in
accordance with accounting principles generally accepted in the United States of America and fairly
represent the transactions and financial position of the company. The financial statements include
amounts that are based on managements best estimates and judgment.
As stated in its report included herein, the independent registered public accounting firm of
PricewaterhouseCoopers LLP has audited the companys consolidated financial statements in accordance
with the standards of the Public Company Accounting Oversight Board (United States).
The Board of Directors of Chevron has an Audit Committee composed of directors who are not
officers or employees of the company. The Audit Committee meets regularly with members of management,
the internal auditors and the independent registered public accounting firm to review accounting,
internal control, auditing and financial reporting matters. Both the internal auditors and the
independent registered public accounting firm have free and direct access to the Audit Committee
without the presence of management.
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, 2011.
The effectiveness of the companys internal control over financial reporting as of December
31, 2011, has been audited by PricewaterhouseCoopers LLP, an independent registered public
accounting firm, as stated in its report included herein.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
John S. Watson |
|
Patricia E. Yarrington |
|
Matthew J. Foehr |
Chairman of the Board
|
|
Vice President
|
|
Vice President |
and Chief Executive Officer
|
|
and Chief Financial Officer
|
|
and Comptroller |
February 23, 2012
FS-21
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 sheet and the related consolidated
statements of income, comprehensive income, equity and of cash flows present fairly, in all material
respects, the financial position of Chevron Corporation and its subsidiaries at December 31, 2011,
and December 31, 2010, and the results of their operations and their cash flows for each of the
three years in the period ended December 31, 2011, 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, 2011, 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.
A companys internal control over financial reporting is a process designed to provide
reasonable assurance regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally accepted accounting
principles. A companys internal control over financial reporting includes those policies and
procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately
and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide
reasonable assurance that transactions are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and
directors of the company; and (iii) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the companys assets that could have
a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent
or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
subject to the risk that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate.
San Francisco, California
February 23, 2012
FS-22
Consolidated Statement of Income
Millions
of dollars, except per-share amounts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31 |
|
|
|
2011 |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
|
Revenues and Other Income |
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales and other operating revenues* |
|
$ |
244,371 |
|
|
|
$ |
198,198 |
|
|
$ |
167,402 |
|
Income from equity affiliates |
|
|
7,363 |
|
|
|
|
5,637 |
|
|
|
3,316 |
|
Other income |
|
|
1,972 |
|
|
|
|
1,093 |
|
|
|
918 |
|
|
|
|
|
|
Total Revenues and Other Income |
|
|
253,706 |
|
|
|
|
204,928 |
|
|
|
171,636 |
|
|
|
|
|
|
Costs and Other Deductions |
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased crude oil and products |
|
|
149,923 |
|
|
|
|
116,467 |
|
|
|
99,653 |
|
Operating expenses |
|
|
21,649 |
|
|
|
|
19,188 |
|
|
|
17,857 |
|
Selling, general and administrative expenses |
|
|
4,745 |
|
|
|
|
4,767 |
|
|
|
4,527 |
|
Exploration expenses |
|
|
1,216 |
|
|
|
|
1,147 |
|
|
|
1,342 |
|
Depreciation, depletion and amortization |
|
|
12,911 |
|
|
|
|
13,063 |
|
|
|
12,110 |
|
Taxes other than on income* |
|
|
15,628 |
|
|
|
|
18,191 |
|
|
|
17,591 |
|
Interest and debt expense |
|
|
|
|
|
|
|
50 |
|
|
|
28 |
|
|
|
|
|
|
Total Costs and Other Deductions |
|
|
206,072 |
|
|
|
|
172,873 |
|
|
|
153,108 |
|
|
|
|
|
|
Income Before Income Tax Expense |
|
|
47,634 |
|
|
|
|
32,055 |
|
|
|
18,528 |
|
Income Tax Expense |
|
|
20,626 |
|
|
|
|
12,919 |
|
|
|
7,965 |
|
|
|
|
|
|
Net Income |
|
|
27,008 |
|
|
|
|
19,136 |
|
|
|
10,563 |
|
Less: Net income attributable to noncontrolling interests |
|
|
113 |
|
|
|
|
112 |
|
|
|
80 |
|
|
|
|
|
|
Net Income Attributable to Chevron Corporation |
|
$ |
26,895 |
|
|
|
$ |
19,024 |
|
|
$ |
10,483 |
|
|
|
|
|
|
Per Share of Common Stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Attributable to Chevron Corporation |
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
13.54 |
|
|
|
$ |
9.53 |
|
|
$ |
5.26 |
|
Diluted |
|
$ |
13.44 |
|
|
|
$ |
9.48 |
|
|
$ |
5.24 |
|
|
|
|
|
|
*Includes excise, value-added and similar taxes. |
|
$ |
8,085 |
|
|
|
$ |
8,591 |
|
|
$ |
8,109 |
|
See accompanying Notes to the Consolidated Financial Statements.
