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, 2008
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 1-368-2
Chevron Corporation
(Exact name of registrant as specified in its charter)
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Delaware
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94-0890210
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6001 Bollinger Canyon Road,
San Ramon, California 94583-2324
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(State or other jurisdiction of
incorporation or organization)
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(I.R.S. Employer
Identification Number)
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(Address of principal executive offices) (Zip Code)
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Registrants telephone number, including area code
(925) 842-1000
Securities registered pursuant to Section 12(b) of the Act:
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Title of Each Class
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Name of Each Exchange
on Which Registered
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Common
stock, par value $.75 per share
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New
York Stock Exchange, Inc.
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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 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. (Check one):
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Large
accelerated filer þ
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Accelerated filer o
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Non-accelerated filer o
(Do not check if a smaller
reporting company)
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Smaller reporting company o
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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 $203,659,751,369 (As of June 30, 2008)
Number of Shares of Common Stock outstanding as of
February 20, 2009 2,004,559,279
DOCUMENTS INCORPORATED BY REFERENCE
(To The Extent Indicated Herein)
Notice of the 2009 Annual Meeting and 2009 Proxy Statement, to
be filed pursuant to
Rule 14a-6(b)
under the Securities Exchange Act of 1934, in connection with
the companys 2009 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 crude-oil and natural-gas prices; 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 OPEC (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 pending or future litigation; the companys
acquisition or disposition of assets; 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 30 and 31 in this report. In
addition, such statements could be affected by general domestic
and international economic and political conditions.
Unpredictable or unknown factors not discussed in this report
could also have material adverse effects on forward-looking
statements.
2
PART I
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(a)
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General
Development of Business
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Summary
Description of Chevron
Chevron
Corporation,1
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. Exploration and production
(upstream) operations consist of exploring for, developing and
producing crude oil and natural gas and also marketing natural
gas. Refining, marketing and transportation (downstream)
operations relate to refining crude oil into finished petroleum
products; marketing crude oil and the many products derived from
petroleum; and transporting crude oil, natural gas and petroleum
products by pipeline, marine vessel, motor equipment and rail
car. Chemical operations include the manufacture and marketing
of commodity petrochemicals, plastics for industrial uses, and
fuel and lubricant oil additives.
A list of the companys major subsidiaries is presented on
pages E-125
and E-126.
As of December 31, 2008, Chevron had approximately
67,000 employees (including about 5,000 service station
employees). Approximately 32,000 employees (including about
4,000 service station employees), or 48 percent, were
employed in U.S. operations.
Overview
of Petroleum Industry
Petroleum industry operations and profitability are influenced
by many factors, and individual petroleum companies have little
control over some of them. Governmental policies, particularly
in the areas of taxation, energy and the environment have a
significant impact on petroleum activities, regulating how
companies are structured and where and how companies conduct
their operations and formulate their products and, in some
cases, limiting their profits directly. Prices for crude oil and
natural gas, petroleum products and petrochemicals are generally
determined by supply and demand for these commodities. However,
some governments impose price controls on refined products such
as gasoline or diesel fuel. 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. Seasonality
is not a primary driver to changes in the companys
quarterly earnings during the year.
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 and
transportation entities 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.
1 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
Chevron
Strategic Direction
Chevrons primary objective is to create stockholder value
and achieve sustained financial returns from its operations that
will enable it to outperform its competitors. As a foundation
for achieving this objective, the company has established the
following strategies:
Strategies
for Major Businesses
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Upstream grow profitably in core
areas, build new legacy positions and commercialize the
companys equity natural-gas resource base while growing a
high-impact global gas business
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Downstream improve returns and
selectively grow, with a focus on integrated value creation
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The company also continues to invest in renewable-energy
technologies, with an objective of capturing profitable
positions.
Enabling
Strategies Companywide
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Invest in people to achieve the companys
strategies
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Leverage technology to deliver superior
performance and growth
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Build organizational capability to deliver
world-class performance in operational excellence, cost
management, capital stewardship and profitable growth
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(b) Description
of Business and Properties
The upstream, downstream and chemicals activities of the company
and its equity affiliates are widely dispersed geographically,
with operations in North America, South America, Europe, Africa,
the Middle East, Asia and Australia. Tabulations of segment
sales and other operating revenues, earnings and income taxes
for the three years ending December 31, 2008, and assets as
of the end of 2008 and 2007 for the United States
and the companys international geographic
areas are in Note 9 to the Consolidated
Financial Statements beginning on
page FS-38.
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-41 to FS-43.
Capital
and Exploratory Expenditures
Total expenditures for 2008 were $22.8 billion, including
$2.3 billion for Chevrons share of expenditures by
affiliated companies, which did not require cash outlays by the
company. In 2007 and 2006, expenditures were $20 billion
and $16.6 billion, respectively, including the
companys share of affiliates expenditures of
$2.3 billion and $1.9 billion in the corresponding
periods.
Of the $22.8 billion in expenditures for 2008, about
three-fourths, or $17.5 billion, was related to upstream
activities. Approximately the same percentage was also expended
for upstream operations in 2007 and 2006. International upstream
accounted for about 70 percent of the worldwide upstream
investment in each of the three years, reflecting the
companys continuing focus on opportunities that are
available outside the United States.
In 2009, the company estimates capital and exploratory
expenditures will be $22.8 billion, including
$1.8 billion of spending by affiliates. About three-fourths
of the total, or $17.5 billion, is budgeted for exploration
and production activities, with $13.9 billion of that
amount outside the United States.
Refer also to a discussion of the companys capital and
exploratory expenditures on
page FS-11
and FS-12.
Upstream
Exploration and Production
The table on the following page summarizes the net production of
liquids and natural gas for 2008 and 2007 by the company and its
affiliates.
4
Net
Production of Crude Oil and Natural Gas Liquids and Natural
Gas1
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Components of Oil-Equivalent
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Crude Oil & Natural Gas
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Oil-Equivalent (Thousands
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Liquids (Thousands of
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Natural Gas (Millions of
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of Barrels per Day)
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Barrels per Day)
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Cubic Feet per Day)
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2008
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2007
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2008
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2007
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2008
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2007
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United States:
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California
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215
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221
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201
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205
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88
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97
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Gulf of Mexico
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160
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214
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86
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118
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439
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576
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Texas (Onshore)
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149
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153
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76
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77
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441
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457
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Other States
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147
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155
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58
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60
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533
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569
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Total United States
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671
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743
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421
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460
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1,501
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1,699
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Africa:
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Angola
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154
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179
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|
145
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171
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52
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48
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Nigeria
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154
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129
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142
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126
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72
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15
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Chad
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29
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32
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28
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31
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5
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4
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Republic of the Congo
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13
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8
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11
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7
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12
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7
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Democratic Republic of the Congo
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2
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3
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2
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3
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1
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2
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Total Africa
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352
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351
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328
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338
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|
142
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|
76
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Asia-Pacific:
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Thailand
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217
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224
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67
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71
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894
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916
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Partitioned Neutral Zone
(PNZ)2
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106
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|
112
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103
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109
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20
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17
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Australia
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|
96
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100
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34
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39
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376
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372
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Bangladesh
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71
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|
47
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|
2
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|
|
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2
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|
|
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414
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275
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Kazakhstan
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66
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|
|
66
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|
|
41
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|
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41
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|
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153
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149
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Azerbaijan
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29
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61
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28
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|
|
60
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7
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5
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Philippines
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26
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|
|
26
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|
|
5
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5
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|
|
|
128
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|
|
|
126
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|
China
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22
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26
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|
19
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|
22
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22
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|
22
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|
Myanmar
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|
|
15
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|
17
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|
|
|
|
|
|
|
|
|
|
|
89
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|
|
100
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Total Asia-Pacific
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648
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679
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|
299
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349
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2,103
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1,982
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|
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|
|
|
|
|
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|
|
|
|
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Indonesia
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|
|
235
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|
|
|
241
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|
|
|
182
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|
|
|
195
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|
|
|
319
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|
|
|
277
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|
Other International:
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|
|
|
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|
|
|
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|
|
|
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|
United Kingdom
|
|
|
106
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|
|
|
115
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|
|
71
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|
|
|
78
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|
|
|
208
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|
|
|
220
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|
Denmark
|
|
|
61
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|
|
|
63
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|
|
|
37
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|
|
|
41
|
|
|
|
142
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|
|
|
132
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|
Argentina
|
|
|
44
|
|
|
|
47
|
|
|
|
37
|
|
|
|
39
|
|
|
|
45
|
|
|
|
50
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|
Canada
|
|
|
37
|
|
|
|
36
|
|
|
|
36
|
|
|
|
35
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|
|
|
4
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|
|
|
5
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|
Colombia
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|
|
35
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|
|
|
30
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|
|
|
|
|
|
|
|
|
|
|
209
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|
|
|
178
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|
Trinidad and Tobago
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|
|
32
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|
|
|
29
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|
|
|
|
|
|
|
|
|
|
|
189
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|
|
|
174
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|
Netherlands
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|
9
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|
|
|
4
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|
|
|
2
|
|
|
|
3
|
|
|
|
40
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|
|
|
5
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|
Norway
|
|
|
6
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|
|
|
6
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|
|
|
6
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|
|
|
6
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|
|
|
1
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|
|
|
1
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Total Other International
|
|
|
330
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|
|
|
330
|
|
|
|
189
|
|
|
|
202
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|
|
|
838
|
|
|
|
765
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total International
|
|
|
1,565
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|
|
|
1,601
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|
998
|
|
|
|
1,084
|
|
|
|
3,402
|
|
|
|
3,100
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Consolidated Operations
|
|
|
2,236
|
|
|
|
2,344
|
|
|
|
1,419
|
|
|
|
1,544
|
|
|
|
4,903
|
|
|
|
4,799
|
|
Equity
Affiliates3
|
|
|
267
|
|
|
|
248
|
|
|
|
230
|
|
|
|
212
|
|
|
|
222
|
|
|
|
220
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Including
Affiliates4
|
|
|
2,503
|
|
|
|
2,592
|
|
|
|
1,649
|
|
|
|
1,756
|
|
|
|
5,125
|
|
|
|
5,019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 Excludes
Athabasca oil sands
production, net:
|
|
|
27
|
|
|
|
27
|
|
|
|
27
|
|
|
|
27
|
|
|
|
|
|
|
|
|
|
2 Located
between Saudi Arabia and Kuwait.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3 Volumes
represent Chevrons share of production by affiliates,
including Tengizchevroil (TCO) in Kazakhstan and Petroboscan,
Petroindependiente and Petropiar/Hamaca in Venezuela.
|
4 Volumes
include natural gas consumed in operations of 520 million
and 498 million cubic feet per day in 2008 and 2007,
respectively.
|
Worldwide oil-equivalent production, including volumes from oil
sands (refer to footnote 1 above), was 2.53 million barrels
per day, down about 3 percent from 2007. The decline was
mostly attributable to damages to facilities caused by September
2008 hurricanes in the U.S. Gulf of Mexico and the impact
of higher prices on certain production-sharing and
variable-royalty agreements outside the United States. Refer to
the Results of Operations section beginning on
page FS-6
for a detailed discussion of the factors explaining the
2006 2008 changes in production for crude oil and
natural gas liquids and natural gas.
5
The company estimates that its average worldwide oil-equivalent
production in 2009 will be approximately 2.63 million
barrels per day. This estimate is subject to many uncertainties,
including quotas that may be imposed by OPEC, the price effect
on production volumes calculated under cost-recovery and
variable-royalty provisions of certain contracts, changes in
fiscal terms or restrictions on the scope of company operations,
delays in project
start-ups,
fluctuations in demand for natural gas in various markets, and
production that may have to be shut in due to weather
conditions, civil unrest, changing geopolitics or other
disruptions to operations. Future production levels also are
affected by the size and number of economic investment
opportunities and, for new large-scale projects, the time lag
between initial exploration and the beginning of production.
Refer to the Review of Ongoing Exploration and Production
Activities in Key Areas, beginning on page 9, for a
discussion of the companys major oil and gas development
projects.
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 and natural gas liquids and per thousand cubic feet of
natural gas produced and the average production cost per
oil-equivalent barrel for 2008, 2007 and 2006.
Gross and
Net Productive Wells
The following table summarizes gross and net productive wells at
year-end 2008 for the company and its affiliates:
Productive
Oil and Gas
Wells1 at
December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive2
|
|
|
Productive2
|
|
|
|
Oil Wells
|
|
|
Gas Wells
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
United States:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
California
|
|
|
25,726
|
|
|
|
23,921
|
|
|
|
188
|
|
|
|
44
|
|
Gulf of Mexico
|
|
|
1,489
|
|
|
|
1,214
|
|
|
|
922
|
|
|
|
701
|
|
Other U.S.
|
|
|
23,729
|
|
|
|
8,460
|
|
|
|
10,587
|
|
|
|
4,824
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total United States
|
|
|
50,944
|
|
|
|
33,595
|
|
|
|
11,697
|
|
|
|
5,569
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Africa
|
|
|
2,126
|
|
|
|
723
|
|
|
|
17
|
|
|
|
7
|
|
Asia-Pacific
|
|
|
2,479
|
|
|
|
1,150
|
|
|
|
2,468
|
|
|
|
1,560
|
|
Indonesia
|
|
|
7,879
|
|
|
|
7,737
|
|
|
|
203
|
|
|
|
165
|
|
Other International
|
|
|
1,091
|
|
|
|
680
|
|
|
|
275
|
|
|
|
105
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total International
|
|
|
13,575
|
|
|
|
10,290
|
|
|
|
2,963
|
|
|
|
1,837
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Consolidated Companies
|
|
|
64,519
|
|
|
|
43,885
|
|
|
|
14,660
|
|
|
|
7,406
|
|
Equity in Affiliates
|
|
|
1,174
|
|
|
|
413
|
|
|
|
7
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Including Affiliates
|
|
|
65,693
|
|
|
|
44,298
|
|
|
|
14,667
|
|
|
|
7,408
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Multiple completion wells included above:
|
|
|
881
|
|
|
|
549
|
|
|
|
411
|
|
|
|
318
|
|
|
|
|
1 |
|
Includes wells producing or capable
of producing and injection wells temporarily functioning as
producing wells. Wells that produce both oil and gas are
classified as oil wells.
|
2 |
|
Gross wells include the total
number of wells in which the company has an interest. Net wells
include wholly owned wells and the sum of the companys
fractional interests in gross wells.
|
Reserves
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 2006 and each
year-end from 2006 through 2008, and an accompanying discussion
of major changes to proved reserves by geographic area for the
three-year period ending December 31, 2008. During 2008,
the company provided oil and gas reserves estimates for 2007 to
the Department of Energy, Energy Information Administration
(EIA), that agree with the 2007 reserve volumes in Table V. This
reporting fulfilled the requirement that such estimates are to
be consistent with, and do not differ more than 5 percent
from, the information furnished to the Securities and Exchange
Commission in the companys 2007 Annual Report on
Form 10-K.
During 2009, the company will file estimates of oil and gas
reserves with the Department of Energy, EIA, consistent with the
2008 reserve data reported in Table V.
6
The net proved-reserve balances at the end of each of the three
years 2006 through 2008 are shown in the table below:
Net
Proved Reserves at December 31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Liquids* Millions of barrels
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated Companies
|
|
|
4,735
|
|
|
|
4,665
|
|
|
|
5,294
|
|
Affiliated Companies
|
|
|
2,615
|
|
|
|
2,422
|
|
|
|
2,512
|
|
Natural Gas Billions of cubic feet
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated Companies
|
|
|
19,022
|
|
|
|
19,137
|
|
|
|
19,910
|
|
Affiliated Companies
|
|
|
4,053
|
|
|
|
3,003
|
|
|
|
2,974
|
|
Total Oil-Equivalent Millions of barrels
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated Companies
|
|
|
7,905
|
|
|
|
7,855
|
|
|
|
8,612
|
|
Affiliated Companies
|
|
|
3,291
|
|
|
|
2,922
|
|
|
|
3,008
|
|
|
|
|
*
|
|
Crude oil, condensate and natural
gas liquids
|
Acreage
At December 31, 2008, the company owned or had under lease
or similar agreements undeveloped and developed oil and gas
properties located throughout the world. The geographical
distribution of the companys acreage is shown in the
following table.
Acreage1
at December 31, 2008
(Thousands of Acres)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed and
|
|
|
|
Undeveloped2
|
|
|
Developed2
|
|
|
Undeveloped
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
United States:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
California
|
|
|
138
|
|
|
|
122
|
|
|
|
183
|
|
|
|
176
|
|
|
|
321
|
|
|
|
298
|
|
Gulf of Mexico
|
|
|
2,108
|
|
|
|
1,500
|
|
|
|
1,568
|
|
|
|
1,141
|
|
|
|
3,676
|
|
|
|
2,641
|
|
Other U.S.
|
|
|
3,441
|
|
|
|
2,784
|
|
|
|
4,461
|
|
|
|
2,497
|
|
|
|
7,902
|
|
|
|
5,281
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total United States
|
|
|
5,687
|
|
|
|
4,406
|
|
|
|
6,212
|
|
|
|
3,814
|
|
|
|
11,899
|
|
|
|
8,220
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Africa
|
|
|
17,686
|
|
|
|
7,710
|
|
|
|
2,487
|
|
|
|
921
|
|
|
|
20,173
|
|
|
|
8,631
|
|
Asia-Pacific
|
|
|
45,429
|
|
|
|
22,447
|
|
|
|
5,937
|
|
|
|
2,649
|
|
|
|
51,366
|
|
|
|
25,096
|
|
Indonesia
|
|
|
8,031
|
|
|
|
5,348
|
|
|
|
383
|
|
|
|
341
|
|
|
|
8,414
|
|
|
|
5,689
|
|
Other International
|
|
|
35,236
|
|
|
|
19,957
|
|
|
|
1,924
|
|
|
|
613
|
|
|
|
37,160
|
|
|
|
20,570
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total International
|
|
|
106,382
|
|
|
|
55,462
|
|
|
|
10,731
|
|
|
|
4,524
|
|
|
|
117,113
|
|
|
|
59,986
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Consolidated Companies
|
|
|
112,069
|
|
|
|
59,868
|
|
|
|
16,943
|
|
|
|
8,338
|
|
|
|
129,012
|
|
|
|
68,206
|
|
Equity in Affiliates
|
|
|
640
|
|
|
|
300
|
|
|
|
259
|
|
|
|
104
|
|
|
|
899
|
|
|
|
404
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Including Affiliates
|
|
|
112,709
|
|
|
|
60,168
|
|
|
|
17,202
|
|
|
|
8,442
|
|
|
|
129,911
|
|
|
|
68,610
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
Gross acreage includes the total
number of acres in all tracts in which the company has an
interest. Net acreage includes wholly owned interests and the
sum of the companys fractional interests in gross acreage.
|
2 |
|
Developed acreage is spaced or
assignable to productive wells. Undeveloped acreage is acreage
on which wells have not been drilled or completed to permit
commercial production and that may contain undeveloped proved
reserves. The gross undeveloped acres that will expire in 2009,
2010 and 2011 if production is not established by certain
required dates are 5,707, 8,290 and 4,720, respectively.
|
7
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 and affiliates 414 billion cubic
feet of natural gas through 2011. The company believes it can
satisfy these contracts from quantities available from
production of the companys proved developed
U.S. reserves. These contracts include a variety of pricing
terms, including both index and fixed-price contracts.
Outside the United States, the company is contractually
committed to deliver to third parties a total of
865 billion cubic feet of natural gas from 2009 through
2011 from Argentina, Australia, Canada, Colombia, Denmark and
the Philippines. 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 Argentina,
Australia, Colombia, Denmark and the Philippines. The company
plans to meet its Canadian contractual delivery commitments of
28 billion cubic feet through third-party purchases.
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 2008,
2007 and 2006.
The table below 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, 2008. 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.