FS-23
Consolidated Statement of Comprehensive Income
Millions of dollars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31 |
|
|
|
2011 |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
Net Income |
|
$ |
27,008 |
|
|
|
$ |
19,136 |
|
|
$ |
10,563 |
|
|
|
|
|
Currency translation adjustment |
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized net change arising during period |
|
|
17 |
|
|
|
|
6 |
|
|
|
60 |
|
|
|
|
|
Unrealized holding (loss) gain on securities |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) gain arising during period |
|
|
(11 |
) |
|
|
|
(4 |
) |
|
|
2 |
|
|
|
|
|
Derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net derivatives gain (loss) on hedge transactions |
|
|
20 |
|
|
|
|
25 |
|
|
|
(69 |
) |
Reclassification to net income of net realized loss (gain) |
|
|
9 |
|
|
|
|
5 |
|
|
|
(23 |
) |
Income taxes on derivatives transactions |
|
|
(10 |
) |
|
|
|
(10 |
) |
|
|
32 |
|
|
|
|
|
Total |
|
|
19 |
|
|
|
|
20 |
|
|
|
(60 |
) |
|
|
|
|
Defined benefit plans |
|
|
|
|
|
|
|
|
|
|
|
|
|
Actuarial loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization to net income of net actuarial loss |
|
|
773 |
|
|
|
|
635 |
|
|
|
575 |
|
Actuarial loss arising during period |
|
|
(3,250 |
) |
|
|
|
(857 |
) |
|
|
(1,099 |
) |
Prior service cost |
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization to net income of net prior service credits |
|
|
(26 |
) |
|
|
|
(61 |
) |
|
|
(65 |
) |
Prior service cost arising during period |
|
|
(27 |
) |
|
|
|
(12 |
) |
|
|
(34 |
) |
Defined benefit plans sponsored by equity affiliates |
|
|
(81 |
) |
|
|
|
(12 |
) |
|
|
65 |
|
Income taxes on defined benefit plans |
|
|
1,030 |
|
|
|
|
140 |
|
|
|
159 |
|
|
|
|
|
Total |
|
|
(1,581 |
) |
|
|
|
(167 |
) |
|
|
(399 |
) |
|
|
|
|
Other Comprehensive Loss, Net of Tax |
|
|
(1,556 |
) |
|
|
|
(145 |
) |
|
|
(397 |
) |
|
|
|
|
Comprehensive Income |
|
|
25,452 |
|
|
|
|
18,991 |
|
|
|
10,166 |
|
|
|
|
|
Comprehensive income attributable to noncontrolling interests |
|
|
(113 |
) |
|
|
|
(112 |
) |
|
|
(80 |
) |
|
|
|
|
Comprehensive Income Attributable to Chevron Corporation |
|
$ |
25,339 |
|
|
|
$ |
18,879 |
|
|
$ |
10,086 |
|
|
|
|
|
See accompanying Notes to the Consolidated Financial Statements.