Development
Well Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wells Drilling
|
|
|
Net Wells
Completed1
|
|
|
|
at 12/31/082
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
Gross
|
|
|
Net
|
|
|
Prod.
|
|
|
Dry
|
|
|
Prod.
|
|
|
Dry
|
|
|
Prod.
|
|
|
Dry
|
|
|
United States:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
California
|
|
|
8
|
|
|
|
1
|
|
|
|
533
|
|
|
|
|
|
|
|
620
|
|
|
|
|
|
|
|
600
|
|
|
|
|
|
Gulf of Mexico
|
|
|
44
|
|
|
|
25
|
|
|
|
26
|
|
|
|
3
|
|
|
|
30
|
|
|
|
1
|
|
|
|
34
|
|
|
|
5
|
|
Other U.S.
|
|
|
9
|
|
|
|
8
|
|
|
|
287
|
|
|
|
1
|
|
|
|
225
|
|
|
|
4
|
|
|
|
317
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total United States
|
|
|
61
|
|
|
|
34
|
|
|
|
846
|
|
|
|
4
|
|
|
|
875
|
|
|
|
5
|
|
|
|
951
|
|
|
|
11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Africa
|
|
|
13
|
|
|
|
8
|
|
|
|
33
|
|
|
|
|
|
|
|
43
|
|
|
|
|
|
|
|
45
|
|
|
|
2
|
|
Asia-Pacific
|
|
|
13
|
|
|
|
4
|
|
|
|
203
|
|
|
|
1
|
|
|
|
223
|
|
|
|
|
|
|
|
235
|
|
|
|
1
|
|
Indonesia
|
|
|
2
|
|
|
|
2
|
|
|
|
462
|
|
|
|
|
|
|
|
374
|
|
|
|
|
|
|
|
258
|
|
|
|
|
|
Other International
|
|
|
7
|
|
|
|
2
|
|
|
|
41
|
|
|
|
|
|
|
|
52
|
|
|
|
|
|
|
|
43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total International
|
|
|
35
|
|
|
|
16
|
|
|
|
739
|
|
|
|
1
|
|
|
|
692
|
|
|
|
|
|
|
|
581
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Consolidated Companies
|
|
|
96
|
|
|
|
50
|
|
|
|
1,585
|
|
|
|
5
|
|
|
|
1,567
|
|
|
|
5
|
|
|
|
1,532
|
|
|
|
14
|
|
Equity in Affiliates
|
|
|
2
|
|
|
|
1
|
|
|
|
16
|
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Including Affiliates
|
|
|
98
|
|
|
|
51
|
|
|
|
1,601
|
|
|
|
5
|
|
|
|
1,570
|
|
|
|
5
|
|
|
|
1,545
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
Indicates the fractional number of
wells completed during the year, regardless of when drilling was
initiated. Completion refers to the installation of permanent
equipment for the production of crude oil or natural gas or, in
the case of a dry well, the reporting of abandonment to the
appropriate agency.
|
2 |
|
Represents wells in the process of
drilling, including wells for which drilling was not completed
and which were temporarily suspended at the end of 2008. Gross
wells include the total number of wells in which the company has
an interest. Net wells include wholly owned wells and the sum of
the companys fractional interests in gross wells.
|
8
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, 2008. 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
Completed1,2
|
|
|
|
at
12/31/083
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
Gross
|
|
|
Net
|
|
|
Prod.
|
|
|
Dry
|
|
|
Prod.
|
|
|
Dry
|
|
|
Prod.
|
|
|
Dry
|
|
|
United States:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
California
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf of Mexico
|
|
|
9
|
|
|
|
3
|
|
|
|
8
|
|
|
|
1
|
|
|
|
4
|
|
|
|
7
|
|
|
|
9
|
|
|
|
8
|
|
Other U.S.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
1
|
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total United States
|
|
|
9
|
|
|
|
3
|
|
|
|
8
|
|
|
|
2
|
|
|
|
4
|
|
|
|
8
|
|
|
|
16
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Africa
|
|
|
8
|
|
|
|
3
|
|
|
|
2
|
|
|
|
1
|
|
|
|
6
|
|
|
|
2
|
|
|
|
1
|
|
|
|
|
|
Asia-Pacific
|
|
|
4
|
|
|
|
2
|
|
|
|
10
|
|
|
|
1
|
|
|
|
14
|
|
|
|
9
|
|
|
|
18
|
|
|
|
7
|
|
Indonesia
|
|
|
|
|
|
|
|
|
|
|
4
|
|
|
|
1
|
|
|
|
1
|
|
|
|
|
|
|
|
2
|
|
|
|
|
|
Other International
|
|
|
2
|
|
|
|
|
|
|
|
39
|
|
|
|
2
|
|
|
|
41
|
|
|
|
6
|
|
|
|
6
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total International
|
|
|
14
|
|
|
|
5
|
|
|
|
55
|
|
|
|
5
|
|
|
|
62
|
|
|
|
17
|
|
|
|
27
|
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Consolidated Companies
|
|
|
23
|
|
|
|
8
|
|
|
|
63
|
|
|
|
7
|
|
|
|
66
|
|
|
|
25
|
|
|
|
43
|
|
|
|
18
|
|
Equity in Affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Including Affiliates
|
|
|
23
|
|
|
|
8
|
|
|
|
63
|
|
|
|
7
|
|
|
|
66
|
|
|
|
25
|
|
|
|
44
|
|
|
|
18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
2007 conformed to 2008 presentation.
|
2 |
|
Indicates the fractional number of
wells completed during the year, regardless of when drilling was
initiated. Completion refers to the installation of permanent
equipment for the production of crude oil or natural gas or, in
the case of a dry well, the reporting of abandonment to the
appropriate agency. Some exploratory wells are not drilled with
the intention of producing from the well bore. In such cases,
completion refers to the completion of drilling.
Further categorization of productive or dry is based on the
determination as to whether hydrocarbons in a sufficient
quantity were found to justify completion as a producing well,
whether or not the well is actually going to be completed as a
producer.
|
3 |
|
Represents wells that are in the
process of drilling but have been neither abandoned nor
completed as of the last day of the year, including wells for
which drilling was not completed and which were temporarily
suspended at the end of 2008. Does not include wells for which
drilling was completed at year-end 2008 and that were reported
as suspended wells in Note 20 beginning on
page FS-48.
Gross wells include the total number of wells in which the
company has an interest. Net wells include wholly owned wells
and the sum of the companys fractional interests in gross
wells.
|
Refer to Table I on
page FS-62
for detail of the companys exploration expenditures and
costs of unproved property acquisitions for 2008, 2007 and 2006.
Review of
Ongoing Exploration and Production Activities in Key
Areas
Chevrons 2008 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-146.
The discussion that follows references the status of proved
reserves recognition for significant long-lead-time projects not
yet on production and for projects recently placed on
production. Reserves are not discussed for recent discoveries
that have yet to advance 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.
9
Consolidated
Operations
|
|
|
|
|
|
|
|
|
Chevron has production and exploration activities in most of the worlds major hydrocarbon basins. The companys upstream strategy is to grow profitably in core areas, build new legacy positions and commercialize the companys equity natural-gas resource base while growing a high-impact global gas business. The map at left indicates Chevrons primary areas of production and exploration.
|
Upstream activities in the United States are concentrated in
California, the Gulf of Mexico, Louisiana, Texas,
New Mexico, the Rocky Mountains and Alaska. Average net
oil-equivalent production in the United States during 2008 was
671,000 barrels per day, composed of 421,000 barrels
of crude oil and natural gas liquids and 1.5 billion cubic
feet of natural gas. Refer to Table V beginning on
page FS-67
for a discussion of the net proved reserves and different
hydrocarbon characteristics for the companys major
U.S. producing areas.
|
|
|
|
|
|
|
|
|
California: The company has significant production
in the San Joaquin Valley. In 2008, average net
oil-equivalent production was 215,000 barrels per day,
composed of 196,000 barrels of crude oil, 88 million
cubic feet of natural gas and 5,000 barrels of natural gas
liquids. Approximately 84 percent of the crude-oil
production is considered heavy oil (typically with API gravity
lower than 22 degrees).
|
|
|
|
|
|
|
|
|
|
Gulf of Mexico: Average net oil-equivalent
production during 2008 for the companys combined interests
in the Gulf of Mexico shelf and deepwater areas, and the onshore
fields in the region was 160,000 barrels per day. The daily
oil-equivalent production comprised 76,000 barrels of crude
oil, 439 million cubic feet of natural gas and
10,000 barrels of natural gas liquids.
Production levels in 2008 were adversely affected by damage to
facilities caused by hurricanes Gustav and Ike in September. At
the end of 2008, approximately 50,000 barrels per day of
oil-equivalent production remained offline, with restoration of
the volumes to occur as repairs to third-party pipelines and
producing facilities are completed.
|
10
During 2008, Chevron was engaged in various development and
exploration activities in the deepwater Gulf of Mexico.
Production
start-up
occurred in fourth quarter 2008 at the 75 percent-owned and
operated Blind Faith project. The project was designed for daily
production capacity of 65,000 barrels of crude oil and
55 million cubic feet of natural gas from subsea wells tied
back to a semisubmersible hull. Proved undeveloped reserves were
initially recorded in 2005, and a portion was transferred to the
proved-developed category in 2008 coincident with project
start-up.
The production life of the field is estimated to be
approximately 20 years.
At Caesar/Tonga, the company participated in a successful
appraisal well in 2008. The Tonga and Caesar partnerships have
formed a unit agreement for the area, with Chevron having a
20 percent nonoperated working interest. First oil is
expected by 2011. Development plans include a subsea tie-back to
a nearby third-party production facility.
The company is also participating in the ultra-deep Perdido
Regional Development. The project encompasses the installation
of a producing host facility to service multiple fields,
including Chevrons 33 percent-owned Great White,
60 percent-owned Silvertip and 58 percent-owned
Tobago. Chevron has a 38 percent interest in the Perdido
Regional Host. All of these fields and the production facility
are partner-operated. Activities during 2008 included facility
construction, development drilling and spar installation. First
oil is expected in early 2010, with the facility capable of
handling 130,000 barrels of oil-equivalent per day. The
project has an expected life of approximately 25 years.
Proved undeveloped reserves related to the project were first
recorded in 2006, and the phased reclassification of these
reserves to the proved-developed category is anticipated near
the time of production
start-up.
At the 58 percent-owned and operated Tahiti Field,
development work continued following a delay in 2007 due to
metallurgical problems with the facilitys mooring
shackles, which problems have been resolved. The project is
designed as a subsea development, with the wells tied back to a
truss-spar floating production facility. Production
start-up is
expected in mid-2009. Initial booking of proved undeveloped
reserves occurred in 2003 for the project, with the transfer of
a portion of these reserves into the proved-developed category
anticipated near the time of production
start-up.
With an estimated production life of 30 years, Tahiti is
designed to have a maximum total daily production of
125,000 barrels of crude oil and 70 million cubic feet
of natural gas. In early 2009, a possible second phase of field
development was under evaluation.
Deepwater exploration activities in 2008 and early 2009 included
participation in 12 exploratory wells four wildcat
and eight appraisal. Exploratory work included the following:
|
|
|
|
|
Big Foot 60 percent-owned and operated. A
successful appraisal well was completed in first quarter 2008. A
final appraisal well began drilling in November 2008, and was
completed in January 2009. As of late February 2009, evaluation
of the drilling results was under way.
|
|
|
|
Buckskin 55 percent-owned and operated. A
successful wildcat well was completed in early 2009.
|
|
|
|
Jack & St. Malo 50 percent- and
41 percent-owned and operated interests, respectively. The
prospects are being evaluated together due to their relative
proximity. Successful appraisal wells were drilled during 2008
at both Jack and St. Malo, bringing the total wells drilled to
three at Jack and four at St. Malo.
|
|
|
|
Knotty Head 25 percent-owned and nonoperated
working interest. Subsurface studies continued during 2008 at
this 2005 discovery, with an appraisal well planned for third
quarter 2009.
|
|
|
|
Puma 22 percent-owned and nonoperated working
interest. An appraisal well began drilling in late 2008 and was
scheduled for completion in second quarter 2009.
|
|
|
|
Tubular Bells 30 percent-owned and nonoperated
working interest. An appraisal well was completed in 2008.
|
At the end of 2008, the company had not yet recognized proved
reserves for any of the exploration projects discussed above.
Besides the activities connected with the development and
exploration projects in the Gulf of Mexico, the company also has
access to liquefied natural gas (LNG) for the North America
natural gas market through the Sabine Pass LNG terminal in
Louisiana. The terminal was completed in mid-2008, and Chevron
has contracted for 1 billion cubic feet per day of
regasification capacity at the facility beginning in July 2009.
The company also has completed the permitting process to develop
the Casotte Landing regasification facility adjacent to the
companys Pascagoula refinery in Mississippi. Casotte
Landing remains a development option for Chevron to bring LNG
into the United States.
Also in the Sabine Pass area of Louisiana, the company has a
binding agreement to be one of the anchor shippers in a
3.2 billion-cubic-feet-per-day third-party-owned natural
gas pipeline. Chevron has contracted to have 1.6 billion
cubic
11
feet per day of capacity in the pipeline, of which
1 billion cubic feet per day is in a new pipeline and
600 million cubic feet per day is interconnecting capacity
to an existing pipeline. The new pipeline system, expected to be
completed in second quarter 2009, will provide access to
Chevrons Sabine and Bridgeline pipelines, which connect 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 NYMEX (New York
Mercantile Exchange).
Other U.S. Areas: Outside California and the
Gulf of Mexico, the company manages operations across the
mid-continental United States and Alaska. During 2008, the
companys U.S. production outside California and the
Gulf of Mexico averaged 296,000 net oil-equivalent barrels
per day, composed of 101,000 barrels of crude oil,
974 million cubic feet of natural gas and
33,000 barrels of natural gas liquids.
In the Piceance Basin in northwestern Colorado, the company is
continuing a natural-gas development in which it holds a
100 percent operated working interest. A pipeline to
transport the gas to a gathering system was completed in 2008
and facilities to produce 60 million cubic feet of natural
gas per day are expected to be completed in mid-2009.
Development drilling began in 2007, and reserves will be
recognized over the life of the project based upon drilling
results.
b) Africa
In Africa, the company is engaged in exploration and production
activities in Angola, Chad, Democratic Republic of the Congo,
Libya, Nigeria and Republic of the Congo.
|
|
|
|
|
|
|
|
|
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 (FST) area. Net production from these operations in 2008 averaged 154,000 barrels of oil-equivalent per day.
The company operates in areas A and B of the 39 percent-owned Block 0, which averaged 109,000 barrels per day of net liquids production in 2008. The Block 0 concession extends through 2030.
Start-up of the Mafumeira Field in Area A of Block 0 is expected in third quarter 2009, with crude-oil production ramping up to the expected maximum total of 35,000 barrels per day in 2011.
Two delineation wells were drilled in Area A. One well found commercial quantities of hydrocarbons and was placed into production during the year. The acquisition of seismic data started in late 2008 and is expected to be finalized in 2010.
Also in Area A are three gas management projects that are expected to eliminate routine flaring of natural gas by injecting excess natural gas into various reservoirs.
|
The Takula gas-processing platform started production in
December 2008. The Cabinda Gas Plant is scheduled for
start-up in
the second half of 2009. The Takula and Malongo Flare and Relief
project is scheduled for
start-up in
stages beginning in the second half of 2009 and continuing into
2011. In Area B, development drilling occurred during 2008
at the Nemba and Kokongo fields. Front-end engineering and
development (FEED) continued on the South NDola field
development.
In 31 percent-owned Block 14, net production in 2008
averaged 33,000 barrels of liquids per day. Activities in
2008 included development drilling at the Benguela Belize-Lobito
Tomboco (BBLT) project and the ongoing evaluation of the Negage
project. Development and production rights for the various
fields in Block 14 expire between 2027 and 2029.
Also in Block 14, development of the Tombua and Landana
fields continued. Installation of producing facilities was
completed in late 2008, with expected
start-up in
the second half of 2009. Production from the Landana North
reservoir is expected to continue to utilize the BBLT
infrastructure after
start-up.
The maximum total production from Tombua and Landana of
100,000 barrels of crude oil per day is expected to occur
in 2011. Proved undeveloped reserves were recognized for Tombua
and Landana in 2001 and 2002, respectively. Reclassification
from proved undeveloped to proved developed for Landana occurred
in 2006 and 2007. Further reclassification is expected between
2009 and 2012 as the
Tombua-Landana
facilities and the drilling program are completed.
12
During 2008, in the Lucapa provisional development area of
Block 14, exploratory drilling included an appraisal well
that was the second successful appraisal of the 2006 Lucapa
discovery. Studies to evaluate development alternatives at
Lucapa began in second quarter 2008. At the end of 2008, proved
reserves had not been recognized. At the 20 percent-owned
Block 2 and the 16 percent-owned FST area, combined
production during 2008 averaged 3,000 barrels of net
liquids per day.
Refer also to page 22 for a discussion of affiliate
operations in Angola.
Angola-Republic of the Congo Joint Development
Area: Chevron operates and holds a 31 percent
interest in the Lianzi Development Area located between Angola
and Republic of the Congo. In 2006, the development of the
Lianzi area was approved by a committee of representatives from
the two countries, and a conceptual field development plan was
also submitted to this committee. In late 2008, the project
entered FEED, and further development planning is scheduled in
2009.
Republic of the Congo: Chevron has a 32 percent
nonoperated working interest in the Nkossa, Nsoko and
Moho-Bilondo exploitation permits and a 29 percent
nonoperated working interest in the Kitina exploitation permit,
all of which are offshore. Net production from the Republic of
the Congo fields averaged 13,000 barrels of oil-equivalent
per day in 2008.
Production at the Moho-Bilondo subsea development project
started in April 2008. Maximum total production of
90,000 barrels of crude oil per day is expected in 2010.
Proved undeveloped reserves were initially recognized in 2001.
Transfer to the proved-developed category occurred in 2008.
Chevrons development and production rights for
Moho-Bilondo expire in 2030. One appraisal well was drilled in
the Moho-Bilondo permit area during 2008. Drilling began on an
exploration well in early 2009.
Chad/Cameroon: Chevron participates in a project to
develop crude-oil fields in southern Chad and transport the
produced volumes by pipeline to the coast of Cameroon for
export. Chevron has a 25 percent nonoperated working
interest in the producing operations and a 21 percent
interest in two affiliates that own the pipeline.
Average daily net production in 2008 was 29,000 barrels of
oil-equivalent. In late 2008, the development application for
the Timbre Field in the Doba area was approved. The Chad
producing operations are conducted under a concession that
expires in 2030. Partners relinquished rights to exploration
acreage not covered by field-development rights in February 2009.
Libya: Chevron is the operator and holds a
100 percent interest in the onshore Block 177
exploration license. A two-well exploration program is scheduled
for 2009.
|
|
|
|
|
|
|
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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 (NNPC), which owns a 60 percent interest. The company also owns varying interests in deepwater offshore blocks. In 2008, the companys net oil-equivalent production in Nigeria averaged 154,000 barrels per day, composed of 142,000 barrels of liquids and 72 million cubic feet of natural gas.
In deepwater offshore, initial production occurred in July 2008 at the 68 percent-owned and operated Agbami Field in OML 127 and OML 128. The project is a subsea design, with wells tied back to a floating production, storage and offloading (FPSO) vessel. By year-end 2008, total crude-oil production was averaging approximately 130,000 barrels per day. Maximum total production of crude oil and natural gas liquids of 250,000 barrels per day is expected to be achieved by year-end 2009. The company initially recognized proved undeveloped reserves for Agbami in 2002. A portion of the proved undeveloped reserves was reclassified to proved developed in 2008 at production start-up. The total cost for the first phase of
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this project was $7 billion. Additional development
drilling is being evaluated. The leases that contain the Agbami
Field expire in 2023 and 2024.
Also in the deepwater area, the Aparo Field in OML 132 and OML
140 and the Bonga SW Field in offshore OML 118 share a
common geologic structure and are planned to be jointly
developed under a proposed unitization agreement. Work continued
in early 2009 on agreements between Chevron and partners in OML
118. At the end of 2008, the company had not recognized proved
reserves for this project.
Chevron operates and holds a 95 percent interest in the
deepwater Nsiko discovery on OML 140. Development activities
continued in 2008, with FEED expected to commence after
commercial terms are resolved. At the end of 2008, the company
had not recognized proved reserves for this project.
The company also holds a 30 percent nonoperated working
interest in the deepwater Usan project in OML 138. The
development plans involve subsea wells producing to an FPSO
vessel. Major construction contracts were awarded in 2008, and
development drilling is scheduled to begin in the second half of
2009. Production
start-up is
scheduled for 2012. Maximum total production of
180,000 barrels of crude oil per day is expected to be
achieved within one year of
start-up.
The company recognized proved undeveloped reserves for the
project in 2004, and a portion is expected to be reclassified to
the proved-developed category near production
start-up.
Chevron participated in three successful deepwater exploration
wells during 2008. Hydrocarbons were confirmed in two wells in
OPL 214 and one well in OML 113. Additional reservoir studies
are scheduled for 2009, and one exploration well is planned
later in the year. The company has 20 percent and
18 percent nonoperated working interests in the two leases,
respectively. At the end of 2008, proved reserves had not been
recognized for these activities.
In the Niger Delta, construction is under way on the Phase 3A
expansion of the Escravos Gas Plant (EGP), which is expected to
be installed in late 2009 and start up production in 2010. Phase
3A scope includes offshore natural-gas gathering and compression
infrastructure and a second gas processing facility, which
potentially would increase processing capacity from
285 million to 680 million cubic feet of natural gas
per day and increase LPG and condensate export capacity from
15,000 to 58,000 barrels per day. EGP Phase 3A is designed
to process natural gas from the Meji, Delta South, Okan and Mefa
fields. Proved undeveloped reserves associated with EGP Phase 3A
were recognized in 2002. These reserves are expected to be
reclassified to proved developed as various project milestones
are reached and related projects are completed. The anticipated
life of EGP Phase 3A is 25 years. Phase 3B of the EGP
project is designed to gather natural gas from eight offshore
fields and to compress and transport natural gas to onshore
facilities beginning in 2013.
Engineering and procurement activities continued during 2008 for
certain onshore fields that had been shut in since 2003 due to
civil unrest. The 40 percent-owned and operated Onshore
Asset Gas Management project is designed to restore
approximately 125 million cubic feet of natural gas per day
to the Nigerian domestic gas market. A major construction
contract is expected to be awarded in 2010.
Refer to page 23 for a discussion of affiliate operations
in Nigeria and to page 25 for a discussion of the planned
gas-to-liquids
facility at Escravos. Refer also to Pipelines under
Transportation Operations beginning on page 26
for a discussion of the West African Gas Pipeline operations.
14
c) Asia-Pacific
Major producing countries in the Asia-Pacific region include
Australia, Azerbaijan, Bangladesh, Kazakhstan, the Partitioned
Neutral Zone located between Saudi Arabia and Kuwait, and
Thailand.
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Australia: During 2008, the average net oil-equivalent production from Chevrons interests in Australia was 96,000 barrels per day, composed of 34,000 barrels of liquids and 376 million cubic feet of natural gas.
Chevron has a 17 percent nonoperated working interest in the North West Shelf (NWS) Venture offshore Western Australia. Daily net production from the project during 2008 averaged 25,000 barrels of crude oil and condensate, 374 million cubic feet of natural gas, and 4,000 barrels of LPG. Approximately 70 percent of the natural gas was sold in the form of LNG to major utilities in Japan, South Korea and China, primarily under long-term contracts. The remaining natural gas was sold to the Western Australia domestic market.
In September 2008, a fifth LNG train increased processing and export capacity from approximately 12 million metric tons per year to more than 16 million. Part of the natural gas for these expanded facilities is being supplied from the Angel natural-gas field, which started production in October 2008. Additional supply will be provided by the North Rankin 2 project, for which an investment decision was made in March 2008. The project is scheduled to start production in 2013.Proved undeveloped reserves were booked in prior years and will be reclassified to proved developed upon completion of the project.
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The NWS Venture is also advancing plans to extend the period of
crude-oil production. The NWS Oil Redevelopment Project is
designed to replace an FPSO and a portion of existing subsea
infrastructure that services production from the Cossack,
Hermes, Lambert and Wanaea offshore fields. A final investment
decision was made in November 2008 and
start-up is
expected early 2011. The project is expected to extend
production past 2020. The concession for the NWS Venture expires
in 2034.
On Barrow and Thevenard islands off the northwest coast of
Australia, Chevron operates crude-oil producing facilities that
had combined net production of 5,000 barrels per day in
2008. Chevrons interests in these operations are
57 percent for Barrow and 51 percent for Thevenard.
Also off the northwest coast of Australia, Chevron is the
operator of the Gorgon development and has a 50 percent
ownership interest across most of the Greater Gorgon Area.
Chevron and two joint-venture participants are planning for the
combined development of Gorgon and nearby natural-gas fields as
one large-scale project. Environmental approvals were in process
and a final investment decision is expected to be made in the
second half of 2009 for a three-train,
15 million-metric-ton-per-year LNG facility. Natural gas
for the project is expected to be supplied from the Gorgon and
Io/Jansz fields. The Gorgon project has an expected economic
life of at least 40 years.
At the end of 2008, the company had not recognized proved
reserves for any of the Greater Gorgon Area fields. Recognition
is contingent on securing sufficient LNG sales agreements and
achieving other key project milestones, including receipt of
environmental permits. In 2008, negotiations continued to
finalize sales agreements with three utility customers in Japan
and GS Caltex, a Chevron affiliated company. Purchases by each
of these customers are expected to range from 250,000 metric
tons per year to 1.5 million metric tons per year over
25 years.
15
In 2008, the company also announced plans for a multi-train LNG
plant to process natural gas from its wholly owned Wheatstone
discovery located on the northwest cost of mainland Australia.
The project is expected to begin FEED during the second half of
2009. During 2008, Chevron conducted appraisal drilling in the
Wheatstone and Iago fields. During 2009, the company plans to
drill multiple exploration and appraisal wells in its operated
acreage. At the end of 2008, the company had not recognized
proved reserves for this project.
In the Browse Basin, the company conducted successful appraisal
drilling programs in the Calliance and Torosa fields. A
commitment well was also drilled to test the northern extension
of the Ichthys Field in the eastern Browse Basin. At the end of
2008, proved reserves had not been recognized.
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Azerbaijan: Chevron holds a 10 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. Chevron also has a 9 percent interest in the Baku-Tbilisi-Ceyhan (BTC) affiliate, which transports AIOC production by pipeline from Baku, Azerbaijan, through Georgia to Mediterranean deepwater port facilities in Ceyhan, Turkey. (Refer to Pipelines under Transportation Operations beginning on page 26 for a discussion of the BTC operations.)
In 2008, the companys daily net production from AIOC averaged 29,000 barrels of oil-equivalent. First oil from Phase III of ACG development occurred during the second quarter 2008. Reserves were reclassified to proved developed shortly before start-up. In early 2009, total production was averaging about 670,000 barrels per day. The AIOC operations are conducted under a 30-year production-sharing contract (PSC) that expires in 2024.
Kazakhstan: Chevron holds a 20 percent nonoperated working interest in the Karachaganak project, which is being developed in phases. During 2008, Karachaganak net oil-equivalent production averaged 66,000 barrels per day, composed of 41,000 barrels of liquids and 153 million cubic feet of natural gas. In 2008, access to the Caspian Pipeline Consortium (CPC) and Atyrau-Samara (Russia) pipelines enabled Karachaganak sales of
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approximately 163,000 barrels per day (30,000 net
barrels) of processed liquids at world-market prices. The
remaining liquids were sold into Russian markets. During 2008,
work continued on a fourth train that is designed to increase
the export of processed liquids by 56,000 barrels per day
(11,000 net barrels). The fourth train is expected to start
up in 2011.
During 2008, partners continued to evaluate alternatives for a
Phase III development of Karachaganak. Timing for the
recognition of Phase III proved reserves is uncertain and
depends on finalizing a Phase III project design and
achievement of project milestones. Karachaganak operations are
conducted under a
40-year PSC
that expires in 2038.
Refer also to page 23 for a discussion of Tengizchevroil, a
50 percent-owned affiliate with operations in Kazakhstan,
and to page 26 in Pipelines under
Transportation Operations for a discussion of CPC
operations.
Bangladesh: Chevron operates and has 98 percent
interests in three PSCs in onshore Blocks 12, 13 and 14 and
an 88 percent interest in Block 7. Net oil-equivalent
production from these operations in 2008 averaged
71,000 barrels per day, composed of 414 million cubic
feet of natural gas and 2,000 barrels of liquids.
Cambodia: Chevron operates and holds a
55 percent interest in the
1.2 million-acre
(4,709 sq-km) Block A, located offshore in the Gulf of Thailand.
During 2008 and early 2009, evaluation continued of the
exploratory and appraisal drilling programs that occurred in
2007. Proved reserves had not been recognized as of the end of
2008.
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Myanmar: Chevron has a 28 percent nonoperated
working interest in a PSC for the production of natural gas from
the Yadana and Sein fields offshore in the Andaman Sea. The
company also has a 28 percent interest in a pipeline
company that transports the natural gas from Yadana to the
Myanmar-Thailand border for delivery to power plants in
Thailand. Most of the natural gas is purchased by
Thailands PTT Public Company Limited (PTT). The
companys average net natural gas production in 2008 was
89 million cubic feet per day.
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Thailand: Chevron has operated and nonoperated working interests in several different offshore blocks. The companys net oil-equivalent production in 2008 averaged 217,000 barrels per day, composed of 67,000 barrels of crude oil and condensate and 894 million cubic feet of natural gas. All of the companys natural gas production is sold to PTT under long-term sales contracts.
Operated interests are in Pattani and other fields with ownership interests ranging from 35 percent to 80 percent in Blocks 10 through 13, B12/27, B8/32, 9A, G4/43 and G4/48. Blocks B8/32 and 9A produce crude oil and natural gas from six operating areas, and Blocks 10 through 13 and B12/27 produce crude oil, condensate and natural gas from 16 operating areas. First production from Block G4/43 occurred in first quarter 2008.
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For Blocks 10 through 13, a final investment decision was
made in March 2008 for the construction of a second central
natural-gas processing facility in the Platong area. The
70 percent-owned and operated Platong Gas II project
is designed to add 420 million cubic feet per day of
processing capacity in 2011. The company expects to reclassify
proved undeveloped reserves to proved developed throughout the
projects life as the wellhead platforms are installed.
Concessions for Blocks 10 through 13 expire in 2022.
Chevron has a 16 percent nonoperated working interest in
Blocks 14A, 15A, 16A, G9/48 and G8/50, known collectively
as the Arthit Field. First production from Arthit occurred in
2008 and averaged 10,000 net oil-equivalent barrels per day
through the end of the year.
During 2008, 13 exploration wells were drilled in the Gulf of
Thailand, and all were successful. In Block G4/50, an
exploratory joint operating agreement was signed in late 2008. A
3-D seismic
survey and geological studies are scheduled for 2009. Three
exploratory wells are planned for 2010. At the end of 2008,
proved reserves had not been recognized for these activities. In
addition, Chevron holds exploration interests in a number of
blocks that are currently inactive, pending resolution of border
issues between Thailand and Cambodia.
Vietnam: The company operates off the southwest
coast and has a 42 percent interest in a PSC that includes
Blocks B and 48/95, and a 43 percent interest in another
PSC for Block 52/97. Chevron also has a third PSC with a
50 percent-owned and operated interest in Block B122
offshore eastern Vietnam. No production occurred in these areas
during 2008.
In the blocks off the southwest coast, the Vietnam Gas Project
is aimed at developing an area in the Malay Basin to supply
natural gas to state-owned PetroVietnam. The project includes
installation of wellhead and hub platforms, an FSO vessel, field
pipelines and a central processing platform. The timing of first
natural-gas production is dependent upon the outcome of
commercial negotiations. Maximum total production of
approximately 500 million cubic feet of natural gas per day
is projected within five years of
start-up. At
the end of 2008, proved reserves had not been recognized for
this project.
During the year, two exploratory wells confirmed hydrocarbons in
Block B and Block 52/97. In Block 122,
2-D seismic
information was purchased in late 2008, with processing
scheduled for 2009. Proved reserves had not been recognized as
of the end of 2008. Future activity in Block 122 may
be affected by an ongoing territorial dispute between Vietnam
and China.
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China: Chevron has one operated and three nonoperated working interests in several areas. Net oil-equivalent production from the nonoperated areas in 2008 averaged 22,000 barrels per day, composed of 19,000 barrels of crude oil and condensate and 22 million cubic feet of natural gas.
The company holds a 49 percent operated interest in the Chuandongbei area in the onshore Sichuan Basin, where the company entered into a 30-year PSC effective February 2008 to develop natural gas resources. Project plans included two sour-gas purification plants with an aggregate design capacity of 740 million cubic feet per day. A final investment decision was made for the first stage of the project in December 2008, and proved undeveloped reserves were recognized at that time.
In the South China Sea, the company has nonoperated working interests of 33 percent in Blocks 16/08 and 16/19 located in the Pearl River Delta Mouth Basin, 25 percent in the QHD-32-6 Field in Bohai Bay and 16 percent in the unitized and producing BZ 25-1 Field in Bohai Bay Block 11/19. Chevron also holds a 50 percent nonoperated working interest in one prospective onshore natural-gas block in the Ordos Basin.
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The joint development of the HZ 25-3 and HZ 25-1
crude-oil fields in Block 16/19 is expected to achieve first
production in the third quarter 2009. The maximum total
production of approximately 11,000 barrels of crude oil per
day is anticipated by early 2011.
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Partitioned Neutral Zone (PNZ): During 2008, the company negotiated a 30-year extension to its agreement with the Kingdom of Saudi Arabia to operate on behalf of the Saudi government its 50 percent interest in the petroleum resources of the onshore area of the PNZ between Saudi Arabia and Kuwait. Under the extension, Chevron has rights to this 50 percent interest in the hydrocarbon resource and pays a royalty and other taxes on the associated volumes produced until 2039. As a result of the contract extension, the company recognized additional proved reserves.
During 2008, the companys average net oil-equivalent production was 106,000 barrels per
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day, composed of 103,000 barrels of crude oil and
20 million cubic feet of natural gas. Steam injection for
the second phase of a steamflood pilot project is anticipated to
begin in mid-2009. This pilot is a unique application of steam
injection into a carbonate reservoir and, if successful, could
significantly increase heavy oil recovery.
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Philippines: The company holds a 45 percent
nonoperated working interest in the Malampaya natural-gas field
located 50 miles (80 km) offshore Palawan Island. Net
oil-equivalent production in 2008 averaged 26,000 barrels
per day, composed of 128 million cubic feet of natural gas
and 5,000 barrels of condensate. Chevron also develops and
produces geothermal resources under an agreement with the
National Power Corporation, a Philippine government-owned
company. The combined generating capacity of the facilities is
637 megawatts.
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d) Indonesia
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Chevrons operated interests in Indonesia are managed by
several wholly owned subsidiaries, including PT. Chevron Pacific
Indonesia (CPI). CPI holds operated interests of
100 percent in the Rokan and Siak PSCs. Other subsidiaries
operate four PSCs in the Kutei Basin, located offshore East
Kalimantan, and one PSC in the East Ambalat Block, located
offshore northeast Kalimantan. These interests range from
80 percent to 100 percent. Chevron also has
nonoperated working interests in a joint venture in Block B in
the South Natuna Sea and in the NE Madura III Block in the
East Java Sea Basin. Chevrons interests in these PSCs
range from 25 percent to 40 percent.
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The companys net oil-equivalent production in 2008 from
all of its interests in Indonesia averaged 235,000 barrels
per day. The daily oil-equivalent rate comprised
182,000 barrels of crude oil and 319 million cubic
feet of natural gas. The largest producing field is Duri,
located in the Rokan PSC. Duri has been under steamflood
operation since 1985 and is one of the worlds largest
steamflood developments. The North Duri Development is located
in the northern area of the Duri Field and is divided into
multiple expansion areas. The Area 12 expansion area started
production November 2008. Maximum total daily production from
Area 12 is estimated at 34,000 barrels of crude oil in
2012. Proved undeveloped reserves for the North Duri development
were recognized in previous years, and reclassification from
proved undeveloped to proved developed is scheduled to occur
during various stages of sequential completion. The Rokan PSC
expires in 2021.
Chevron has plans to develop the Gendalo and Gehem deepwater
natural-gas fields located in the Kutei Basin as a single
project with one development concept. In October 2008, the
company received approval from the government of Indonesia for
the final development plans. The Bangka natural-gas project
remained under evaluation in 2008 and, based on the evaluation
results, may be developed in parallel with Gendalo and Gehem.
The development timing is dependent on government approvals,
market conditions and the achievement of key project milestones.
At the end of 2008, the company had not recognized proved
reserves for either of these projects. The company holds an
80 percent operated interest in both.
Also in the Kutei Basin, first production is expected in March
2009 at the Seturian Field, which is providing natural gas to a
state-owned refinery. During 2008, the development concept for
the 50 percent-owned and operated Sadewa project in the
Kutei Basin remained under evaluation. A development decision
for Sadewa is expected by year-end 2009.
A drilling campaign continued through 2008 in South Natuna Sea
Block B to provide additional supply for long-term gas sales
contracts. Additional development drilling in the North Belut
Field began in November 2008, with first production expected in
fourth quarter 2009. In November 2008, Chevron was awarded
100 percent interests in two exploration blocks in western
Papua. Geological studies are planned for 2009 in preparation
for 2-D
seismic acquisition.
In West Java, Chevron operates the wholly owned Salak geothermal
field with a total capacity of 377 megawatts. Also in West Java,
Chevron holds a 95 percent interest in a power generation
company that operates the Darajat geothermal contract area in
Garut with a total capacity of 259 megawatts. Chevron also
operates a 95 percent-owned 300-megawatt cogeneration
facility in support of CPIs operation in North Duri,
Sumatra.
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e)
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Other
International Areas
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The Other International region is composed of Latin
America, Canada and Europe.
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Argentina: Chevron holds operated interests in several concessions and one exploratory block in the Neuquen and Austral basins. Working interests range from 19 percent to 100 percent. Net oil-equivalent production in 2008 averaged 44,000 barrels per day, composed of 37,000 barrels of crude oil and natural gas liquids and 45 million cubic feet of natural gas. The company also holds a 14 percent interest in the Oleoductos del Valle S.A. pipeline.
Brazil: Chevron holds working interests ranging from 30 percent to 52 percent in three deepwater blocks in the Campos Basin. Chevron also holds a 20 percent nonoperated working interest in one block in the Santos Basin. None of these blocks had production in 2008.
In Block BC-4, located in the Campos Basin, the company is the operator and has a 52 percent interest in the Frade Field, which is under development as a subsea production design. Proved undeveloped reserves were recorded for the first time in 2005. Partial reclassification to the proved-developed category is scheduled upon production start-up in 2009. Estimated maximum total production of 87,000 oil-equivalent barrels per day is anticipated in 2011. The concession that includes the Frade project expires in 2025.
In the partner-operated Campos Basin Block BC-20, two areas 38 percent-owned Papa-Terra and 30 percent-owned Maromba were retained for development following the end of the exploration phase of this block. Evaluation of design options continued into
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2009. At the end of 2008, proved reserves had not been
recognized for these projects.
In the Santos basin, evaluation of investment options continued
into 2009 for the 20 percent-owned and partner-operated
Atlanta and Oliva fields. At the end of 2008, proved reserves
had not been recognized.
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 from a
fixed-fee Build-Operate-Maintain-Transfer agreement based on
prior Chuchupa capital contributions. Daily net production
averaged 209 million cubic feet of natural gas in 2008.
Trinidad and Tobago: Company interests include
50 percent ownership in four 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. Chevron also holds a 50 percent
operated interest in the Manatee area of Block 6d. Net
production in 2008 averaged 189 million cubic feet of
natural gas per day. Incremental production associated with a
new domestic sales agreement is scheduled to commence at Dolphin
in third quarter 2009.
Venezuela: The company operates in two exploratory
blocks offshore Plataforma Deltana, with working interests of
60 percent in Block 2 and 100 percent in
Block 3. Chevron also holds a 100 percent operated
interest in the Cardon III exploratory block, located north
of Lake Maracaibo in the Gulf of Venezuela. Petróleos de
Venezuela, S.A. (PDVSA), Venezuelas national crude-oil and
natural-gas company, has the option to increase its ownership in
each of the three company-operated blocks up to 35 percent
upon declaration of commerciality.
A conceptual development plan has been completed for the Loran
Field in Block 2. Loran is projected to provide the initial
supply of natural gas for Delta Caribe LNG (DCLNG) Train 1,
Venezuelas first LNG train. A DCLNG framework agreement
was signed in September 2008, which provides Chevron with a
10 percent nonoperated interest in the first train and the
associated offshore pipeline. An exploration well is planned in
the Cardon III block in 2009. At the end of 2008, proved
reserves had not been recognized in these exploratory blocks.
Chevron also holds interest in two affiliates located in western
Venezuela and in one affiliate in the Orinoco Belt. Refer to
page 23 for a discussion of affiliate operations in
Venezuela.
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Canada: Company activities in Canada include
nonoperated working interests of 27 percent in the Hibernia
and Hebron fields offshore eastern Canada and 20 percent in
the Athabasca Oil Sands Project (AOSP), and operated interests
of 60 percent in the Ells River In Situ Oil
Sands Project. Excluding volumes mined at AOSP, average net
oil-equivalent production during 2008 was 37,000 barrels
per day, composed of 36,000 barrels of crude oil and
natural gas liquids and 4 million cubic feet of natural
gas. Substantially all of this production was from the Hibernia
Field, where a development plan is being formulated for a
proposed Hibernia South Extension. At AOSP, the companys
share of mined bitumen (for upgrading into synthetic crude oil)
averaged 27,000 barrels per day during 2008.
For Hebron, agreements were reached during
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2008 with the provincial government of Newfoundland and Labrador
that allow development activities to begin. As of the end of
2008, the company had not recognized proved reserves for this
project.
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At AOSP, the first phase of an expansion project is under way
that is designed to produce an additional 100,000 barrels
per day of mined bitumen. The expansion would increase total
AOSP design capacity to more than 255,000 barrels per day
in late 2010. The projected cost of this expansion is
$13.7 billion.
The Ells River project consists of heavy oil leases of more than
85,000 acres (344 sq km). The area contains significant
volumes with potential for recovery by using Steam Assisted
Gravity Drainage, an industry-proven technology that employs
steam and horizontal drilling to extract the bitumen through
wells rather than through mining operations. During 2008, the
company completed an appraisal drilling program and a seismic
survey. An additional seismic program started in late 2008 and
is expected to be completed in March 2009. At the end of 2008,
proved reserves had not been recognized.
The company also holds exploration leases in the Mackenzie Delta
and Beaufort Sea region, including a 33 percent nonoperated
working interest in the offshore Amauligak discovery. Three
exploration wells were drilled on company leases in the
Mackenzie Delta region in 2008. Drilling on three additional
wells in the Mackenzie Delta is expected to be completed in
second quarter 2009 and assessment of development concept
alternatives for Amauligak continued. The company holds
additional exploration acreage in eastern Labrador and the
Orphan Basin. At the end of 2008, proved reserves had not been
recognized for any of these areas.
Greenland: Chevron has a 29 percent nonoperated
working interest in an exploration license in Block 4
offshore West Greenland in the Baffin Basin. A
2-D seismic
survey was completed in 2008, and interpretation of the data is
expected to occur in 2009.
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Denmark: Chevron has a 15 percent working interest in the partner-operated Danish Underground Consortium (DUC), which produces crude oil and natural gas from 15 fields in the Danish North Sea. Net oil-equivalent production in 2008 from DUC averaged 61,000 barrels per day, composed of 37,000 barrels of crude oil and 142 million cubic feet of natural gas.
Faroe Islands: Chevron operates and holds a 40 percent interest in five offshore exploratory blocks. During 2008, the company acquired additional 2-D seismic data for an area located near the Rosebank/Lochnagar discovery offshore the United Kingdom. Engineering and geological evaluation of the seismic data continued into early 2009. As of the end of 2008, proved reserves had not been recognized.
Netherlands: Chevron is the operator and holds interests ranging from 34 percent to 80 percent in nine blocks in the Dutch sector of the North Sea. In 2008, the companys net oil-equivalent production from the five producing blocks was 9,000 barrels per day, composed of 2,000 barrels of crude oil and 40 million cubic feet of natural gas.
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Norway: The company holds an 8 percent interest
in the partner-operated Draugen Field. The companys net
production averaged 6,000 barrels of oil-equivalent per day
during 2008. In the 40 percent-owned and partner-operated
PL397 area in the Barents Sea, additional
3-D seismic
information was obtained in 2008, with evaluation of the data
continuing into 2009.