FS-24
Consolidated Balance Sheet
Millions of dollars, except per-share amounts
|
|
|
|
|
|
|
|
|
|
|
|
At December 31 |
|
|
|
2011 |
|
|
|
2010 |
|
|
|
|
|
Assets |
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
15,864 |
|
|
|
$ |
14,060 |
|
Time deposits |
|
|
3,958 |
|
|
|
|
2,855 |
|
Marketable securities |
|
|
249 |
|
|
|
|
155 |
|
Accounts and notes receivable (less allowance: 2011 $98; 2010 $184) |
|
|
21,793 |
|
|
|
|
20,759 |
|
Inventories: |
|
|
|
|
|
|
|
|
|
Crude oil and petroleum products |
|
|
3,420 |
|
|
|
|
3,589 |
|
Chemicals |
|
|
502 |
|
|
|
|
395 |
|
Materials, supplies and other |
|
|
1,621 |
|
|
|
|
1,509 |
|
|
|
|
|
|
Total inventories |
|
|
5,543 |
|
|
|
|
5,493 |
|
Prepaid expenses and other current assets |
|
|
5,827 |
|
|
|
|
5,519 |
|
|
|
|
|
Total Current Assets |
|
|
53,234 |
|
|
|
|
48,841 |
|
Long-term receivables, net |
|
|
2,233 |
|
|
|
|
2,077 |
|
Investments and advances |
|
|
22,868 |
|
|
|
|
21,520 |
|
Properties, plant and equipment, at cost |
|
|
233,432 |
|
|
|
|
207,367 |
|
Less: Accumulated depreciation, depletion and amortization |
|
|
110,824 |
|
|
|
|
102,863 |
|
|
|
|
|
|
Properties, plant and equipment, net |
|
|
122,608 |
|
|
|
|
104,504 |
|
Deferred charges and other assets |
|
|
3,889 |
|
|
|
|
3,210 |
|
Goodwill |
|
|
4,642 |
|
|
|
|
4,617 |
|
|
|
|
|
Total Assets |
|
$ |
209,474 |
|
|
|
$ |
184,769 |
|
|
|
|
|
Liabilities and Equity |
|
|
|
|
|
|
|
|
|
Short-term debt |
|
$ |
340 |
|
|
|
$ |
187 |
|
Accounts payable |
|
|
22,147 |
|
|
|
|
19,259 |
|
Accrued liabilities |
|
|
5,287 |
|
|
|
|
5,324 |
|
Federal and other taxes on income |
|
|
4,584 |
|
|
|
|
2,776 |
|
Other taxes payable |
|
|
1,242 |
|
|
|
|
1,466 |
|
|
|
|
|
Total Current Liabilities |
|
|
33,600 |
|
|
|
|
29,012 |
|
Long-term debt |
|
|
9,684 |
|
|
|
|
11,003 |
|
Capital lease obligations |
|
|
128 |
|
|
|
|
286 |
|
Deferred credits and other noncurrent obligations |
|
|
19,181 |
|
|
|
|
19,264 |
|
Noncurrent deferred income taxes |
|
|
15,544 |
|
|
|
|
12,697 |
|
Reserves for employee benefit plans |
|
|
9,156 |
|
|
|
|
6,696 |
|
|
|
|
|
Total Liabilities |
|
|
87,293 |
|
|
|
|
78,958 |
|
|
|
|
|
Preferred stock (authorized 100,000,000 shares; $1.00 par value; none issued) |
|
|
|
|
|
|
|
|
|
Common stock (authorized 6,000,000,000 shares; $0.75 par value; 2,442,676,580 shares
issued at December 31, 2011 and 2010) |
|
|
1,832 |
|
|
|
|
1,832 |
|
Capital in excess of par value |
|
|
15,156 |
|
|
|
|
14,796 |
|
Retained earnings |
|
|
140,399 |
|
|
|
|
119,641 |
|
Accumulated other comprehensive loss |
|
|
(6,022 |
) |
|
|
|
(4,466 |
) |
Deferred compensation and benefit plan trust |
|
|
(298 |
) |
|
|
|
(311 |
) |
Treasury stock, at cost (2011 461,509,656 shares; 2010 435,195,799 shares) |
|
|
(29,685 |
) |
|
|
|
(26,411 |
) |
|
|
|
|
Total Chevron Corporation Stockholders Equity |
|
|
121,382 |
|
|
|
|
105,081 |
|
|
|
|
|
Noncontrolling interests |
|
|
799 |
|
|
|
|
730 |
|
|
|
|
|
Total Equity |
|
|
122,181 |
|
|
|
|
105,811 |
|
|
|
|
|
Total Liabilities and Equity |
|
$ |
209,474 |
|
|
|
$ |
184,769 |
|
|
|
|
|
|
See accompanying Notes to the Consolidated Financial Statements.