United Kingdom: The companys average net
oil-equivalent production in 2008 from 11 offshore fields was
106,000 barrels per day, composed of 71,000 barrels of
crude oil and natural gas liquids and 208 million cubic
feet of natural gas. Most of the production was from the
85 percent-owned and operated Captain Field and the
32 percent-owned and jointly operated Britannia Field.
Two partner-operated satellite fields of Britannia commenced
production in 2008 the 17 percent-owned
Callanish Field in the second quarter and the
25 percent-owned Brodgar Field in the third quarter.
At the 40 percent-owned and operated Rosebank/Lochnagar
area northwest of the Shetland Islands, an exploration well in
an adjacent structure is expected to be completed in
second-quarter 2009 and an appraisal well is planned for later
in the year. Evaluation of development alternatives continued
during 2008 for the 19 percent-owned and partner-operated
Clair Phase 2 and 10 percent-owned and partner-operated
Laggan/Tormore projects. As of the end of 2008, proved reserves
had not been recognized for any of these three exploration areas.
Equity
Affiliate Operations
Angola: In addition to the exploration and producing
activities in Angola, Chevron has a 36 percent ownership
interest in the Angola LNG affiliate that began construction in
early 2008 of an onshore natural gas liquefaction plant located
in the northern part of the country. The plant is designed to
process more than 1 billion cubic feet of natural gas per
day. Plant
start-up is
scheduled for 2012. Chevron made an initial booking of proved
undeveloped natural-gas reserves in 2007 for the producing
operations associated with this LNG project. The life of the LNG
plant is estimated to be in excess of 20 years.
22
Kazakhstan: The company holds a 50 percent
interest in Tengizchevroil (TCO), which operates and is
developing the Tengiz and Korolev crude-oil fields, located in
western Kazakhstan, under a
40-year
concession that expires in 2033. Chevrons net
oil-equivalent production in 2008 from these fields averaged
201,000 barrels per day, composed of 168,000 barrels
of crude oil and natural gas liquids and 195 million cubic
feet of natural gas.
In 2008, TCO completed a significant expansion composed of two
integrated projects referred to as Second Generation Plant (SGP)
and Sour Gas Injection (SGI). Total cost of the project was
$7.4 billion. The projects increased TCOs daily
production capacity to 540,000 barrels of crude oil,
760 million cubic feet of natural gas and
46,000 barrels of natural gas liquids. The SGI facility
injects approximately one-third of the sour gas separated from
the crude oil back into the reservoir. The injected gas
maintains higher reservoir pressure and displaces oil towards
producing wells. The company recognized additional proved
reserves associated with SGI in 2008. TCO is evaluating options
for another expansion project based on SGI/SGP technologies.
During 2008, the majority of TCOs 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 majority
of the incremental production from SGI/SGP was moved by rail to
Black Sea ports. Other export routes included shipment via
tanker to Baku for transport by the BTC pipeline to Ceyhan or by
rail to Black Sea ports. (Refer to Pipelines under
Transportation Operations beginning on page 26
for a discussion of CPC operations.)
Nigeria: Chevron holds a 19 percent interest in
the OKLNG Free Zone Enterprise (OKLNG) affiliate, which will
operate the Olokola LNG project. OKLNG plans to build a
multitrain natural gas liquefaction facility and marine terminal
located northwest of Escravos. The project is expected to be
implemented in phases, starting with two
6.3 million-ton-per-year trains. Approximately
50 percent of the gas supplied to the plant is expected to
be provided from the producing areas associated with
Chevrons joint-venture arrangement with Nigerian National
Petroleum Corporation. At the end of 2008, a final investment
decision had not been reached, and the company had not
recognized proved reserves associated with this project.
Venezuela: 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 percent interest in the Petroboscan
affiliate that operates the Boscan Field in the western part of
the country, and a 25 percent interest in the
Petroindependiente affiliate that operates the LL-652 Field in
Lake Maracaibo. The companys share of average net
oil-equivalent production during 2008 from these operations was
66,000 barrels per day, composed of 62,000 barrels of
crude oil and natural gas liquids and 27 million cubic feet
of natural gas.
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. Outside the United States, substantially all of
the natural gas sales are from the companys producing
interests in Australia, Bangladesh, Kazakhstan, Indonesia, Latin
America, the Philippines, Thailand and the United Kingdom. The
company also makes third-party purchases and sales of natural
gas in connection with its trading activities. Substantially all
of the sales of natural gas liquids are from company operations
in Africa, Australia and Indonesia.
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 8 for information related to the companys
delivery commitments for the sale of crude oil and natural gas.
23
Downstream
Refining, Marketing and Transportation
Refining
Operations
At the end of 2008, the company had a refining network capable
of processing 2.1 million barrels of crude oil per day.
Daily refinery inputs for 2006 through 2008 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, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operable
|
|
|
Refinery Inputs
|
|
Locations
|
|
Number
|
|
|
Capacity
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Pascagoula
|
|
Mississippi
|
|
|
1
|
|
|
|
330
|
|
|
|
299
|
|
|
|
285
|
|
|
|
337
|
|
El Segundo
|
|
California
|
|
|
1
|
|
|
|
265
|
|
|
|
263
|
|
|
|
222
|
|
|
|
258
|
|
Richmond
|
|
California
|
|
|
1
|
|
|
|
243
|
|
|
|
237
|
|
|
|
192
|
|
|
|
224
|
|
Kapolei
|
|
Hawaii
|
|
|
1
|
|
|
|
54
|
|
|
|
46
|
|
|
|
51
|
|
|
|
50
|
|
Salt Lake City
|
|
Utah
|
|
|
1
|
|
|
|
45
|
|
|
|
38
|
|
|
|
42
|
|
|
|
39
|
|
Other1
|
|
|
|
|
1
|
|
|
|
80
|
|
|
|
8
|
|
|
|
20
|
|
|
|
31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Consolidated Companies United
States
|
|
|
6
|
|
|
|
1,017
|
|
|
|
891
|
|
|
|
812
|
|
|
|
939
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pembroke
|
|
United Kingdom
|
|
|
1
|
|
|
|
210
|
|
|
|
203
|
|
|
|
212
|
|
|
|
165
|
|
Cape Town2
|
|
South Africa
|
|
|
1
|
|
|
|
110
|
|
|
|
75
|
|
|
|
72
|
|
|
|
71
|
|
Burnaby, B.C.
|
|
Canada
|
|
|
1
|
|
|
|
55
|
|
|
|
36
|
|
|
|
49
|
|
|
|
49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Consolidated Companies
International
|
|
|
3
|
|
|
|
375
|
|
|
|
314
|
|
|
|
333
|
|
|
|
285
|
|
Affiliates3
|
|
Various Locations
|
|
|
9
|
|
|
|
747
|
|
|
|
653
|
|
|
|
688
|
|
|
|
765
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Including Affiliates
International
|
|
|
12
|
|
|
|
1,122
|
|
|
|
967
|
|
|
|
1,021
|
|
|
|
1,050
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Including Affiliates Worldwide
|
|
|
18
|
|
|
|
2,139
|
|
|
|
1,858
|
|
|
|
1,833
|
|
|
|
1,989
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
Asphalt plant in Perth Amboy, New
Jersey. Plant was idled during 2008.
|
2 |
|
Chevron holds 100 percent of
the common stock issued by Chevron South Africa (Pty) Limited,
which owns the Cape Town Refinery. A consortium of South African
partners owns preferred shares ultimately convertible to a
25 percent equity interest in Chevron South Africa (Pty)
Limited. None of the preferred shares had been converted as of
February 2009.
|
3 |
|
Chevron sold its 31 percent
interest in the Nerefco Refinery in the Netherlands in March
2007. During 2008, the company sold its 4 percent ownership
interest in a refinery in Abidjan, Côte dIvoire, and
its 8 percent ownership interest in a refinery in Cameroon,
decreasing the companys combined share of operable
capacity by about 5,000 barrels per day.
|
Average crude oil distillation capacity utilization during 2008
was 87 percent, compared with 85 percent in 2007. This
increase generally resulted from an improvement in utilization
at the refineries in Richmond and El Segundo, California. At the
U.S. fuel refineries, crude oil distillation capacity
utilization averaged 95 percent in 2008, compared with
85 percent in 2007, and cracking and coking capacity
utilization averaged 86 percent and 78 percent in 2008
and 2007, respectively. Cracking and coking units are the
primary facilities used in fuel refineries to convert heavier
feedstocks into gasoline and other light products.
The companys refineries in the United States, the United
Kingdom, Canada, South Africa and Australia produce low-sulfur
fuels. GS Caltex, the companys 50 percent-owned
affiliate, completed construction in 2008 on projects to produce
low-sulfur fuels at the
700,000 barrel-per-day
Yeosu refining complex in South Korea. Other projects completed
during the year at Yeosu included a new hydrocracker complex and
distillation unit that increases high-value product yield and
lowers feedstock costs. In 2009, construction continues at the
Yeosu complex on projects designed to further improve processing
of higher-sulfur crude oils and reduce fuel-oil production. At
the companys 50 percent-owned Singapore Refining
Company, construction continued during 2008 and into early 2009
to enable the refinery to meet regional specifications for clean
diesel fuels.
At the Pascagoula refinery, various projects were completed
during 2008 that enhanced the ability to process heavier,
higher-sulfur crudes, resulting in lower crude-acquisition
costs. In addition, construction progressed on a continuous
catalytic reformer that is expected to improve refinery
reliability and increase daily gasoline production at the
refinery by 10 percent, or 600,000 gallons per day, by
mid-2010. At the Richmond and El Segundo refineries,
construction continued and design and engineering work advanced
during 2008 to further increase the ability to process
high-sulfur crude oils and improve high-value product yields.
24
In August 2008, Chevron submitted an environmental permit
application to the Mississippi Department of Environmental
Quality for the construction of a premium base oil facility at
the companys Pascagoula Refinery. The facility is expected
to have daily production of approximately 25,000 barrels of
premium base oil for use in manufacturing high-performance
lubricants, such as motor oils for consumer and commercial uses.
Chevron holds a 5 percent interest in Reliance Petroleum
Limited, a company formed by Reliance Industries Limited to
construct a new refinery in Jamnagar, India. Chevron has rights
to increase its equity ownership to 29 percent or to sell
back its investment to Reliance Industries Limited. These rights
expire the later of July 27, 2009, or three months after
the plant is fully commissioned.
Chevron processes imported and domestic crude oil in its
U.S. refining operations. Imported crude oil accounted for
about 88 percent and 87 percent of Chevrons
U.S. refinery inputs in 2008 and 2007, respectively.
Gas-to-Liquids
In Nigeria, Chevron and the Nigerian National Petroleum
Corporation are developing a
34,000 barrel-per-day
gas-to-liquids
facility at Escravos designed to process natural gas supplied
from the Phase 3A expansion of the Escravos Gas Plant (EGP). At
the end of 2008, engineering was essentially complete and
facility construction was under way. Chevron has a
75 percent interest in the plant, which is expected to be
operational by 2012. The estimated cost of the plant is
$5.9 billion. Refer also to page 14 for a discussion
on the EGP Phase 3A expansion.
Marketing
Operations
The company markets petroleum products under the principal
brands of Chevron, Texaco and
Caltex throughout much of the world. The table below
identifies the companys and affiliates refined
products sales volumes, excluding intercompany sales, for the
three years ending December 31, 2008.
Refined
Products Sales
Volumes1
(Thousands of Barrels per Day)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasolines
|
|
|
692
|
|
|
|
728
|
|
|
|
712
|
|
Jet Fuel
|
|
|
274
|
|
|
|
271
|
|
|
|
280
|
|
Gas Oils and Kerosene
|
|
|
229
|
|
|
|
221
|
|
|
|
252
|
|
Residual Fuel Oil
|
|
|
127
|
|
|
|
138
|
|
|
|
128
|
|
Other Petroleum
Products2
|
|
|
91
|
|
|
|
99
|
|
|
|
122
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total United States
|
|
|
1,413
|
|
|
|
1,457
|
|
|
|
1,494
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International3
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasolines
|
|
|
589
|
|
|
|
581
|
|
|
|
595
|
|
Jet Fuel
|
|
|
278
|
|
|
|
274
|
|
|
|
266
|
|
Gas Oils and Kerosene
|
|
|
710
|
|
|
|
730
|
|
|
|
776
|
|
Residual Fuel Oil
|
|
|
257
|
|
|
|
271
|
|
|
|
324
|
|
Other Petroleum
Products2
|
|
|
182
|
|
|
|
171
|
|
|
|
166
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total International
|
|
|
2,016
|
|
|
|
2,027
|
|
|
|
2,127
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Worldwide3
|
|
|
3,429
|
|
|
|
3,484
|
|
|
|
3,621
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
Includes buy/sell arrangements. Refer to Note 14 on page FS-43.
|
|
|
|
|
|
|
|
|
|
|
50
|
|
2
|
|
Principally naphtha, lubricants, asphalt and coke.
|
|
|
|
|
|
|
|
|
|
|
|
|
3
|
|
Includes share of equity affiliates sales:
|
|
|
512
|
|
|
|
492
|
|
|
|
492
|
|
In the United States, the company markets under the Chevron and
Texaco brands. The company supplies directly or through
retailers and marketers approximately 9,700 Chevron- and
Texaco-branded motor vehicle retail outlets, primarily in the
mid-Atlantic, southern and western states. Approximately 500 of
these outlets are company-owned or -leased stations.
25
Outside the United States, Chevron supplies directly or through
retailers and marketers approximately 15,300 branded service
stations, including affiliates. In British Columbia, Canada, the
company markets under the Chevron brand. The company markets in
the United Kingdom, Ireland, 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, using the GS Caltex
brand. The companys 50 percent-owned affiliate in
Australia, Caltex Australia Limited, operates using the Caltex
and Ampol brands.
In 2008, the company announced agreements to sell
marketing-related businesses in Brazil, Nigeria, Kenya, Uganda,
Benin, Cameroon, Republic of the Congo, Côte dIvoire
and Togo. The company will retain its lubricants business in
Brazil. The company also completed the sale of its heating-oil
business in the United Kingdom. In addition, the company sold
its interest in about 350 individual service-station sites. The
majority of these sites will continue to market company-branded
gasoline through new supply agreements.
The company also manages other marketing businesses globally.
Chevron markets aviation fuel at more than 1,000 airports. The
company also markets an extensive line of lubricant and coolant
products under brand names that include Havoline, Delo, Ursa,
Meropa and Taro.
Transportation
Operations
Pipelines: Chevron owns and operates an extensive
system of crude oil, refined products, chemicals, natural gas
liquids and natural gas pipelines in the United States. The
company also has direct or 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, 2008
|
|
|
|
|
|
|
Net
Mileage1
|
|
United States:
|
|
|
|
|
Crude Oil2
|
|
|
2,886
|
|
Natural Gas
|
|
|
2,263
|
|
Petroleum
Products3
|
|
|
6,030
|
|
|
|
|
|
|
Total United States
|
|
|
11,179
|
|
International:
|
|
|
|
|
Crude Oil2
|
|
|
700
|
|
Natural Gas
|
|
|
576
|
|
Petroleum
Products3
|
|
|
433
|
|
|
|
|
|
|
Total International
|
|
|
1,709
|
|
|
|
|
|
|
Worldwide
|
|
|
12,888
|
|
|
|
|
|
|
|
|
|
1
|
|
Partially owned pipelines are included at the companys
equity percentage.
|
2
|
|
Includes gathering lines related to the transportation function.
Excludes gathering lines related to U.S. and international
production activities.
|
3
|
|
Includes refined products, chemicals and natural gas liquids.
|
During 2008, the company completed the construction of a natural
gas gathering pipeline serving the Piceance Basin in northwest
Colorado; participated in the successful installation of the
Amberjack-Tahiti lateral pipeline on the seafloor of the
U.S. Gulf of Mexico; and led the expansion of the West
Texas LPG pipeline system. Chevron also continued with a project
during 2008 to expand capacity by about 2 billion cubic
feet at the Keystone natural-gas storage facility. The project
is expected to be completed in late 2009.
Chevron has a 15 percent interest in the Caspian Pipeline
Consortium (CPC) affiliate. CPC operates a crude oil export
pipeline from the Tengiz Field in Kazakhstan to the Russian
Black Sea port of Novorossiysk. During 2008, CPC transported an
average of approximately 675,000 barrels of crude oil per
day, including 557,000 barrels per day from Kazakhstan and
118,000 barrels per day from Russia. In late 2008, the CPC
partners signed a Memorandum of Understanding to expand the
design capacity to 1.4 million barrels per day. A final
investment decision is expected after commercial terms have been
agreed upon and required government approvals have been received.
26
The company has a 9 percent interest in the
Baku-Tbilisi-Ceyhan (BTC) affiliate that owns and operates a
pipeline that transports primarily the crude oil produced by
Azerbaijan International Operating Company (AIOC) (owned
10 percent by Chevron) from Baku, Azerbaijan, through
Georgia to deepwater port facilities in Ceyhan, Turkey. The BTC
pipeline has a crude-oil capacity of 1.2 million barrels
per day and transports the majority of the AIOC production.
Another production export route for crude oil is the Western
Route Export Pipeline, wholly owned by AIOC, with capacity to
transport 145,000 barrels per day from Baku, Azerbaijan, to
the marine terminal at Supsa, Georgia.
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
(678-km)
West African Gas Pipeline. The pipeline is designed to supply
Nigerian natural gas to customers in Benin, Ghana and Togo for
industrial applications and power generation and is expected to
have capacity of 170 million cubic feet of natural gas per
day by 2010. First gas was shipped in December 2008.
Tankers: All tankers in Chevrons controlled
seagoing fleet were utilized during 2008. In addition, at any
given time during 2008 the company had approximately 40 deep-sea
vessels chartered on a voyage basis, or for a period of less
than one year. Additionally, the following table summarizes the
capacity of the companys controlled fleet.
Controlled
Tankers at December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Flag
|
|
|
Foreign Flag
|
|
|
|
|
|
|
Cargo Capacity
|
|
|
|
|
|
Cargo Capacity
|
|
|
|
Number
|
|
|
(Millions of Barrels)
|
|
|
Number
|
|
|
(Millions of Barrels)
|
|
|
Owned
|
|
|
3
|
|
|
|
0.8
|
|
|
|
1
|
|
|
|
1.1
|
|
Bareboat Chartered
|
|
|
2
|
|
|
|
0.7
|
|
|
|
18
|
|
|
|
27.1
|
|
Time Chartered*
|
|
|
|
|
|
|
|
|
|
|
17
|
|
|
|
14.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
5
|
|
|
|
1.5
|
|
|
|
36
|
|
|
|
42.8
|
|
Federal law requires that cargo transported between
U.S. ports be carried in ships built and registered in the
United States, owned and operated by U.S. entities, and
manned by U.S. crews. In 2008, the companys
U.S. flag fleet was 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. One
U.S.-flagged
product tanker, capable of carrying 300,000 barrels of
cargo, was delivered in 2008 and two additional
U.S.-flagged
product tankers are scheduled for delivery in 2010.
The foreign-flagged vessels were engaged primarily in
transporting crude oil from the Middle East, Asia, the Black
Sea, Mexico and West Africa to ports in the United States,
Europe, Australia and Asia. Refined products were also
transported by tanker worldwide.
In addition to the vessels described above, the company owns a
one-sixth interest in each of seven LNG tankers transporting
cargoes for the North West Shelf (NWS) Venture in Australia. The
NWS project also has two LNG tankers under long-term time
charter. In 2008, the company sold its two LNG shipbuilding
contracts with Samsung Heavy Industries, but retained the option
to purchase two new LNG vessels.
The Federal Oil Pollution Act of 1990 requires the phase-out by
year-end 2010 of all single-hull tankers trading to
U.S. ports or transferring cargo in waters within the
U.S. Exclusive Economic Zone. As of the end of 2008, the
companys owned and bareboat-chartered fleet was completely
double-hulled. The company is a member of many
oil-spill-response cooperatives in areas in which it operates
around the world.
Chemicals
Chevron Phillips Chemical Company LLC (CPChem) is equally owned
with ConocoPhillips Corporation. At the end of 2008, CPChem
owned or had joint venture interests in 35 manufacturing
facilities and five research and technical centers in Belgium,
Brazil, China, Colombia, Qatar, Saudi Arabia, Singapore, South
Korea and the United States.
Americas Styrenics LLC, a
50-50 joint
venture between CPChem and Dow Chemical Company, began
commercial operations in 2008. This joint venture combined
CPChems U.S. styrene and polystyrene operations with
Dows U.S. and Latin America polystyrene operations.
Also, construction continued on the new
22 million-pound-per-year
Ryton®
polyphenylene-sulfide (PPS) manufacturing facility at Borger,
Texas. Completion of this plant is expected in second quarter
2009.
27
Outside the United States, CPChems 50 percent-owned
Jubail Chevron Phillips Company began commercial production at
its world-scale styrene facility at Al Jubail, Saudi Arabia. The
styrene facility is located adjacent to an existing aromatics
complex in Al Jubail that is jointly owned by CPChem and the
Saudi Industrial Investment Group. Also during 2008,
construction commenced by Saudi Polymers Company, a joint
venture company formed to build a third petrochemical project in
Al Jubail. Project completion is expected in 2011.
CPChem continued construction during 2008 on the
49 percent-owned Q-Chem II project in Mesaieed, Qatar.
The project includes a 350,000-metric-ton-per-year polyethylene
plant and a 345,000-metric-ton-per-year normal alpha olefins
plant each utilizing CPChem proprietary
technology and is located adjacent to the existing
Q-Chem I complex. Q-Chem II also includes a separate joint
venture to develop a 1.3 million-metric-ton-per-year
ethylene cracker at Qatars Ras Laffan Industrial City, in
which Q-Chem II owns 54 percent of the capacity
rights.
Start-up is
anticipated in late 2009.
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 provides
additives for lubricating oil in most engine applications, such
as passenger car, heavy-duty diesel, marine, locomotive and
motorcycle engines, and additives for fuels to improve engine
performance and extend engine life. Oronite completed
construction and started up the hydrofluoric acid replacement
alkylation units in Gonfreville, France, during 2008. Commercial
production commenced in January 2009. Also during 2008, the
Gonfreville facility began full commercial production of new
sulfur-free detergent components for marine engine applications
and low-sulfur components for automotive engine oil applications.
Other
Businesses
Mining
Chevrons
U.S.-based
mining company produces and markets coal and molybdenum. Sales
occur in both U.S. and international markets.
The company owns and operates two surface coal mines, McKinley,
in New Mexico, and Kemmerer, in Wyoming, and one underground
coal mine, North River, in Alabama. The company also owns a
50 percent interest in Youngs Creek Mining Company LLC, a
joint venture to develop a coal mine in northern Wyoming. Coal
sales from wholly owned mines were 11 million tons, down
about 1 million tons from 2007.
At year-end 2008, Chevron controlled approximately
200 million tons of proven and probable coal reserves in
the United States, including reserves of environmentally
desirable low-sulfur coal. The company is contractually
committed to deliver between 8 million and 11 million
tons of coal per year through the end of 2010 and believes it
will satisfy these contracts from existing coal reserves.
In addition to the coal operations, Chevron owns and operates
the Questa molybdenum mine in New Mexico. At year-end 2008,
Chevron controlled approximately 53 million pounds of
proven molybdenum reserves at Questa.
In 2008, the company sold the petroleum coke calciner assets of
Chicago Carbon Company, a wholly owned subsidiary in Illinois.
The company also sold its lanthanides processing facilities and
rare-earth mineral mine in Mountain Pass, California, and its
33 percent interest in Sumikin Molycorp, a manufacturer and
marketer of neodymium compounds in Japan. In early 2009, the
company was actively marketing its coal reserves at the North
River Mine and elsewhere in Alabama for sale.
Power
Generation
Chevrons power generation business develops and operates
commercial power projects and has interests in 13 power assets
through joint ventures in the United States and Asia. The
company manages the production of more than 2,300 megawatts of
electricity at 11 facilities it owns through joint ventures. The
company operates gas-fired cogeneration facilities that use
waste heat recovery to produce additional electricity or to
support industrial thermal hosts. A number of the facilities
produce steam for use in upstream operations to facilitate
production of heavy oil.
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 page 19 and Research and
Technology, on page 29.
28
Chevron
Energy Solutions
Chevron Energy Solutions (CES) is a wholly owned subsidiary that
provides public institutions and businesses with sustainable
energy projects designed to increase energy efficiency and
reliability, reduce energy costs, and utilize renewable and
alternative-power technologies. Since 2000, CES has developed
hundreds of projects that will help government, education and
other customers reduce their energy costs and carbon footprint.
Major projects completed by CES in 2008 included several large
solar panel installations in California.
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. 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 2008, CTV
was investigating technologies such as next-generation biofuels,
advanced solar power and enhanced geothermal.
Chevrons research and development expenses were
$835 million, $562 million and $468 million for
the years 2008, 2007 and 2006, respectively.
Some of the investments the company makes in the areas described
above are in new or unproven technologies and business
processes, and ultimate successes are not certain. Although not
all initiatives may prove to be economically viable, the
companys overall investment in this area is not
significant to the companys consolidated financial
position.
Environmental
Protection
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. Chevron expects more environment-related regulations in
the countries where it has operations. Most of the costs of
complying with the many laws and regulations pertaining to its
operations are embedded in the normal costs of conducting
business.
In 2008, the companys U.S. capitalized environmental
expenditures were approximately $780 million, representing
approximately 9 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 2009, the company estimates U.S. capital
expenditures for environmental control facilities will be
approximately $1 billion. The future annual capital costs
are uncertain and will be governed by several factors, including
future changes to regulatory requirements.
Refer to Managements Discussion and Analysis of Financial
Condition and Results of Operations on pages FS-16 through FS-18
for additional information on environmental matters and their
impact on Chevron and on the companys 2008 environmental
expenditures, remediation provisions and year-end environmental
reserves.
Web Site
Access to SEC Reports
The companys Internet Web site is at
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 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 at the
SECs Web site at www.sec.gov.
29
Chevron is a major fully integrated petroleum company with a
diversified business portfolio, a strong balance sheet, and a
history of generating sufficient cash to fund capital and
exploratory expenditures and to pay dividends. 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 and
geopolitical risk.
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, 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 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, including hurricanes, floods and other
forms of severe weather, war, civil unrest and other political
events, fires, earthquakes, and explosions, any of which could
result in suspension of operations or harm to people or the
natural environment.
Chevrons
business subjects the company to liability risks.
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 the
companys business. Chevron operations also produce
byproducts, which may be considered pollutants. Any of these
activities could result in liability, 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.
Political
instability 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 taken by
governments to increase public ownership of the companys
partially or wholly owned businesses
and/or to
impose additional taxes or royalties.
In certain locations, governments have imposed restrictions,
controls and taxes, and in others, political conditions have
existed that may threaten the safety of employees and the
companys continued presence in those countries. Internal
unrest, acts of violence or strained relations between a
government and the company or other governments may 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, 2008, 29 percent of the
companys net proved reserves were located in Kazakhstan.
The company also has significant interests in Organization of
Petroleum Exporting Countries (OPEC)-member countries including
Angola, Nigeria and Venezuela and in the Partitioned Neutral
Zone between Saudi Arabia and Kuwait. Twenty-three percent of
the companys net proved reserves, including affiliates,
were located in OPEC countries at December 31, 2008
(excluding reserves in Indonesia, which relinquished its OPEC
membership at the end of 2008).
30
Regulation
of greenhouse gas emissions could increase Chevrons
operational costs and reduce demand for Chevrons
products.
Management expects continued political attention to issues
concerning climate change, and the role of human activity in it
and potential remediation or mitigation through regulation that
could materially affect the companys operations.
International agreements and national or regional legislation
and regulatory measures to limit greenhouse emissions are
currently in various phases of discussion or implementation. The
Kyoto Protocol, Californias Global Warming Solutions Act
and Australias proposed Carbon Pollution Reduction Scheme,
along with other actual or pending federal, state and provincial
regulations, envision a reduction of greenhouse gas emissions
through market-based trading schemes. The company is currently
complying with greenhouse gas emissions limits within the
European Union.
As a result of these and other environmental regulations, the
company expects to incur substantial capital, compliance,
operating, maintenance and remediation costs. The level of
expenditure required to comply with these laws and regulations
is uncertain and may vary by jurisdiction depending on the laws
enacted in each jurisdiction and the companys activities
in it. The companys production and processing operations
(e.g., the production of crude oil at offshore platforms and the
processing of natural gas at liquefied natural gas facilities)
typically result in emission of greenhouse gases. Likewise,
emissions arise from power and downstream operations, including
crude oil transportation and refining. Finally, although beyond
the control of the company, the use of passenger vehicle fuels
and related products by consumers also results in greenhouse gas
emissions that may be regulated.
The companys financial performance will depend on a number
of factors, including, among others, the greenhouse gas
emissions reductions required by law, the price and availability
of emission allowances and credits, the extent to which Chevron
would be entitled to receive emission allowances or need to
purchase them in the open market or through auctions and the
impact of legislation on the companys ability to recover
the costs incurred through the pricing of the companys
products. Material cost increases or incentives to conserve or
use alternative energy sources could reduce demand for products
the company currently sells. To the extent these costs are not
ultimately reflected in the price of the companys
products, the companys operating results will be adversely
affected.
|
|
Item 1B.
|
Unresolved
Staff Comments
|
None.
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
the Securities Exchange Act Industry Guide No. 2
(Disclosure of Oil and Gas Operations) is also
contained in Item 1 and in Tables I through VII on pages
FS-62 to FS-74. Note 13, Properties, Plant and
Equipment, to the companys financial statements is
on
page FS-43.
|
|
Item 3.
|
Legal
Proceedings
|
Ecuador Chevron is a defendant in a civil
lawsuit before the Superior Court of Nueva Loja in Lago Agrio,
Ecuador, brought in May 2003 by plaintiffs who claim to be
representatives of certain residents of an area where an oil
production consortium formerly had operations. The lawsuit
alleges damage to the environment from the oil exploration and
production operations, and seeks unspecified damages to fund
environmental remediation and restoration of the alleged
environmental harm, plus a health monitoring program. Until
1992, Texaco Petroleum Company (Texpet), a subsidiary of Texaco
Inc., was a minority member of this consortium with
Petroecuador, the Ecuadorian state-owned oil company, as the
majority partner; since 1990, the operations have been conducted
solely by Petroecuador. At the conclusion of the consortium and
following an independent third-party environmental audit of the
concession area, Texpet entered into a formal agreement with the
Republic of Ecuador and Petroecuador for Texpet to remediate
specific sites assigned by the government in proportion to
Texpets ownership share of the consortium. Pursuant to
that agreement, Texpet conducted a three-year remediation
program at a cost of $40 million. After certifying that the
sites were properly remediated, the government granted Texpet
and all related corporate entities a full release from any and
all environmental liability arising from the consortium
operations.
Based on the history described above, Chevron believes that this
lawsuit lacks legal or factual merit. As to matters of law, the
company believes first, that the court lacks jurisdiction over
Chevron; second, that the law under which plaintiffs bring the
action, enacted in 1999, cannot be applied retroactively to
Chevron; third, that the claims are barred by the
31
statute of limitations in Ecuador; and, fourth, that the lawsuit
is also barred by the releases from liability previously given
to Texpet by the Republic of Ecuador and Petroecuador. With
regard to the facts, the company believes that the evidence
confirms that Texpets remediation was properly conducted
and that the remaining environmental damage reflects
Petroecuadors failure to timely fulfill its legal
obligations and Petroecuadors further conduct since
assuming full control over the operations.
In April 2008, a mining engineer appointed by the court to
identify and determine the cause of environmental damage, and to
specify steps needed to remediate it, issued a report
recommending that the court assess $8 billion, which would,
according to the engineer, provide financial compensation for
purported damages, including wrongful death claims, and pay for,
among other items, environmental remediation, health care
systems, and additional infrastructure for Petroecuador. The
engineers report also asserted that an additional
$8.3 billion could be assessed against Chevron for unjust
enrichment. The engineers report is not binding on the
court. Chevron also believes that the engineers work was
performed and his report prepared in a manner contrary to law
and in violation of the courts orders. Chevron submitted a
rebuttal to the report in which it asked the court to strike the
report in its entirety. In November 2008, the engineer revised
the report and, without additional evidence, recommended an
increase in the financial compensation for purported damages to
a total of $18.9 billion and an increase in the assessment
for purported unjust enrichment to a total of $8.4 billion.
Chevron submitted a rebuttal to the revised report, and Chevron
will continue a vigorous defense of any attempted imposition of
liability.
Management does not believe an estimate of a reasonably possible
loss (or a range of loss) can be made in this case. Due to the
defects associated with the engineers report, management
does not believe the report itself has any utility in
calculating a reasonably possible loss (or a range of loss).
Moreover, the highly uncertain legal environment surrounding the
case provides no basis for management to estimate a reasonably
possible loss (or a range of loss).
|
|
Item 4.
|
Submission
of Matters to a Vote of Security Holders
|
None.
32
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-24.
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
|
|
|
Oct. 1 Oct. 31, 2008
|
|
|
14,185,681
|
|
|
|
67.71
|
|
|
|
14,184,858
|
|
|
|
|
|
Nov. 1 Nov. 30, 2008
|
|
|
7,687,933
|
|
|
|
72.46
|
|
|
|
7,665,000
|
|
|
|
|
|
Dec. 1 Dec. 31, 2008
|
|
|
6,373,015
|
|
|
|
76.05
|
|
|
|
6,367,989
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Oct. 1 Dec. 31, 2008
|
|
|
28,246,629
|
|
|
|
70.88
|
|
|
|
28,217,847
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Includes 14,339 common shares repurchased during the three-month
period ended December 31, 2008, from company employees for
required personal income tax withholdings on the exercise of the
stock options issued to management and employees under the
companys broad-based employee stock options, long-term
incentive plans and former Texaco Inc. stock option plans. Also
includes 14,443 shares delivered or attested to in
satisfaction of the exercise price by holders of certain former
Texaco Inc. employee stock options exercised during the
three-month period ended December 31, 2008. The October
purchases also include approximately 14.2 million shares
acquired in an exchange transaction for a U.S. upstream property
and cash.
|
|
(2)
|
In September 2007, the company authorized stock repurchases of
up to $15 billion that may be made from time to time at
prevailing prices as permitted by securities laws and other
requirements and subject to market conditions and other factors.
The program will occur over a period of up to three years and
may be discontinued at any time. As of December 31, 2008,
118,996,749 shares had been acquired under this program for
$10.1 billion.
|
|
|
Item 6.
|
Selected
Financial Data
|
The selected financial data for years 2004 through 2008 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 Instruments, beginning on
page FS-13
and in Note 7 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.
33
|
|
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 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 Chief
Financial Officer concluded that the companys disclosure
controls and procedures were effective as of December 31,
2008.
|
|
(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 Chief Financial Officer, conducted an evaluation of
the effectiveness of the companys internal control over
financial reporting based on the Internal Control
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on the results
of this evaluation, the companys management concluded that
internal control over financial reporting was effective as of
December 31, 2008.
The effectiveness of the companys internal control over
financial reporting as of December 31, 2008, has been
audited by PricewaterhouseCoopers LLP, an independent registered
public accounting firm, as stated in its report included on
page FS-26.
|
|
(c)
|
Changes
in Internal Control Over Financial Reporting
|
During the quarter ended December 31, 2008, 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 26, 2009
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
|
|
D.J. OReilly
|
|
62
|
|
Chairman of the Board and Chief Executive Officer (since 2000)
|
|
Chief Executive Officer
|
P.J. Robertson
|
|
62
|
|
Vice Chairman of the Board (since 2002)
|
|
Policy, Government and Public Affairs; Human Resources
|
J.E. Bethancourt
|
|
57
|
|
Executive Vice President (since 2003)
|
|
Technology; Chemicals; Mining; Health, Environment and Safety
|
G.L. Kirkland
|
|
58
|
|
Executive Vice President (since 2005) President of Chevron
Overseas
Petroleum Inc. (2002 to 2004)
|
|
Worldwide Exploration and Production Activities and Global Gas
Activities, including Natural Gas Trading
|
J.S. Watson
|
|
52
|
|
Executive Vice President (since 2008)
Vice President and President of Chevron
International Exploration and Production Company
(2005 through 2007)
Vice President and Chief Financial
Officer (2000 through 2004)
|
|
Business Development, Mergers and Acquisitions, Strategic
Planning, Project Resources Company, Procurement
|
M.K. Wirth
|
|
48
|
|
Executive Vice President (since 2006) President of Global Supply
and Trading
(2004 to 2006)
President of Marketing, Asia, Middle East and Africa
Marketing
Business Unit (2001 to 2004)
|
|
Global Refining, Marketing, Lubricants, and Supply and Trading,
excluding Natural Gas Trading
|
P.E. Yarrington
|
|
52
|
|
Vice President and Chief Financial
Officer (since 2009)
Vice President and Treasurer
(2007 through 2008)
Vice President, Policy, Government and
Public Affairs (2002 to 2007)
|
|
Finance
|
C.A. James
|
|
54
|
|
Vice President and General Counsel
(since 2002)
|
|
Law
|
The information required by Item 401(b) and (e) of
Regulation S-K
and contained under the heading Election of
Directors in the Notice of the 2009 Annual Meeting and
2009 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 2009 Annual
Meeting of Stockholders (the 2009 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 2009 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 2009 Proxy Statement is incorporated by reference into this
Annual Report on
Form 10-K.
The information required by
Item 407(d)(4)-(5)
of
Regulation S-K
and contained under the heading Board
Operations Board Committee Membership and
Functions in the 2009 Proxy Statement is incorporated by
reference into this Annual Report on
Form 10-K.
35
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 Directors Compensation
in the 2009 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 2009 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 2009 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 2009 Proxy Statement shall not be deemed
filed for purposes 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 2009 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 2009 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 2009 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 Board
Operations Independence of Directors in the
2009 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 Ratification of
Independent Registered Public Accounting Firm in the 2009
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-26
|
|
|
FS-27
|
|
|
FS-28
|
|
|
FS-29
|
|
|
FS-30
|
|
|
FS-31
|
|
|
FS-32 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 and
E-2 lists
the exhibits that are filed as part of this report.
|
37
SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
Millions of Dollars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Employee Termination Benefits:
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1
|
|
$
|
117
|
|
|
$
|
28
|
|
|
$
|
91
|
|
Additions (deductions) charged (credited) to expense
|
|
|
(13
|
)
|
|
|
106
|
|
|
|
(21
|
)
|
Payments
|
|
|
(60
|
)
|
|
|
(17
|
)
|
|
|
(42
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31
|
|
$
|
44
|
|
|
$
|
117
|
|
|
$
|
28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for Doubtful Accounts:
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1
|
|
$
|
200
|
|
|
$
|
217
|
|
|
$
|
198
|
|
Additions charged to expense
|
|
|
105
|
|
|
|
29
|
|
|
|
61
|
|
Bad debt write-offs
|
|
|
(30
|
)
|
|
|
(46
|
)
|
|
|
(42
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31
|
|
$
|
275
|
|
|
$
|
200
|
|
|
$
|
217
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred Income Tax Valuation Allowance:*
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1
|
|
$
|
5,949
|
|
|
$
|
4,391
|
|
|
$
|
3,249
|
|
Additions charged to deferred income tax expense
|
|
|
2,599
|
|
|
|
1,894
|
|
|
|
1,700
|
|
Deductions credited to goodwill
|
|
|
|
|
|
|
|
|
|
|
(77
|
)
|
Deductions credited to deferred income tax expense
|
|
|
(1,013
|
)
|
|
|
(336
|
)
|
|
|
(481
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31
|
|
$
|
7,535
|
|
|
$
|
5,949
|
|
|
$
|
4,391
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
See also Note 16 to the
Consolidated Financial Statements beginning on
page FS-45.
|
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 26th day of February,
2009.
Chevron Corporation
David J. OReilly, 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 26th day of February, 2009.
|
|
|
Principal Executive Officers
|
|
|
(and Directors)
|
|
Directors
|
|
/s/David J.
OReilly
David J. OReilly, Chairman of the
Board and Chief Executive Officer
|
|
Samuel H. Armacost*
Samuel H. Armacost
|
|
|
|
/s/Peter J.
Robertson
Peter J. Robertson, Vice Chairman of the Board
|
|
Linnet F. Deily*
Linnet F. Deily
|
|
|
|
|
|
Robert E. Denham*
Robert E. Denham
|
|
|
|
|
|
Robert J. Eaton*
Robert J. Eaton
|
|
|
|
Principal Financial Officer
/s/Patricia E. Yarrington Patricia E. Yarrington, Vice President and Chief Financial Officer
Principal Accounting Officer
/s/Mark A. Humphrey Mark A. Humphrey, Vice President and Comptroller
|
|
Sam Ginn* Sam Ginn
Enrique Hernandez, Jr.* Enrique Hernandez, Jr.
Franklyn G. Jenifer* Franklyn G. Jenifer
Sam Nunn* Sam Nunn
|
|
|
|
|
|
Donald B. Rice*
Donald B. Rice
|
|
|
|
*By: /s/Lydia I.
Beebe
Lydia I. Beebe,
Attorney-in-Fact
|
|
Kevin W. Sharer*
Kevin W. Sharer
|
|
|
Charles R.
Shoemate*
Charles R. Shoemate
|
|
|
|
|
|
Ronald D. Sugar*
Ronald D. Sugar
|
|
|
|
|
|
Carl Ware*
Carl Ware
|
39
Financial
Table of Contents
FS-2
|
|
|
|
|
|
|
|
FS-2 |
|
|
FS-2 |
|
|
FS-2 |
|
|
FS-5 |
|
|
FS-6 |
|
|
FS-8 |
|
|
FS-10 |
|
|
FS-10 |
|
|
FS-12 |
|
|
FS-12 |
|
|
FS-13 |
|
|
FS-15 |
|
|
FS-15 |
|
|
FS-17 |
|
|
FS-18 |
|
|
FS-21 |
|
|
FS-24 |
FS-25
|
|
|
Consolidated
Financial Statements |
|
|
|
|
FS-25 |
|
|
FS-26 |
|
|
FS-27 |
|
|
FS-28 |
|
|
FS-29 |
|
|
FS-30 |
|
|
FS-31 |
FS-32
FS-1
|
|
|
|
|
|
|
|
|
|
Managements Discussion and Analysis of
Financial Condition and Results of Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Key Financial Results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars, except per-share amounts |
|
2008 |
|
|
|
2007 |
|
|
2006 |
|
Net Income |
|
$ |
23,931 |
|
|
|
$ |
18,688 |
|
|
$ |
17,138 |
|
Per Share Amounts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Basic |
|
$ |
11.74 |
|
|
|
$ |
8.83 |
|
|
$ |
7.84 |
|
Diluted |
|
$ |
11.67 |
|
|
|
$ |
8.77 |
|
|
$ |
7.80 |
|
Dividends |
|
$ |
2.53 |
|
|
|
$ |
2.26 |
|
|
$ |
2.01 |
|
Sales and Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues |
|
$ |
264,958 |
|
|
|
$ |
214,091 |
|
|
$ |
204,892 |
|
Return on: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Capital Employed |
|
|
26.6 |
% |
|
|
|
23.1 |
% |
|
|
22.6 |
% |
Average Stockholders Equity |
|
|
29.2 |
% |
|
|
|
25.6 |
% |
|
|
26.0 |
% |
|
|
|
|
|
Income by Major Operating Area
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2008 |
|
|
|
2007 |
|
|
2006 |
|
Upstream Exploration and Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
7,126 |
|
|
|
$ |
4,532 |
|
|
$ |
4,270 |
|
International |
|
|
14,584 |
|
|
|
|
10,284 |
|
|
|
8,872 |
|
|
|
|
|
|
Total Upstream |
|
|
21,710 |
|
|
|
|
14,816 |
|
|
|
13,142 |
|
|
|
|
|
|
Downstream Refining, Marketing
and Transportation |
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
1,369 |
|
|
|
|
966 |
|
|
|
1,938 |
|
International |
|
|
2,060 |
|
|
|
|
2,536 |
|
|
|
2,035 |
|
|
|
|
|
|
Total Downstream |
|
|
3,429 |
|
|
|
|
3,502 |
|
|
|
3,973 |
|
|
|
|
|
|
Chemicals |
|
|
182 |
|
|
|
|
396 |
|
|
|
539 |
|
All Other |
|
|
(1,390 |
) |
|
|
|
(26 |
) |
|
|
(516 |
) |
|
|
|
|
|
Net Income* |
|
$ |
23,931 |
|
|
|
$ |
18,688 |
|
|
$ |
17,138 |
|
|
|
|
|
|
|
*Includes Foreign Currency Effects: |
|
|
$ 862 |
|
|
|
|
$(352 |
) |
|
|
$(219 |
) |
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
ending December 31, 2008.