FS-25
Consolidated Statement of Cash Flows
Millions of dollars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31 |
|
|
|
2011 |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
|
$ |
27,008 |
|
|
|
$ |
19,136 |
|
|
$ |
10,563 |
|
Adjustments |
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
12,911 |
|
|
|
|
13,063 |
|
|
|
12,110 |
|
Dry hole expense |
|
|
377 |
|
|
|
|
496 |
|
|
|
552 |
|
Distributions less than income from equity affiliates |
|
|
(570 |
) |
|
|
|
(501 |
) |
|
|
(103 |
) |
Net before-tax gains on asset retirements and sales |
|
|
(1,495 |
) |
|
|
|
(1,004 |
) |
|
|
(1,255 |
) |
Net foreign currency effects |
|
|
(103 |
) |
|
|
|
251 |
|
|
|
466 |
|
Deferred income tax provision |
|
|
1,589 |
|
|
|
|
559 |
|
|
|
467 |
|
Net decrease (increase) in operating working capital |
|
|
2,318 |
|
|
|
|
76 |
|
|
|
(2,301 |
) |
Increase in long-term receivables |
|
|
(150 |
) |
|
|
|
(12 |
) |
|
|
(258 |
) |
Decrease in other deferred charges |
|
|
341 |
|
|
|
|
48 |
|
|
|
201 |
|
Cash contributions to employee pension plans |
|
|
(1,467 |
) |
|
|
|
(1,450 |
) |
|
|
(1,739 |
) |
Other |
|
|
339 |
|
|
|
|
697 |
|
|
|
670 |
|
|
|
|
|
Net Cash Provided by Operating Activities |
|
|
41,098 |
|
|
|
|
31,359 |
|
|
|
19,373 |
|
|
|
|
|
Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of Atlas Energy |
|
|
(3,009 |
) |
|
|
|
|
|
|
|
|
|
Advance to Atlas Energy |
|
|
(403 |
) |
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(26,500 |
) |
|
|
|
(19,612 |
) |
|
|
(19,843 |
) |
Proceeds and deposits related to asset sales |
|
|
3,517 |
|
|
|
|
1,995 |
|
|
|
2,564 |
|
Net purchases of time deposits |
|
|
(1,104 |
) |
|
|
|
(2,855 |
) |
|
|
|
|
Net (purchases) sales of marketable securities |
|
|
(74 |
) |
|
|
|
(49 |
) |
|
|
127 |
|
Repayment of loans by equity affiliates |
|
|
339 |
|
|
|
|
338 |
|
|
|
336 |
|
Net (purchases) sales of other short-term investments |
|
|
(255 |
) |
|
|
|
(732 |
) |
|
|
244 |
|
|
|
|
|
Net Cash Used for Investing Activities |
|
|
(27,489 |
) |
|
|
|
(20,915 |
) |
|
|
(16,572 |
) |
|
|
|
|
Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net borrowings (payments) of short-term obligations |
|
|
23 |
|
|
|
|
(212 |
) |
|
|
(3,192 |
) |
Proceeds from issuances of long-term debt |
|
|
377 |
|
|
|
|
1,250 |
|
|
|
5,347 |
|
Repayments of long-term debt and other financing obligations |
|
|
(2,769 |
) |
|
|
|
(156 |
) |
|
|
(496 |
) |
Cash dividends common stock |
|
|
(6,139 |
) |
|
|
|
(5,674 |
) |
|
|
(5,302 |
) |
Distributions to noncontrolling interests |
|
|
(71 |
) |
|
|
|
(72 |
) |
|
|
(71 |
) |
Net (purchases) sales of treasury shares |
|
|
(3,193 |
) |
|
|
|
(306 |
) |
|
|
168 |
|
|
|
|
|
Net Cash Used for Financing Activities |
|
|
(11,772 |
) |
|
|
|
(5,170 |
) |
|
|
(3,546 |
) |
|
|
|
|
Effect of Exchange Rate Changes
on Cash and Cash Equivalents |
|
|
(33 |
) |
|
|
|
70 |
|
|
|
114 |
|
|
|
|
|
Net Change in Cash and Cash Equivalents |
|
|
1,804 |
|
|
|
|
5,344 |
|
|
|
(631 |
) |
Cash and Cash Equivalents at January 1 |
|
|
14,060 |
|
|
|
|
8,716 |
|
|
|
9,347 |
|
|
|
|
|
Cash and Cash Equivalents at December 31 |
|
$ |
15,864 |
|
|
|
$ |
14,060 |
|
|
$ |
8,716 |
|
|
|
|
|
See accompanying Notes to the Consolidated Financial Statements.