Business Environment and Outlook
Chevron is a global energy company with
significant business activities in the following
countries: Angola, Argentina, Australia, Azerbaijan,
Bangladesh, Brazil, Cambodia, Canada, Chad, China,
Colombia, Democratic Republic of the Congo, Denmark,
France, India, Indonesia, Kazakhstan, Myanmar, the
Netherlands, Nigeria, Norway, the Partitioned Neutral
Zone between Saudi Arabia and Kuwait, the Philippines,
Qatar, 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 largely on the
profitability of its upstream (exploration and
production) and downstream (refining, marketing and
transportation) business segments. The single biggest
factor that affects the
results of operations for both segments is
movement in the price of crude oil. In the downstream
business, crude oil is the largest cost component of
refined products. The overall trend in earnings is
typically less affected by results from the companys
chemicals business and other activities and invest-
ments. Earnings for the company in any period
may also be influenced by events or transactions that
are infrequent and/ or unusual in nature.
In recent
years and through most of 2008, Chevron and the oil
and gas industry at large experienced an increase in
certain costs that exceeded the general trend of
inflation in many areas of the world. This increase in
costs affected the companys operating expenses and
capital programs for all business segments, but
particularly for upstream. These cost pressures began
to soften somewhat in late 2008. As the price of crude
oil dropped precipitously from a record high in
mid-year, the demand for some goods and services in
the industry began to slacken. This cost trend is
expected to continue during 2009 if crude-oil prices
do not significantly rebound. (Refer to the Upstream
section on next page for a discussion of the trend in
crude-oil prices.)
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. 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.
To sustain its long-term competitive position in
the upstream business, the company must develop and
replenish an inventory of projects that offer adequate
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. 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. The
company will continue to monitor these developments,
take them into account in evaluating future investment
opportunities, and otherwise seek to mitigate any risks
to the companys current operations or future
prospects.
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 growth. Refer to the
Results of Operations section beginning on page FS-6
for discussions of net gains on asset sales during
2008. Asset dispositions and
restructurings may occur in future periods and
could result in significant gains or losses.
FS-2
The company has been closely monitoring the ongoing uncertainty in financial and credit
markets, the rapid decline in crude-oil prices that began in the second half of 2008, and the
general contraction of worldwide economic activity. Management is taking these developments into
account in the conduct of daily operations and for business planning. The company remains confident of its underlying financial strength to deal with potential problems presented in this
environment.
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 may be caused by military conflicts, civil
unrest or political uncertainty. Moreover, any of these factors could also inhibit the companys
production capacity in an affected region. The company monitors developments closely in the
countries in which it operates and holds investments, and attempts to manage risks in operating its
facilities and business.
Price levels for capital and exploratory costs and operating expenses associated with the efficient production of crude oil and natural gas can also be subject to external factors beyond the
companys control. External factors include not only the general level of inflation but also
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 also can be affected by damages to
production facilities caused by severe weather or civil unrest.
Industry price levels for crude oil were volatile during 2008. The spot price for West Texas
Intermediate (WTI) crude oil, a benchmark crude, started 2008 at $96 per barrel and peaked at $147
in early July. At the end of the year, the WTI price had fallen to $45 per barrel. As of
mid-February 2009, the WTI price was $38 per barrel. The collapse in price during the second half
of 2008 was largely driven by a decline in the demand for crude oil that was associated with a
significant weakening in world economies. The WTI price averaged $100 per barrel for the full-year
2008, compared with $72 in 2007.
As in 2007, a wide differential in prices existed in 2008 between high-quality (i.e.,
high-gravity, low-sulfur) crude oils and those of lower quality (i.e., low-gravity, high-sulfur
crude). The relatively lower price for the high-sulfur crudes has been associated with an ample
supply and relatively lower demand due to the limited number of refineries that are able to
process this lower-quality feedstock into light products (i.e., motor gasoline, jet fuel, aviation
gasoline and diesel fuel). Chevron produces or shares in the production of heavy crude oil in
California, Chad, Indonesia, the Partitioned Neutral Zone between Saudi Arabia and Kuwait,
Venezuela and certain fields in Angola, China and the United Kingdom North Sea. (Refer to 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 during 2008, benchmark prices at Henry Hub averaged about $9 per thousand cubic feet (MCF),
compared with about $7 in 2007. At December 31, 2008, and as of mid-February 2009,
FS-3
|
|
|
|
|
|
|
|
|
|
Managements Discussion and Analysis of
Financial Condition and Results of Operations |
|
|
|
|
|
|
|
|
|
|
the Henry Hub price was about $5.60 and $4.70 per MCF, respectively. Fluctuations in the price
for natural gas in the United States are closely associated with the volumes produced in North
America and the inventory in underground storage relative to customer demand. U.S. natural gas
prices are also typically higher during the winter period when demand for heating is greatest.
Certain other regions of the world in which the company operates have different supply, demand
and regulatory circumstances, typically resulting in lower average sales prices for the companys
production of natural gas. (Refer to page FS-10 for the companys average natural gas realizations
for the U.S. and international regions.) Additionally, excess-supply conditions that exist in
certain parts of the world cannot easily serve to mitigate the relatively higher-price conditions
in the United States and other markets because of the lack of infrastructure to transport and
receive liquefied natural gas.
To help address this regional imbalance between supply and demand for natural gas, Chevron
continues to invest in long-term projects in areas of excess supply to install infrastructure to
produce and liquefy natural gas for transport by tanker, along with investments and commitments to
regasify the product in markets where demand is strong and supplies are not as plentiful. Due to
the significance of the overall investment in these long-term projects, the natural gas sales
prices in the areas of excess supply (before the natural gas is transferred to a processing
facility) are expected to remain below sales prices for natural gas that is produced much nearer to
areas of high demand and can be transported in existing natural gas pipeline networks (as in the
United States or Thailand).
Besides the impact of the fluctuation in price for crude oil and natural gas, 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, changes in tax rates on income, and the cost of goods and services.
Chevrons worldwide net oil-equivalent production in 2008, including volumes produced from oil
sands, averaged 2.53 million barrels per day, a decline of about 90,000 barrels per day from 2007
due mainly to the impact of higher prices on volumes recovered under certain production-sharing and
variable-royalty agreements outside the United States and damage to production facilities in
September 2008 caused by hurricanes Gustav and Ike in the U.S. Gulf of Mexico. (Refer to the
discussion of U.S. upstream production trends in the Results of
Operations section on page
FS-6.
Refer also to the Selected Operating Data table on page
FS-10 for a listing of production volumes
for each of the three years ending December 31, 2008.)
The company estimates that oil-equivalent production in 2009 will average approximately 2.63
million barrels per day. This estimate is subject to many uncertainties, including quotas that may
be imposed by OPEC, price effects on production volumes calculated under cost-recovery and
variable-royalty provisions of certain contracts, changes in fiscal terms or restrictions on the
scope of company operations, delays in project startups, fluctuations in demand for natural gas in
various markets, weather conditions that may shut in production, civil unrest, changing
geopolitics, or other disruptions to operations. Future production levels also are affected by the
size and number of economic investment opportunities and, for new large-scale projects, the time
lag between initial exploration and the beginning of production. Most of Chevrons upstream
investment is currently being made outside the United States. Investments in upstream projects
generally are made well in advance of the start of the associated production of crude oil and
natural gas.
Approximately 20 percent of the companys net oil-equivalent production in 2008 occurred in
the OPEC-member countries of Angola, Nigeria and Venezuela and in the Partitioned Neutral Zone
between Saudi Arabia and Kuwait. (This production statistic excludes volumes produced in Indonesia,
which relinquished its OPEC membership at the end of 2008.) At a meeting on December 17, 2008, OPEC
announced a reduction of 4.2 million barrels per day, or 14 percent, from actual September 2008
production of 29 million barrels per day. The reduction became effective January 1, 2009. OPEC
quotas did not significantly affect Chevrons production level in 2007 or in 2008. The companys
current and future production levels could be affected by the cutbacks announced by OPEC in
December 2008.
Refer to the Results of Operations section on pages FS-6 through FS-7 for
additional discussion of the companys upstream operations.
Downstream Earnings for the downstream segment are closely tied to margins on the refining
and marketing of products that include gasoline, diesel, jet fuel, lubricants, fuel oil and
feedstocks for chemical manufacturing. Industry margins are sometimes volatile and can be affected
by the global and regional supply-and-demand balance for refined products and by changes in the
price of crude oil used for refinery feedstock. Industry margins can also be influenced by refined-product inventory levels, geopolitical events, refinery maintenance programs and disruptions
at refineries resulting from unplanned outages that may be due to severe weather or other
operational events.
Other factors affecting profitability for downstream operations include the reliability and
efficiency of the companys refining and marketing network, the effectiveness of
FS-4
the crude-oil and product-supply functions and the economic returns on invested capital. Profitability can also
be affected by the volatility of tanker-charter rates for the companys shipping operations, which
are driven by the industrys demand for crude oil and product tankers. Other factors beyond the
companys control include the general level of inflation and energy costs to operate the companys
refinery and distribution network.
The companys most significant marketing areas are the West Coast of North America, the U.S.
Gulf Coast, Latin America, Asia, southern Africa and the United Kingdom. Chevron operates or has
ownership interests in refineries in each of these areas except Latin America. Downstream
earnings, especially in the United States, were weak from mid-2007 through mid-2008 due mainly to
increasing prices of crude oil used in the refining process that were not always fully recovered
through sales prices of refined products. Margins significantly improved in the second half of 2008 as the price of crude oil declined.
As part of its downstream strategy to focus on areas of market strength, the company announced
plans to sell marketing businesses in several countries. Refer to the discussion in Operating
Developments below.
Industry margins in the future may be volatile and are influenced by changes
in the price of crude oil used for refinery feedstock and by changes in the supply and demand for
crude oil and refined products. The industry supply-and-demand balance can be affected by
disruptions at refineries resulting from maintenance programs and unplanned outages, including
weather-related disruptions; refined-product inventory levels; and geopolitical events.
Refer to pages FS-7 through FS-8 for additional discussion of the companys downstream
operations.
Chemicals Earnings in the petrochemicals business are closely tied to global chemical demand,
industry inventory levels and plant capacity utilization. Feedstock and fuel costs, which tend to
follow crude oil and natural gas price movements, also influence earnings in this segment.
Refer to the Results of Operations section on page FS-8 for additional discussion of
chemicals earnings.
Operating Developments
Key operating developments and other events during 2008 and early 2009 included the following:
Upstream
Australia Started production from Train 5 of the 17 percent-owned North West Shelf Venture
onshore liquefied-natural-gas (LNG) facility in West Australia, increasing export capacity from
about 12 million metric tons annually to more than 16 million. The company also announced plans for
an LNG project that initially will have a capacity of 5 million tons per year and process natural
gas from Chevrons 100 percent-owned Wheatstone discovery located on the northwest coast of
mainland Australia.
Canada Finalized agreements with the government of Newfoundland and Labrador to develop the 27
percent-owned Hebron heavy-oil project off the eastern coast.
Indonesia Achieved first oil at North Duri Field Area 12, which Chevron operates with a 100
percent interest. Maximum total crude-oil production of 34,000 barrels per day is expected in 2012.
Kazakhstan Completed the second phase of a major
expansion of production operations and processing
facilities at the 50 percent-owned Tengizchevroil
affiliate, increasing
total crude-oil production capacity from 400,000 to 540,000 barrels per day.
Middle East Signed an agreement with the Kingdom of Saudi Arabia to extend to 2039 the
companys operation of the Kingdoms 50 percent interest in oil and gas resources of the onshore
area of the Partitioned Neutral Zone between the Kingdom and the state of Kuwait.
Nigeria Started production offshore at the 68 percent-owned and operated Agbami Field, with total oil production
expected to reach a maximum of 250,000 barrels per day by the end of 2009. The company and partners also
announced plans to develop the 30 percent-owned and
partner-operated offshore Usan Field, which is expected to have maximum total production of 180,000 barrels of crude oil per
day within one year of start-up in 2012.
Republic
of the Congo Confirmed startup of the 32 percent-owned, partner-operated Moho-Bilondo deepwater project, which is expected to reach maximum total crude-oil production of 90,000
barrels per day in 2010.
Thailand Approved construction in the Gulf of Thailand of the 70 percent-owned and operated
Platong Gas II project, which is designed to have processing capacity of 420 million cubic feet of
natural gas per day.
United States Began production at the 75 percent-owned and operated Blind Faith project in the
deepwater Gulf of Mexico. Total volumes are expected to ramp up during 2009 to approximately 65,000
barrels of crude oil and 55 million cubic feet of natural gas per day.
Downstream
The company announced plans to sell marketing-related businesses in Brazil, Nigeria, Benin,
Cameroon, Republic of the Congo, Côte dIvoire, Togo, Kenya, and Uganda.
FS-5
|
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|
Managements Discussion and Analysis of
Financial Condition and Results of Operations |
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|
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|
Other
Common Stock Dividends Increased the quarterly common stock dividend by 12.1 percent in April 2008
to $0.65 per share. 2008 was the 21st consecutive year that the company increased its annual
dividend payment.
Common Stock Repurchase Program Acquired $8.0 billion of common shares in 2008 as part of a $15
billion repurchase program initiated in 2007.
Results of Operations
Major Operating Areas The following section presents the results of operations for the companys
business segments upstream, downstream and chemicals as well as for all other, which
includes mining, power generation businesses, the various companies and departments that are
managed at the corporate level, and the companys investment in Dynegy prior to its sale in May
2007. Income is also presented for the U.S. and international geographic areas of the upstream and
downstream business segments. (Refer to Note 9, beginning on page
FS-38, for a discussion of the
companys reportable segments, as defined in Financial Accounting Standards Board (FASB)
Statement No. 131, Disclosures About Segments of an Enterprise and Related Information.) 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 Exploration and Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2008 |
|
|
|
2007 |
|
|
2006 |
|
|
|
|
|
|
Income |
|
$ |
7,126 |
|
|
|
$ |
4,532 |
|
|
$ |
4,270 |
|
|
|
|
|
|
U.S upstream income of $7.1 billion in 2008 increased $2.6 billion from 2007. Higher average prices
for crude oil and natural gas increased earnings by $3.1 billion between periods. Also contributing
to the higher earnings were gains of approximately $1 billion on asset sales, including a $600
million gain on an asset-exchange transaction. Partially offsetting these benefits were adverse
effects of about $1.6 billion associated with lower oil-equivalent production and higher operating
expenses, which included approximately $400 million of expenses resulting from damage to facilities
in the Gulf of Mexico caused by hurricanes Gustav and Ike in September.
Income of $4.5 billion in 2007 increased approximately $260 million from 2006. Results in 2007
benefited approximately $700 million from higher prices for crude oil and natural gas liquids.
This benefit to income was partially offset by the effects of a decline in oil-equivalent
production and an increase in depreciation, operating and exploration expenses.
The companys average realization for crude oil and natural gas liquids in 2008 was $88.43 per
barrel, compared with $63.16 in 2007 and $56.66 in 2006. The average natural gas realization was
$7.90 per thousand cubic feet in 2008, compared with $6.12 and $6.29 in 2007 and 2006,
respectively.
Net oil-equivalent production in 2008 averaged 671,000 barrels per day, down 9.7 percent and
12.1 percent from 2007 and 2006, respectively. The decrease between 2007 and 2008 was mainly due to
normal field declines and the adverse impact of the hurricanes. The decline in 2007 from 2006 was
due primarily to normal field declines. The net liquids component of oil-equivalent production for
2008 averaged 421,000 barrels per day, down approximately 8 percent from 2007 and down 9 percent
compared with 2006. Net natural gas production averaged 1.5 billion cubic feet per day in 2008,
down 12 percent from 2007 and down 17 percent from 2006.
Refer to the Selected Operating Data table on page FS-10 for the three-year comparative
production volumes in the United States.
International Upstream Exploration and Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2008 |
|
|
|
2007 |
|
|
2006 |
|
|
|
|
|
|
Income* |
|
$ |
14,584 |
|
|
|
$ |
10,284 |
|
|
$ |
8,872 |
|
|
|
|
|
|
*Includes Foreign Currency Effects: |
|
|
$ 873 |
|
|
|
|
$ (417 |
) |
|
|
$ (371 |
) |
International upstream income of $14.6 billion in 2008 increased $4.3 billion from 2007.
Higher prices for crude oil and natural gas increased earnings by $4.9 billion. Partially
offsetting the benefit of higher prices was an impact of about $1.8 billion associated with a
reduction of crude-oil sales volumes due to
timing of certain cargo liftings and higher depreciation and operating expenses. Foreign
currency effects benefited earnings by $873 million in 2008, compared with reductions to earnings
of $417 million in 2007 and $371 million in 2006.
FS-6
Income in 2007 of $10.3 billion increased $1.4 billion from 2006. Earnings in 2007 benefited
approximately $1.6 billion from higher prices, primarily for crude oil, and $300 million from
increased liftings. Non-recurring income-tax items also benefited earnings between periods. These
benefits to income were partially offset by the impact of higher operating and depreciation
expenses.
The companys average realization for crude oil and natural gas liquids in 2008 was $86.51 per
barrel, compared with $65.01 in 2007 and $57.65 in 2006. The average natural gas realization was
$5.19 per thousand cubic feet in 2008, compared with $3.90 and $3.73 in 2007 and 2006,
respectively.
Net oil-equivalent production of 1.86 million
barrels per day in 2008 declined about 1 percent and 2
percent from 2007 and 2006, respectively. The volumes
for each year included production from oil sands in
Canada. Volumes in 2006 also included production under
an operating service agreement in Venezuela until its
conversion to a joint-stock company in October of that
year. Absent the impact of higher prices on certain
production-sharing and variable-royalty agreements, net
oil-equivalent production increased between 2007 and
2008. The decline in 2007 from 2006 was associated with
the impact of the contract conversion in Venezuela and
the impact of higher prices on production-sharing
agreements.
The net liquids component of oil-equivalent
production was 1.3 million barrels per day in 2008, a
decrease of 5 percent from 2007 and 9 percent from
2006. Net natural gas production of 3.6 billion cubic
feet per day in 2008 was up 9 percent and 15 percent
from 2007 and 2006, respectively.
Refer to the
Selected Operating Data table, on page FS-10, for the
three-year comparative of international production
volumes.
U.S. Downstream Refining, Marketing and Transportation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2008 |
|
|
|
2007 |
|
|
2006 |
|
|
|
|
|
|
Income |
|
$ |
1,369 |
|
|
|
$ |
966 |
|
|
$ |
1,938 |
|
|
|
|
|
|
U.S downstream earnings of $1.4 billion in 2008
increased about $400 million from 2007 due mainly to
improved margins on the sale of refined products and
gains on derivative commodity instruments. Operating
expenses were higher between periods. Income of $966
million in 2007 decreased nearly $1 billion from 2006.
The decline was associated mainly with lower refined-product margins and higher planned and unplanned
refinery downtime than a year earlier. Operating
expenses were also higher in 2007 than in 2006.
Sales volumes of refined products were 1.41 million barrels
per day in 2008, a decrease of 3 percent from 2007.
The decline was associated with reduced sales of
gasoline and fuel oil. Sales volumes of refined
products were 1.46 million barrels per day in 2007, a
decrease of 3 percent from 2006. The reported sales
volume for 2007 was on a different basis than 2006 due
to a change in accounting rules that became effective
April 1, 2006, for certain purchase-and-sale (buy/
sell) contracts with the same counterparty. Excluding
the
impact of this accounting standard, refined-product sales in 2007 decreased 1 percent from
2006. Branded gasoline sales volumes of 601,000 barrels per day in 2008 was
down about 4 percent and 2 percent from 2007 and 2006,
respectively.
Refer to the Selected Operating Data
table on page FS-10 for a three-year comparative of
sales volumes of gasoline and other refined products
and refinery-input volumes. Refer also to Note 14,
Accounting for Buy/Sell Contracts, on page FS-43 for
a discussion of the accounting for purchase-and-sale
contracts with the same counterparty.
International Downstream Refining, Marketing and Transportation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2008 |
|
|
|
2007 |
|
|
2006 |
|
|
|
|
|
|
Income* |
|
$ |
2,060 |
|
|
|
$ |
2,536 |
|
|
$ |
2,035 |
|
|
|
|
|
|
*Includes Foreign Currency Effects: |
|
|
$ 193 |
|
|
|
|
$ 62 |
|
|
|
$ 98 |
|
International downstream income of $2.1 billion in
2008 decreased nearly $500 million from 2007. Earnings
in 2007 included gains of approximately $1 billion on
the sale of assets, which included an interest in a
refinery and marketing assets in the Benelux region of
Europe. The $500 million improvement otherwise between
years was associated primarily with a benefit from
gains on derivative commodity instruments that was only
partially offset by the impact of lower margins on the
sale of refined products. Foreign currency effects
increased earnings by $193 million in 2008, compared
with $62 million in 2007. Income in 2007 of $2.5
billion increased $500 million from 2006, largely due
to the gains on asset sales. Margins on the sale of
refined products in 2007 were up slightly from 2006.
Operating expenses were higher, and earnings from the
companys shipping operations were lower.
FS-7
|
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|
Managements Discussion and Analysis of
Financial Condition and Results of Operations |
|
|
|
|
|
|
|
|
|
|
Refined-product
sales volumes were 2.02
million barrels per day
in 2008, about 1 percent
lower than 2007 due
mainly to reduced sales
of gas oil and fuel oil.
Refined product sales
volumes were 2.03 million
barrels per day in 2007,
about 5 percent lower
than 2006. The decline in
2007 was largely due to
the impact of asset sales
and the accounting-standard
change for buy/sell
contracts. Excluding the
accounting change, sales
decreased about 4
percent.
Refer to the
Selected Operating Data
table, on page FS-10, for
a three-year comparative
of sales volumes of gasoline
and other refined
products and refinery-input volumes. Refer also to Note 14, Accounting for Buy/Sell
Contracts, on page FS-43 for a discussion of the
accounting for purchase-and-sale contracts with the same counterparty.
Chemicals
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2008 |
|
|
|
2007 |
|
|
2006 |
|
|
|
|
|
|
Income* |
|
$ |
182 |
|
|
|
$ |
396 |
|
|
$ |
539 |
|
|
|
|
|
|
*Includes Foreign Currency Effects: |
|
|
$ (18 |
) |
|
|
|
$ (3 |
) |
|
|
$ (8 |
) |
The chemicals segment includes the companys
Oronite subsidiary and the 50 percent-owned Chevron
Phillips Chemical Company LLC (CPChem). In 2008,
earnings were $182 million, compared with $396 million
and $539 million in 2007 and 2006, respectively.
Earnings declined in 2008 due to lower sales volumes of
commodity chemicals by CPChem. Higher expenses for
planned maintenance activities also contributed to the
earnings decline. Earnings also declined for the
companys Oronite subsidiary due to lower volumes and
higher operating expenses. In 2007, earnings of $396
million decreased $143 million from 2006 due to the impact
of lower margins on the sale of commodity chemicals by
CPChem that were only partially offset by improved
margins on Oronites sales of additives for lubricants
and fuel.
All Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2008 |
|
|
|
2007 |
|
|
2006 |
|
|
|
|
|
|
Net Charges* |
|
$ |
(1,390 |
) |
|
|
$ |
(26 |
) |
|
$ |
(516 |
) |
|
|
|
|
|
*Includes Foreign Currency Effects: |
|
|
$ (186 |
) |
|
|
|
$ 6 |
|
|
|
$ 62 |
|
All Other includes mining operations, power generation businesses,
worldwide cash management and debt financing activities, corporate
administrative functions, insurance operations, real estate activities,
alternative fuels and technology companies, and the companys interest in
Dynegy prior to its sale in May 2007.
Net charges in 2008 increased $1.4 billion from 2007. Results in 2007 included
a $680 million gain on the sale of the companys investment in Dynegy
common stock and a loss of approximately $175 million associated with the early redemption of Texaco Capital Inc. bonds.
Results in 2008 included net
unfavorable
corporate tax items and increased costs of environmental remediation for sites that previously had been
closed or sold. Foreign exchange effects also contributed to the
increase in net charges between years. Net charges of $26 million in
2007 decreased $490 million from 2006 due mainly to the
Dynegy-related gain in 2007.
Consolidated Statement of Income
Comparative amounts for certain income statement
categories are shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2008 |
|
|
|
2007 |
|
|
2006 |
|
|
|
|
|
|
Sales and other operating revenues |
|
$ |
264,958 |
|
|
|
$ |
214,091 |
|
|
$ |
204,892 |
|
|
|
|
|
|
Sales and other operating revenues increased in
the comparative periods due mainly to higher prices
for crude oil, natural gas and refined products.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2008 |
|
|
|
2007 |
|
|
2006 |
|
|
|
|
|
|
Income from equity affiliates |
|
$ |
5,366 |
|
|
|
$ |
4,144 |
|
|
$ |
4,255 |
|
|
|
|
|
|
FS-8
Income from equity affiliates increased in 2008 from 2007 on improved upstream-related
earnings at Tengizchevroil (TCO) due to higher prices for crude oil. Lower income from equity affiliates
between 2006 and 2007 was mainly due to a decline in earnings from CPChem, Dynegy (sold in
May 2007) and downstream affiliates in the Asia-Pacific area. Partially offsetting these declines
were improved results for TCO and income for a full year from Petroboscan, which was converted from
an operating service agreement to a joint-stock company in October 2006. Refer to Note 12,
beginning on page FS-41, for a discussion of Chevrons investments in affiliated companies.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2008 |
|
|
|
2007 |
|
|
2006 |
|
|
|
|
|
Other income |
|
$ |
2,681 |
|
|
|
$ |
2,669 |
|
|
$ |
971 |
|
|
|
|
|
Other income of $2.7 billion in 2008 included gains of approximately $1.3 billion on asset
sales. Other income of $2.7 billion in 2007 included net gains of $1.7 billion from asset sales and
a loss of $245 million on the early redemption of debt. Interest income was approximately $340
million in 2008 and $600 million in both 2007 and 2006. Foreign currency effects benefited other
income by $355 million in 2008 while reducing other income by $352 million and $260 million in 2007
and 2006, respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2008 |
|
|
|
2007 |
|
|
2006 |
|
|
|
|
|
Purchased crude oil and products |
|
$ |
171,397 |
|
|
|
$ |
133,309 |
|
|
$ |
128,151 |
|
|
|
|
|
Crude oil and product purchases in 2008 increased $38.1 billion from 2007 due to higher prices
for crude oil, natural gas and refined products. Crude oil and product purchases in 2007 increased
more than $5 billion from 2006 due to these same factors.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2008 |
|
|
|
2007 |
|
|
2006 |
|
|
|
|
|
Operating,
selling, general and
administrative expenses |
|
$ |
26,551 |
|
|
|
$ |
22,858 |
|
|
$ |
19,717 |
|
|
|
|
|
Operating, selling, general and administrative expenses in 2008 increased approximately $3.7
billion from 2007 primarily due to $1.2 billion of higher costs for employee and contract labor;
$800 million of increased costs for materials, services and equipment; $700 million of uninsured
losses associated with hurricanes in the Gulf of Mexico in 2008; and an increase of about $300
million for environmental remediation activities. Total expenses were about $3.1 billion higher in
2007 than in 2006. Increases were recorded in a number of categories, including $1.5 billion of
higher costs for employee and contract labor.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2008 |
|
|
|
2007 |
|
|
2006 |
|
|
|
|
|
Exploration expense |
|
$ |
1,169 |
|
|
|
$ |
1,323 |
|
|
$ |
1,364 |
|
|
|
|
|
Exploration expenses in 2008 declined from 2007 due mainly to lower amounts for well
write-offs for operations in the United States. Expenses in 2007 were essentially unchanged from
2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2008 |
|
|
|
2007 |
|
|
2006 |
|
|
|
|
|
Depreciation, depletion and
amortization |
|
$ |
9,528 |
|
|
|
$ |
8,708 |
|
|
$ |
7,506 |
|
|
|
|
|
Depreciation, depletion and amortization expenses increased in 2008 from 2007 largely due to
higher depreciation rates for certain crude oil and natural gas producing fields, reflecting
completion of higher-cost development projects and asset-retirement obligations. The increase
between 2006 and 2007 reflects an increase in charges related to asset write-downs and higher
depreciation rates for certain crude oil and natural gas producing fields worldwide.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2008 |
|
|
|
2007 |
|
|
2006 |
|
|
|
|
|
Taxes other than on income |
|
$ |
21,303 |
|
|
|
$ |
22,266 |
|
|
$ |
20,883 |
|
|
|
|
|
Taxes other than on income decreased between 2007 and 2008 periods mainly due to lower import
duties as a result of the effects of the 2007 sales of the companys Benelux refining and
marketing businesses and a decline in import volumes in the United Kingdom. Taxes other than on
income increased between 2006 and 2007 due to higher import duties in the companys U.K. downstream
operations in 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2008 |
|
|
|
2007 |
|
|
2006 |
|
|
|
|
|
Interest and debt expense |
|
$ |
|
|
|
|
$ |
166 |
|
|
$ |
451 |
|
|
|
|
|
Interest and debt expense decreased significantly in 2008 because all interest-related
amounts were being capitalized. Interest and debt expense in 2007 decreased from 2006 primarily due
to lower average debt balances and higher amounts of interest capitalized.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2008 |
|
|
|
2007 |
|
|
2006 |
|
|
|
|
|
Income tax expense |
|
$ |
19,026 |
|
|
|
$ |
13,479 |
|
|
$ |
14,838 |
|
|
|
|
|
Effective income tax rates were 44 percent in 2008, 42 percent in 2007 and 46 percent in 2006.
Rates were higher between 2007 and 2008 primarily due to a greater proportion of income earned in
tax jurisdictions with higher income tax rates. In addition, the 2007 period included a relatively
low effective tax rate on the sale of the companys investment in Dynegy common stock and the sale
of downstream assets in Europe. Rates were lower in 2007 compared with 2006 due mainly to the
impact of nonrecurring items in 2007 mentioned above and the absence of 2006 charges related to a
tax-law change that increased tax rates on upstream operations in the U.K. North Sea and the
settlement of a tax claim in Venezuela. Refer also to the discussion of income taxes in Note 16
beginning on page FS-45.
FS-9
|
|
|
|
|
|
|
|
|
|
Managements Discussion and Analysis of
Financial Condition and Results of Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Selected Operating Data1,2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
|
|
2007 |
|
|
2006 |
|
|
|
|
|
U.S. Upstream |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Crude Oil and Natural Gas
Liquids Production (MBPD) |
|
|
421 |
|
|
|
|
460 |
|
|
|
462 |
|
Net Natural Gas Production (MMCFPD)3 |
|
|
1,501 |
|
|
|
|
1,699 |
|
|
|
1,810 |
|
Net Oil-Equivalent Production (MBOEPD) |
|
|
671 |
|
|
|
|
743 |
|
|
|
763 |
|
Sales of Natural Gas (MMCFPD) |
|
|
7,226 |
|
|
|
|
7,624 |
|
|
|
7,051 |
|
Sales of Natural Gas Liquids (MBPD) |
|
|
159 |
|
|
|
|
160 |
|
|
|
124 |
|
Revenues From Net Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
Liquids ($/Bbl) |
|
$ |
88.43 |
|
|
|
$ |
63.16 |
|
|
$ |
56.66 |
|
Natural Gas ($/MCF) |
|
$ |
7.90 |
|
|
|
$ |
6.12 |
|
|
$ |
6.29 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International Upstream |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Crude Oil and Natural Gas
Liquids Production (MBPD) |
|
|
1,228 |
|
|
|
|
1,296 |
|
|
|
1,270 |
|
Net Natural Gas Production (MMCFPD)3 |
|
|
3,624 |
|
|
|
|
3,320 |
|
|
|
3,146 |
|
Net Oil-Equivalent
Production (MBOEPD)4 |
|
|
1,859 |
|
|
|
|
1,876 |
|
|
|
1,904 |
|
Sales Natural Gas (MMCFPD) |
|
|
4,215 |
|
|
|
|
3,792 |
|
|
|
3,478 |
|
Sales Natural Gas Liquids (MBPD) |
|
|
114 |
|
|
|
|
118 |
|
|
|
102 |
|
Revenues From Liftings |
|
|
|
|
|
|
|
|
|
|
|
|
|
Liquids ($/Bbl) |
|
$ |
86.51 |
|
|
|
$ |
65.01 |
|
|
$ |
57.65 |
|
Natural Gas ($/MCF) |
|
$ |
5.19 |
|
|
|
$ |
3.90 |
|
|
$ |
3.73 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Worldwide Upstream |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Oil-Equivalent Production
(MBOEPD)3,4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
671 |
|
|
|
|
743 |
|
|
|
763 |
|
International |
|
|
1,859 |
|
|
|
|
1,876 |
|
|
|
1,904 |
|
|
|
|
|
|
|
Total |
|
|
2,530 |
|
|
|
|
2,619 |
|
|
|
2,667 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Downstream |
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline Sales (MBPD)5 |
|
|
692 |
|
|
|
|
728 |
|
|
|
712 |
|
Other Refined-Product Sales (MBPD) |
|
|
721 |
|
|
|
|
729 |
|
|
|
782 |
|
|
|
|
|
|
|
Total (MBPD)6 |
|
|
1,413 |
|
|
|
|
1,457 |
|
|
|
1,494 |
|
Refinery Input (MBPD) |
|
|
891 |
|
|
|
|
812 |
|
|
|
939 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International Downstream |
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline Sales (MBPD)5 |
|
|
589 |
|
|
|
|
581 |
|
|
|
595 |
|
Other Refined-Product Sales (MBPD) |
|
|
1,427 |
|
|
|
|
1,446 |
|
|
|
1,532 |
|
|
|
|
|
|
|
Total (MBPD)6, 7 |
|
|
2,016 |
|
|
|
|
2,027 |
|
|
|
2,127 |
|
Refinery Input (MBPD) |
|
|
967 |
|
|
|
|
1,021 |
|
|
|
1,050 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 Includes interest in 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 gas = 1 barrel of oil. |
3 Includes natural gas consumed in operations (MMCFPD): |
United States |
|
|
70 |
|
|
|
65 |
|
|
|
56 |
|
International |
|
|
450 |
|
|
|
433 |
|
|
|
419 |
|
4 Includes other produced volumes (MBPD): |
|
|
|
|
|
|
|
|
|
|
|
|
Athabasca Oil Sands Net |
|
|
27 |
|
|
|
27 |
|
|
|
27 |
|
Boscan Operating Service Agreement |
|
|
|
|
|
|
|
|
|
|
82 |
|
|
|
|
|
|
|
27 |
|
|
|
27 |
|
|
|
109 |
|
5 Includes branded and unbranded gasoline. |
6 Includes volumes for buy/sell contracts (MBPD): |
United States |
|
|
|
|
|
|
|
|
|
|
26 |
|
International |
|
|
|
|
|
|
|
|
|
|
24 |
|
7 Includes sales of affiliates (MBPD): |
|
|
512 |
|
|
|
492 |
|
|
|
492 |
|
Liquidity and Capital Resources
Cash, cash equivalents and marketable securities Total balances were $9.6 billion and $8.1 billion
at December 31, 2008 and 2007, respectively. Cash provided by operating activities in 2008 was
$29.6 billion, compared with $25.0 billion in 2007 and $24.3 billion in 2006.
Cash provided by operating activities was net of contributions to employee pension plans of
approximately $800 million, $300 million and $400 million in 2008, 2007 and 2006, respectively.
Cash provided by investing activities included proceeds from asset sales of $1.5 billion in 2008,
$3.3 billion in 2007 and $1.0 billion in 2006.
At December 31, 2008, restricted cash of $367 million associated with capital-investment projects
at the companys Pascagoula, Mississippi, refinery and Angola liquefied natural gas project was
invested in short-term marketable securities and reclassified from cash equivalents to a long-term
asset on the Consolidated Balance Sheet.
Dividends The company paid dividends of approximately $5.2 billion in 2008, $4.8 billion in
2007 and $4.4 billion in 2006. In April 2008, the company increased its quarterly common stock
dividend by 12.1 percent to $0.65 per share.
Debt, capital lease and minority interest obligations Total debt and capital lease balances
were $8.9 billion at December 31, 2008, up from $7.2 billion at year-end 2007. The company also
had minority interest obligations of $469 million and $204 million at December 31, 2008 and 2007,
respectively.
The $1.7 billion increase in total debt and capital lease obligations during 2008 included the
net effect of an approximate $2.7 billion increase in commercial paper and $749 million of Chevron
Canada Funding Company bonds that matured. The companys debt and capital lease obligations due
within one year, consisting primarily of commercial paper and the current portion of long-term
debt, totaled $7.8 billion at December 31, 2008, up from $5.5 billion at year-end 2007. Of these
amounts, $5.0 billion and $4.4 billion were reclassified to long-term at the end of each period,
respectively. At year-end 2008, settlement of these obligations was not expected to require the use
of working capital within one year, as the company had the intent and the ability, as evidenced by
committed credit facilities, to refinance them on a long-term basis.
At year-end 2008, the company had $5 billion in committed credit facilities with various major
banks, which permit the refinancing of short-term obligations on a long-term basis. These
facilities support commercial-paper borrowing and also can be used for general corporate purposes. The companys
practice has been to continually
FS-10
replace expiring commitments with new commitments on substantially the same terms, maintaining
levels management believes appropriate. Terms of new commitments in the future will be subject to
market conditions at the time of renewal. Any borrowings under the facilities would be
unsecured indebtedness at interest rates based on London Interbank Offered Rate or an average of
base lending rates published by specified banks and on terms reflecting the companys strong
credit rating. No borrowings were outstanding under these facilities at December 31, 2008. In
addition, the company has an automatic shelf registration statement that expires in March 2010 for
an unspecified amount of nonconvertible debt securities issued or guaranteed by the company. In
January 2009, the companys Board of Directors authorized the issuance of one or more series of
notes or debentures in an aggregate amount up to $5 billion for a term not to exceed ten years.
At December 31, 2008, the company had outstanding public bonds issued by Chevron Corporation
Profit Sharing/Savings Plan Trust Fund, Texaco Capital Inc. and Union Oil Company of California.
All of these securities are 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-1 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-spending program and cash that may be generated from asset dispositions. During periods of
low prices for crude oil and natural gas and narrow margins for refined products and commodity
chemicals, the company has the flexibility to increase borrowings and/or modify capital-spending
plans to continue paying the common stock dividend and maintain the companys high-quality debt
ratings.
Common stock repurchase program In September 2007, the company authorized the acquisition of
up to $15 billion of additional common shares from time to time at prevailing prices, as permitted
by securities laws and other legal requirements and subject to market conditions and other factors.
The program is for a period of up to three years and may be discontinued at any time. Through
December 31, 2008, 119 million shares had been acquired under the program for $10.1 billion,
including $8.0 billion in 2008. These amounts include shares acquired in October 2008 as part of an
asset-exchange transaction described in Note 2 beginning on page FS-34. The company did not acquire
any shares in early 2009 and does not plan to acquire any shares in the 2009 first quarter.
Capital and exploratory expenditures Total reported expenditures for 2008 were $22.8 billion,
including $2.3 billion for the companys share of affiliates expenditures, which did not require
cash outlays by the company. In 2007 and 2006, expenditures were $20.0 billion and $16.6 billion,
respectively, including the companys share of affiliates expenditures of $2.3 billion and $1.9
billion in the corresponding periods.
Of the $22.8 billion in expenditures for 2008, about three-fourths, or $17.5 billion, related
to upstream activities. Approximately the same percentage was also expended for upstream operations
in 2007 and 2006. International upstream accounted for about 70 percent of the worldwide
upstream
investment in each of the three years, reflecting the companys continuing focus on opportunities
that are available outside the United States.
The company estimates that in 2009, capital and exploratory expenditures will be $22.8
billion, including $1.8 billion of spending by affiliates. About three-fourths of the total, or
$17.5 billion, is budgeted for exploration and production activities, with $13.9 billion of this
amount outside the United States. Spending in 2009 is primarily targeted for exploratory prospects
in the deepwater U.S. Gulf of Mexico, western Africa, and the Gulf of Thailand and major
development projects in Angola, Australia, Brazil, Indonesia, Nigeria, Thailand and the deepwater
U.S. Gulf of Mexico. Also included are one-time payments associated with upstream operating
agreements in China and the Partitioned Neutral Zone between Saudi Arabia and Kuwait.