FS-26
Consolidated Statement of Equity
Shares in thousands; amounts in millions of dollars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011 |
|
|
|
2010 |
|
|
2009 |
|
|
|
Shares |
|
|
Amount |
|
|
|
Shares |
|
|
Amount |
|
|
Shares |
|
|
Amount |
|
|
|
|
|
Preferred Stock |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
$ |
|
|
|
|
|
|
|
$ |
|
|
|
|
|
|
Common Stock |
|
|
2,442,677 |
|
|
$ |
1,832 |
|
|
|
|
2,442,677 |
|
|
$ |
1,832 |
|
|
|
2,442,677 |
|
|
$ |
1,832 |
|
|
|
|
|
Capital in Excess of Par |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1 |
|
|
|
|
|
$ |
14,796 |
|
|
|
|
|
|
|
$ |
14,631 |
|
|
|
|
|
|
$ |
14,448 |
|
Treasury stock transactions |
|
|
|
|
|
|
360 |
|
|
|
|
|
|
|
|
165 |
|
|
|
|
|
|
|
183 |
|
|
|
|
|
|
Balance at December 31 |
|
|
|
|
|
$ |
15,156 |
|
|
|
|
|
|
|
$ |
14,796 |
|
|
|
|
|
|
$ |
14,631 |
|
|
|
|
|
Retained Earnings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1 |
|
|
|
|
|
$ |
119,641 |
|
|
|
|
|
|
|
$ |
106,289 |
|
|
|
|
|
|
$ |
101,102 |
|
Net income attributable to Chevron Corporation |
|
|
|
|
|
|
26,895 |
|
|
|
|
|
|
|
|
19,024 |
|
|
|
|
|
|
|
10,483 |
|
Cash dividends on common stock |
|
|
|
|
|
|
(6,139 |
) |
|
|
|
|
|
|
|
(5,674 |
) |
|
|
|
|
|
|
(5,302 |
) |
Tax benefit from dividends paid on unallocated ESOP shares and other |
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
6 |
|
|
|
|
|
|
Balance at December 31 |
|
|
|
|
|
$ |
140,399 |
|
|
|
|
|
|
|
$ |
119,641 |
|
|
|
|
|
|
$ |
106,289 |
|
|
|
|
|
Accumulated Other Comprehensive Loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Currency translation adjustment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1 |
|
|
|
|
|
$ |
(105 |
) |
|
|
|
|
|
|
$ |
(111 |
) |
|
|
|
|
|
$ |
(171 |
) |
Change during year |
|
|
|
|
|
|
17 |
|
|
|
|
|
|
|
|
6 |
|
|
|
|
|
|
|
60 |
|
|
|
|
|
|
Balance at December 31 |
|
|
|
|
|
$ |
(88 |
) |
|
|
|
|
|
|
$ |
(105 |
) |
|
|
|
|
|
$ |
(111 |
) |
Pension and other postretirement benefit plans |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1 |
|
|
|
|
|
$ |
(4,475 |
) |
|
|
|
|
|
|
$ |
(4,308 |
) |
|
|
|
|
|
$ |
(3,909 |
) |
Change during year |
|
|
|
|
|
|
(1,581 |
) |
|
|
|
|
|
|
|
(167 |
) |
|
|
|
|
|
|
(399 |
) |
|
|
|
|
|
Balance at December 31 |
|
|
|
|
|
$ |
(6,056 |
) |
|
|
|
|
|
|
$ |
(4,475 |
) |
|
|
|
|
|
$ |
(4,308 |
) |
Unrealized net holding gain on securities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1 |
|
|
|
|
|
$ |
11 |
|
|
|
|
|
|
|
$ |
15 |
|
|
|
|
|
|
$ |
13 |
|
Change during year |
|
|
|
|
|
|
(11 |
) |
|
|
|
|
|
|
|
(4 |
) |
|
|
|
|
|
|
2 |
|
|
|
|
|
|
Balance at December 31 |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
$ |
11 |
|
|
|
|
|
|
$ |
15 |
|
Net derivatives gain (loss) on hedge transactions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1 |
|
|
|
|
|
$ |
103 |
|
|
|
|
|
|
|
$ |
83 |
|
|
|
|
|
|
$ |
143 |
|
Change during year |
|
|
|
|
|
|
19 |
|
|
|
|
|
|
|
|
20 |
|
|
|
|
|
|
|
(60 |
) |
|
|
|
|
|
Balance at December 31 |
|
|
|
|
|
$ |
122 |
|
|
|
|
|
|
|
$ |
103 |
|
|
|
|
|
|
$ |
83 |
|
|
|
|
|
|
Balance at December 31 |
|
|
|
|
|
$ |
(6,022 |
) |
|
|
|
|
|
|
$ |
(4,466 |
) |
|
|
|
|
|
$ |
(4,321 |
) |
|
|
|
|
Deferred Compensation and Benefit Plan Trust |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred Compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1 |
|
|
|
|
|
$ |
(71 |
) |
|
|
|
|
|
|
$ |
(109 |
) |
|
|
|
|
|
$ |
(194 |
) |
Net reduction of ESOP debt and other |
|
|
|
|
|
|
13 |
|
|
|
|
|
|
|
|
38 |
|
|
|
|
|
|
|
85 |
|
|
|
|
|
|
Balance at December 31 |
|
|
|
|
|
|
(58 |
) |
|
|
|
|
|
|
|
(71 |
) |
|
|
|
|
|
|
(109 |
) |
Benefit Plan Trust (Common Stock) |
|
|
14,168 |
|
|
|
(240 |
) |
|
|
|
14,168 |
|
|
|
(240 |
) |
|
|
14,168 |
|
|
|
(240 |
) |
|
|
|
|
|
Balance at December 31 |
|
|
14,168 |
|
|
$ |
(298 |
) |
|
|
|
14,168 |
|
|
$ |
(311 |
) |
|
|
14,168 |
|
|
$ |
(349 |
) |
|
|
|
|
Treasury Stock at Cost |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1 |
|
|
435,196 |
|
|
$ |
(26,411 |
) |
|
|
|
434,955 |
|
|
$ |
(26,168 |
) |
|
|
438,445 |
|
|
$ |
(26,376 |
) |
Purchases |
|
|
42,424 |
|
|
|
(4,262 |
) |
|
|
|
9,091 |
|
|
|
(775 |
) |
|
|
85 |
|
|
|
(6 |
) |
Issuances mainly employee benefit plans |
|
|
(16,110 |
) |
|
|
988 |
|
|
|
|
(8,850 |
) |
|
|
532 |
|
|
|
(3,575 |
) |
|
|
214 |
|
|
|
|
|
|
Balance at December 31 |
|
|
461,510 |
|
|
$ |
(29,685 |
) |
|
|
|
435,196 |
|
|
$ |
(26,411 |
) |
|
|
434,955 |
|
|
$ |
(26,168 |
) |
|
|
|
|
Total Chevron Corporation Stockholders Equity at December 31 |
|
|
|
|
|
$ |
121,382 |
|
|
|
|
|
|
|
$ |
105,081 |
|
|
|
|
|
|
$ |
91,914 |
|
|
|
|
|
Noncontrolling Interests |
|
|
|
|
|
$ |
799 |
|
|
|
|
|
|
|
$ |
730 |
|
|
|
|
|
|
$ |
647 |
|
|
|
|
|
Total Equity |
|
|
|
|
|
$ |
122,181 |
|
|
|
|
|
|
|
$ |
105,811 |
|
|
|
|
|
|
$ |
92,561 |
|
|
|
|
|
See accompanying Notes to the Consolidated Financial Statements.
FS-27
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 1
Summary of Significant Accounting Policies
General Upstream operations consist primarily of
exploring for, developing and producing crude oil and natural gas; liquefaction, transportation and
regasification associated with liquefied natural gas (LNG); transporting crude oil by major
international oil export pipelines; processing, transporting, storage and marketing of natural gas;
and a gas-to-liquids project. Downstream operations relate primarily to refining crude oil into
petroleum products; marketing of crude oil and refined products; transporting crude oil and refined
products by pipeline, marine vessel, motor equipment and rail car; and manufacturing and marketing
of commodity petrochemicals, plastics for industrial uses, and additives for fuels and lubricant
oils.
The companys Consolidated Financial Statements are prepared in accordance with accounting
principles generally accepted in the United States of America. These require the use of estimates
and assumptions that affect the assets, liabilities, revenues and expenses reported in the
financial statements, as well as amounts included in the notes thereto, including discussion and
disclosure of contingent liabilities. Although the company uses its best estimates and judgments,
actual results could differ from these estimates as future confirming events occur.
Subsidiary and Affiliated Companies The Consolidated Financial Statements include the accounts of
controlled subsidiary companies more than 50 percent-owned and any variable-interest entities in
which the company is the primary beneficiary. Undivided interests in oil and gas joint ventures and
certain other assets are consolidated on a proportionate basis. Investments in and advances to
affiliates in which the company has a substantial ownership interest of approximately 20 percent to
50 percent, or for which the company exercises significant influence but not control over policy
decisions, are accounted for by the equity method. 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.
Investments are assessed for possible impairment when events indicate that the fair value of
the investment may be below the companys carrying value. When such a condition is deemed to be
other than temporary, the carrying value of the investment is written down to its fair value, and
the amount of the write-down is included in net income. In making the determination as to whether a
decline is other than temporary, the company considers such factors as the duration and extent of
the decline, the investees financial 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.
Differences between the companys carrying value of an equity investment and its underlying equity
in the net assets of the affiliate are assigned to the extent practicable to specific assets and
liabilities based on the companys analysis of the various factors giving rise to the difference.
When appropriate, the companys share of the affiliates reported earnings is adjusted quarterly to
reflect the difference between these allocated values and the affiliates historical book values.
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, gains and losses from derivative
instruments are reported in current income. The company may enter into interest rate swaps from
time to time as part of its overall strategy to manage the interest rate risk on its debt. Interest
rate swaps related to a portion of the companys fixed-rate debt, if any, may be accounted for as
fair value hedges. Interest rate swaps related to floating-rate debt, if any, are recorded at fair
value on the balance sheet with resulting gains and losses reflected in income. Where Chevron is a
party to master netting arrangements, fair value receivable and payable amounts recognized for
derivative instruments executed with the same counterparty are generally offset on the balance
sheet.
Short-Term Investments All short-term investments are classified as available for sale and are in
highly liquid debt securities. Those investments that are part of the companys cash management
portfolio and have original maturities of three months or less are reported as Cash equivalents.
Bank time deposits with maturities greater than 90 days are reported as Time deposits. The
balance of short-term investments is reported as Marketable securities and is marked-to-market,
with any unrealized gains or losses included in Other comprehensive income.
Inventories Crude oil, petroleum products and chemicals inventories are generally stated at cost,
using a last-in, first-out method. In the aggregate, these costs are below market. Materials,
supplies and other inventories generally are stated at average cost.
FS-28
Note 1 Summary of Significant Accounting Policies - Continued
Properties, Plant and Equipment The successful efforts method is used for crude oil
and natural gas exploration and production activities. All costs for development wells, related
plant and equipment, proved mineral interests in crude oil and natural gas properties, and related
asset retirement obligation (ARO) assets are capitalized. Costs of exploratory wells are
capitalized pending determination of whether the wells found proved reserves. Costs of wells that
are assigned proved reserves remain capitalized. Costs also are capitalized for exploratory wells
that have found crude oil and natural gas reserves even if the reserves cannot be classified as
proved when the drilling is completed, provided the exploratory well has found a sufficient
quantity of reserves to justify its completion as a producing well and the company is making
sufficient progress assessing the reserves and the economic and operating viability of the project.
All other exploratory wells and costs are expensed. Refer to Note 19, beginning on page FS-47, for
additional discussion of accounting for suspended exploratory well costs.
Long-lived assets to be held and used, including proved crude oil and natural gas properties,
are assessed for possible impairment by comparing their carrying values with their associated
undiscounted, future net before-tax cash flows. Events that can trigger assessments for possible
impairments include write-downs of proved reserves based on field performance, significant
decreases in the market value of an asset, significant change in the extent or manner of use of or
a physical change in an asset, and a more-likely-than-not expectation that a long-lived asset or
asset group will be sold or otherwise disposed of significantly sooner than the end of its
previously