FS-11
|
|
|
|
|
|
|
|
|
|
Managements Discussion and Analysis of
Financial Condition and Results of Operations |
|
|
|
|
|
|
|
|
|
|
Capital and Exploratory Expenditures
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
|
|
2007 |
|
|
|
2006 |
|
Millions of dollars |
|
U.S. |
|
|
Intl. |
|
|
Total |
|
|
|
U.S. |
|
|
Intl. |
|
|
Total |
|
|
|
U.S. |
|
|
Intl. |
|
|
Total |
|
|
|
|
|
|
|
|
|
Upstream Exploration and Production |
|
$ |
5,516 |
|
|
$ |
11,944 |
|
|
$ |
17,460 |
|
|
|
$ |
4,558 |
|
|
$ |
10,980 |
|
|
$ |
15,538 |
|
|
|
$ |
4,123 |
|
|
$ |
8,696 |
|
|
$ |
12,819 |
|
Downstream Refining, Marketing and
Transportation |
|
|
2,182 |
|
|
|
2,023 |
|
|
|
4,205 |
|
|
|
|
1,576 |
|
|
|
1,867 |
|
|
|
3,443 |
|
|
|
|
1,176 |
|
|
|
1,999 |
|
|
|
3,175 |
|
Chemicals |
|
|
407 |
|
|
|
78 |
|
|
|
485 |
|
|
|
|
218 |
|
|
|
53 |
|
|
|
271 |
|
|
|
|
146 |
|
|
|
54 |
|
|
|
200 |
|
All Other |
|
|
618 |
|
|
|
7 |
|
|
|
625 |
|
|
|
|
768 |
|
|
|
6 |
|
|
|
774 |
|
|
|
|
403 |
|
|
|
14 |
|
|
|
417 |
|
|
|
|
|
|
|
|
|
Total |
|
$ |
8,723 |
|
|
$ |
14,052 |
|
|
$ |
22,775 |
|
|
|
$ |
7,120 |
|
|
$ |
12,906 |
|
|
$ |
20,026 |
|
|
|
$ |
5,848 |
|
|
$ |
10,763 |
|
|
$ |
16,611 |
|
|
|
|
|
|
|
|
|
Total, Excluding Equity in Affiliates |
|
$ |
8,241 |
|
|
$ |
12,228 |
|
|
$ |
20,469 |
|
|
|
$ |
6,900 |
|
|
$ |
10,790 |
|
|
$ |
17,690 |
|
|
|
$ |
5,642 |
|
|
$ |
9,050 |
|
|
$ |
14,692 |
|
|
|
|
|
|
|
|
|
Worldwide downstream spending in 2009 is
estimated at $4.3 billion, with about $2.0 billion
for projects in the United States. Capital projects
include upgrades to refineries in the United States
and South Korea and construction of a gas-to-liquids
facility in support of associated upstream projects.
Investments in chemicals, technology and other
corporate businesses in 2009 are budgeted at $1.0
billion. Technology investments include projects
related to unconventional hydrocarbon technologies, oil
and gas reservoir management, and gas-fired and
renewable power generation.
Pension Obligations In 2008, the companys
pension plan contributions were $839 million (including
$577 million to the U.S. plans). The company estimates
contributions in 2009 will be approximately $800
million. Actual contribution amounts are dependent upon
plan-investment results, changes in pension
obligations, regulatory requirements and other economic
factors. Additional funding may be required if
investment returns are insufficient to offset
increases in plan obligations. Refer also to the
discussion of pension accounting in Critical
Accounting Estimates and Assumptions, beginning on
page FS-18.
Financial Ratios
Financial Ratios
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31 |
|
|
|
2008 |
|
|
|
2007 |
|
|
2006 |
|
|
|
|
|
|
Current Ratio |
|
|
1.1 |
|
|
|
|
1.2 |
|
|
|
1.3 |
|
Interest Coverage Ratio |
|
|
166.9 |
|
|
|
|
69.2 |
|
|
|
53.5 |
|
Debt Ratio |
|
|
9.3 |
% |
|
|
|
8.6 |
% |
|
|
12.5 |
% |
|
|
|
|
|
Current Ratio current assets divided by current
liabilities. The current ratio in all periods was
adversely affected by the fact that Chevrons
inventories are valued on a Last-In, First-Out basis.
At year-end 2008, the book value of inventory was lower
than replacement costs, based on average acquisition
costs during the year, by approximately $9 billion.
Interest Coverage Ratio income before
income tax expense, plus interest and debt expense and
amortization of capitalized interest, divided by before-tax
interest costs. The companys interest coverage ratio was higher
between 2007 and 2008 and between 2006 and 2007, primarily due to higher
before-tax income and lower average debt balances in each of the subsequent years.
Debt Ratio total debt as a percentage of total debt plus equity.
The increase between 2007 and 2008 was primarily due to higher
debt. The decrease between 2006 and 2007 was due to lower debt and higher stockholders equity balance.
Guarantees, Off-Balance-Sheet Arrangements and
Contractual Obligations, and Other Contingencies
Direct Guarantee
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
Commitment Expiration by Period |
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2012 |
|
|
After |
|
|
|
Total |
|
|
2009 |
|
|
2011 |
|
|
2013 |
|
|
2013 |
|
|
Guarantee of non-consolidated affiliate or
joint-venture obligation |
|
$ |
613 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
76 |
|
|
$ |
537 |
|
|
The companys guarantee of approximately $600
million is associated with certain payments under a
terminal-use agreement entered into by a company affiliate. The terminal is expected to be operational by
2012. Over the approximate 16-year term of the
guarantee, the maximum guarantee amount will be reduced
as certain fees are paid by the affiliate.
FS-12
There are numerous cross-indemnity agreements with the
affiliate and the other partners to permit recovery of
any amounts paid under the guarantee. Chevron has
recorded no liability for its obligation under this
guarantee.
Indemnifications The company provided certain
indemnities of contingent liabilities of Equilon and
Motiva to Shell and Saudi Refining, Inc., in
connection with the February 2002 sale of the companys
interests in those investments. The company would be
required to perform if the indemnified liabilities
become actual losses. Were that to occur, the company
could be required to make future payments up to $300
million. Through the end of 2008, the company had paid
$48 million under these indemnities and continues to be
obligated for possible additional indemnification
payments in the future.
The company has also provided indemnities relating
to contingent environmental liabilities related to
assets originally contributed by Texaco to the Equilon
and Motiva joint ventures and environmental conditions
that existed prior to the formation of Equilon and
Motiva or that occurred during the period of Texacos
ownership interest in the joint ventures. In general,
the environmental conditions or events that are subject
to these indemnities must have arisen prior to December
2001. Claims must be asserted no later than February
2009 for Equilon indemnities and no later than February
2012 for Motiva indemnities. Under the terms of these
indemnities, there is no maximum limit on the amount of
potential future payments. In February 2009, Shell delivered a
letter to the company purporting to preserve
unmatured claims for certain Equilon indemnities. The letter itself provides no estimate of the ultimate claim amount,
and management does not believe the letter provides a basis to estimate the amount, if any, of a range of loss or potential
range of loss with respect to Equilon or the Motiva indemnities. The company posts no assets as collateral
and has made no payments under the indemnities.
The amounts payable for the indemnities described
above are to be net of amounts recovered from insurance
carriers and others and net of liabilities recorded by
Equilon or Motiva prior to September 30, 2001, for any
applicable incident.
In the acquisition of Unocal, the company assumed
certain indemnities relating to contingent
environmental liabilities associated with assets that
were sold in 1997. Under the indemnification
agreement, the companys liability is unlimited until
April 2022, when the indemnification expires. The
acquirer shares in certain environmental remediation
costs up to a maximum obligation of $200 million, which
had not been reached as of December 31, 2008.
Securitization During 2008, the company terminated
the program used to securitize downstream-related trade
accounts receivable. At year-end 2007, the balance of
securitized receivables was $675 million. As of
December 31, 2008, the company had no other
securitization arrangements in place.
Minority Interests The company has commitments of $469 million
related to minority interests in subsidiary companies.
Long-Term Unconditional Purchase Obligations and
Commitments, Including Throughput and Take-or-Pay
Agreements The company and its subsidiaries have
certain other contingent liabilities relating to
long-term unconditional purchase obligations and
commitments, including throughput and take-or-pay
agreements, some of which relate to
suppliers financing arrangements. The agreements typically
provide goods and services, such as pipeline and
storage capacity, drilling rigs, utilities, and
petroleum products, to be used or sold in the
ordinary course of the companys business. The
aggregate approximate amounts of required payments
under these various commitments are: 2009 $6.4
billion; 2010 $4.0 billion; 2011 $3.6 billion;
2012 $1.5 billion; 2013 $1.3 billion; 2014 and
after $4.3 billion. A portion of these commitments
may ultimately be shared with project partners. Total
payments under the agreements were approximately $5.1
billion in 2008, $3.7 billion in 2007 and $3.0
billion in 2006.
The following table summarizes the
companys significant contractual obligations:
Contractual Obligations1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
Payments Due by Period |
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2012 |
|
|
After |
|
|
|
Total |
|
|
2009 |
|
|
2011 |
|
|
2013 |
|
|
2013 |
|
|
|
On Balance Sheet:2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-Term Debt3 |
|
$ |
2,818 |
|
|
$ |
2,818 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Long-Term Debt3 |
|
|
5,742 |
|
|
|
|
|
|
|
5,061 |
|
|
|
74 |
|
|
|
607 |
|
Noncancelable Capital
Lease Obligations |
|
|
548 |
|
|
|
97 |
|
|
|
154 |
|
|
|
143 |
|
|
|
154 |
|
Interest |
|
|
2,133 |
|
|
|
174 |
|
|
|
322 |
|
|
|
312 |
|
|
|
1,325 |
|
Off-Balance-Sheet: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncancelable Operating
Lease Obligations |
|
|
2,888 |
|
|
|
503 |
|
|
|
835 |
|
|
|
603 |
|
|
|
947 |
|
Throughput and
Take-or-Pay Agreements |
|
|
15,726 |
|
|
|
5,063 |
|
|
|
5,383 |
|
|
|
1,261 |
|
|
|
4,019 |
|
Other Unconditional
Purchase Obligations4 |
|
|
5,356 |
|
|
|
1,342 |
|
|
|
2,159 |
|
|
|
1,541 |
|
|
|
314 |
|
|
|
1 |
|
Excludes contributions for pensions and
other postretirement benefit plans. Information on
employee benefit plans is contained in Note 22
beginning on page FS-51. |
|
2 |
|
Does not include amounts related to the
companys income tax liabilities associated with
uncertain tax positions. The company is unable to
make reasonable estimates for the periods in which
these liabilities may become payable. The company
does not expect settlement of such liabilities will
have a material effect on its results of operations,
consolidated financial position or liquidity in any
single period. |
|
3 |
|
$5.0 billion of short-term debt that
the company expects to refinance is included in
long-term debt. The repayment schedule above reflects the projected repayment of the entire amounts in
the 20102011 period. |
|
4 |
|
Does not include obligations to
purchase the companys share of natural gas liquids
and regasified natural gas associated with
operations of the 36.4 percent-owned Angola LNG affiliate. The LNG plant is expected to commence
operations in 2012 and is designed to produce 5.2
million metric tons of liquefied natural gas and
related natural gas liquids per year. Volumes and
prices associated with these purchase obligations are
neither fixed nor determinable. |
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 discussed below 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
FS-13
|
|
|
|
|
|
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|
|
|
Managements Discussion and Analysis of
Financial Condition and Results of Operations |
|
|
|
|
|
|
|
|
|
|
Factors in Part I,
Item 1A, of the
companys 2008 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 purchase, 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 this activity
were not material to the companys financial position,
net income or cash flows in 2008.
The companys market
exposure positions are monitored and managed on a daily
basis by an internal Risk Control group to ensure
compliance with the companys risk management policies
that have been approved by the Audit Committee of the companys Board of Directors.
The derivative instruments used in the companys
risk management and trading activities consist mainly
of futures, options and swap contracts traded on the
NYMEX (New York Mercantile Exchange) and on electronic
platforms of ICE (Inter-Continental Exchange) and
GLOBEX (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.
Virtually all derivatives beyond those
designated as normal purchase and normal sale contracts
are recorded at fair value on the Consolidated Balance
Sheet 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 from
Chevrons derivative commodity instruments in 2008 was
a quarterly average increase of $160 million in total
assets and a quarterly average decrease of $1 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 instruments
held or issued, which are recorded on the balance sheet
at December 31, 2008, as derivative instruments in
accordance with FAS Statement No. 133, Accounting for
Derivative Instruments and Hedging Activities, as
amended (FAS 133). VaR is the maximum 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 distribution 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
table below 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, 2008 and 2007. The higher amounts in 2008 were
associated with an increase in price volatility for
these commodities during the year.
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2008 |
|
|
|
2007 |
|
|
|
|
|
Crude Oil |
|
$ |
39 |
|
|
|
$ |
29 |
|
Natural Gas |
|
|
5 |
|
|
|
|
3 |
|
Refined Products |
|
|
45 |
|
|
|
|
23 |
|
|
|
|
|
Foreign Currency The company enters into forward
exchange contracts, generally with terms of 180 days
or less, to manage some of its foreign currency
exposures. These exposures include revenue and
anticipated purchase transactions, including foreign
currency capital expenditures and lease commitments,
forecasted to occur within 180 days. The forward
exchange contracts are recorded at fair value on the
balance sheet with resulting gains and losses reflected in income.
The aggregate effect of a hypothetical 10 percent
increase in the value of the U.S. dollar at year-end
2008 would be a reduction in the fair value of the
foreign exchange contracts of approximately $100
million. The effect would be the opposite for a
hypothetical 10 percent decrease in the value of the
U.S. dollar at year-end 2008.
Interest
Rates The company enters into
interest-rate swaps from time to time as part of its
overall strategy to manage the interest rate risk on
its debt. Under the terms of the swaps, net cash
settlements are based on the difference between fixed-rate and floating-rate interest amounts calculated
by reference to agreed notional principal amounts.
Interest rate swaps related to a portion of the
companys fixed-rate debt are accounted for as fair
value hedges. Interest rate swaps related to floating-rate debt are recorded at fair value on the
balance sheet with resulting gains and losses reflected in income. At year-end 2008, the company had no
interest-rate swaps on floating-rate debt. The
companys only interest-rate swaps on fixed-rate debt
matured in January 2009.
FS-14
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-42, 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 Chevron and many other companies in the petroleum industry have used methyl tertiary butyl
ether (MTBE) as a gasoline additive. In October 2008, 59 cases were settled in which the company
was a party and which related to the use of MTBE in certain oxygenated gasolines and the alleged
seepage of MTBE into groundwater. The terms of this agreement are confidential and not material to
the companys results of operations, liquidity or financial position.
Chevron is a party to 37 other pending lawsuits and claims, the majority of which involve numerous
other petroleum marketers and refiners. Resolution of these lawsuits and claims may ultimately
require the company to correct or ameliorate the alleged effects on the environment of prior
release of MTBE by the company or other parties. Additional lawsuits and claims related to the use
of MTBE, including personal-injury claims, may be filed in the future. The settlement of the 59
lawsuits did not set any precedents related to standards of liability to be used to judge the
merits of the claims, corrective measures required or monetary damages to be assessed for the
remaining lawsuits and claims or future lawsuits and claims. As a result, the companys ultimate
exposure related to pending lawsuits and claims is not currently determinable, but could be
material to net income in any one period. The company no longer uses MTBE in the manufacture of
gasoline in the United States.
RFG Patent Fourteen purported class actions were brought by consumers who purchased
reformulated gasoline (RFG) from January 1995 through August 2005, alleging that Unocal misled the
California Air Resources Board into adopting standards for composition of RFG that overlapped with
Unocals undisclosed and pending patents. The parties agreed to a settlement that calls for, among
other things, Unocal to pay $48 million and for the establishment of a cy pres fund to administer
payout of the award. The court approved the final settlement in November 2008.
Ecuador Chevron is a
defendant in a civil lawsuit before the Superior Court of Nueva Loja in Lago Agrio, Ecuador,
brought in May 2003 by plaintiffs who claim to be representatives of certain residents of an area
where an oil production consortium formerly had operations. The lawsuit alleges damage to the
environment from the oil exploration and production operations, and seeks unspecified damages to
fund environmental remediation and restoration of the alleged environmental harm, plus a health
monitoring program. Until 1992, Texaco Petroleum Company (Texpet), a subsidiary of Texaco Inc., was
a minority member of this consortium with Petroecuador, the Ecuadorian state-owned
oil company, as
the majority partner; since 1990, the operations have been conducted solely by Petroecuador. At the
conclusion of the consortium and following an
independent third-party environmental audit of the concession area, Texpet entered into a
formal agreement with the Republic of Ecuador and Petroecuador for Texpet to remediate specific
sites assigned by the government in proportion to Texpets ownership share of the consortium.
Pursuant to that agreement, Texpet conducted a three-year remediation program at a cost of $40
million. After certifying that the sites were properly remediated, the government granted Texpet
and all related corporate entities a full release from any and all environmental liability arising
from the consortium operations.
Based on the history described above, Chevron believes that this lawsuit lacks legal or
factual merit. As to matters of law, the company believes first, that the court lacks jurisdiction
over Chevron; second, that the law under which plaintiffs bring the action, enacted in 1999, cannot
be applied retroactively to Chevron; third, that the claims are barred by the statute of
limitations in Ecuador; and, fourth, that the lawsuit is also barred by the releases from liability
previously given to Texpet by the Republic of Ecuador and Petroecuador. With regard to the facts,
the company believes that the evidence confirms that Texpets remediation was properly conducted
and that the remaining environmental damage reflects Petroecuadors failure to timely fulfill its
legal obligations and Petroecuadors further conduct since assuming full control over the
operations.
In April 2008, a mining engineer appointed by the court to identify and determine the cause of
environmental damage, and to specify steps needed to remediate it, issued a report recommending
that the court assess $8 billion, which would, according to the engineer, provide financial
compensation for purported damages, including wrongful death claims, and pay for, among other
items, environmental remediation, health care systems, and additional infrastructure for
Petroecuador. The engineers report also asserted that an additional $8.3 billion could be assessed
against Chevron for unjust enrichment. The engineers report is not binding on the court. Chevron
also believes that the engineers work was performed and his report prepared in a manner contrary
to law and in violation of the courts orders. Chevron submitted a rebuttal to the report in which
it asked the court to strike the report in its entirety. In November 2008, the engineer revised the
report and, without additional evidence, recommended an increase in the financial compensation for
purported damages to a total of $18.9 billion and an increase in the assessment for purported
unjust enrichment to a total of $8.4 billion. Chevron submitted a rebuttal to the revised report,
and Chevron will continue a vigorous defense of any attempted imposition of liability.
Management does not believe an estimate of a reasonably possible loss (or a range of loss) can
be made in this case. Due to the defects associated with the engineers report, management does not
believe the report itself has any utility in calculating a reasonably possible loss (or a range of
loss). Moreover, the highly uncertain legal environment surrounding the case provides no
basis for management to
FS-15
|
|
|
|
|
|
|
|
|
|
Managements Discussion and Analysis of
Financial Condition and Results of Operations |
|
|
|
|
|
|
|
|
|
|
estimate a reasonable possible loss (or a range of loss).
Environmental The company is
subject to loss contingencies pursuant to
environmental laws and regulations that in
the future may require the company to take
action to correct or ameliorate the
effects on the environment of prior release
of chemicals or petroleum substances, including MTBE, by the company
or other parties. Such
contingencies may exist for various sites, including, but not limited to, federal Superfund sites and analogous sites under
state laws, refineries, crude oil fields, service stations, terminals, land development areas, and
mining operations, whether operating, closed or divested. These future costs are not fully
determinable due to such factors as the unknown magnitude of possible contamination, the unknown
timing and extent of the corrective actions that may be required, the determination of the
companys liability in proportion to other responsible parties, and the extent to which such
costs are recoverable from third parties.
Although the company has provided for known environmental obligations that are probable and
reasonably estimable, the amount of additional future costs may be material to results of
operations in the period in which they are recognized. The company does not expect these costs will
have a material effect on its consolidated financial position or liquidity. Also, the company does
not believe its obligations to make such expenditures have had, or will have, any significant
impact on the companys competitive position relative to other U.S. or international petroleum or
chemical companies.
The 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 |
|
2008 |
|
|
|
2007 |
|
|
2006 |
|
|
|
|
|
|
Balance at January 1 |
|
$ |
1,539 |
|
|
|
$ |
1,441 |
|
|
$ |
1,469 |
|
Net Additions |
|
|
784 |
|
|
|
|
562 |
|
|
|
366 |
|
Expenditures |
|
|
(505 |
) |
|
|
|
(464 |
) |
|
|
(394 |
) |
|
|
|
|
|
Balance at December 31 |
|
$ |
1,818 |
|
|
|
$ |
1,539 |
|
|
$ |
1,441 |
|
|
|
|
|
|
Included in the $1,818 million year-end 2008 reserve balance were remediation activities of
248 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 2008 was $120 million. The federal Superfund law and analogous state laws provide for joint
and several liability for all responsible parties. Any future actions by the EPA or other
regulatory agencies to require Chevron to assume other potentially responsible parties costs at
designated hazardous waste sites are not expected to have a material effect on the companys
consolidated financial position or liquidity.
Of the remaining year-end 2008 environmental reserves balance of $1,698 million, $968 million
related to current and former sites for the companys U.S. downstream operations, including
refineries and other plants, marketing locations (i.e., service stations and terminals), and
pipelines. The remaining $730 million was associated with various sites in international downstream
($117 million), upstream ($390 million), chemicals ($154 million) and other ($69 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 or
local regulations. No single remediation site at year-end 2008 had a recorded liability that was
material to the companys financial position, results of operations 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 accounts for asset retirement obligations in
accordance with FASB Statement No. 143, Accounting for Asset Retirement Obligations (FAS 143).
Under FAS 143, the fair value of a liability for an asset retirement obligation is recorded when
there is a legal obligation associated with the retirement of long-lived assets and the liability
can be
FS-16
reasonably estimated. The liability balance of approximately $9.4 billion for asset
retirement obligations at year-end 2008 related primarily to upstream properties.
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 24, beginning on page FS-58, related to FAS 143 and the companys adoption
in 2005 of FASB Interpretation No. (FIN) 47, Accounting for Conditional Asset Retirement
Obligations An Interpretation of FASB Statement No. 143 (FIN 47), and the discussion of
Environmental Matters below.
Income Taxes The company calculates its income tax expense and liabilities quarterly. These
liabilities generally are subject to audit and are not finalized with the individual taxing
authorities until several years after the end of the annual period for which income taxes have been
calculated. Refer to Note 16 beginning on page FS-45 for a discussion of the periods for which tax
returns have been audited for the companys major tax jurisdictions and a discussion for all tax
jurisdictions of the differences between the amount of tax benefits recognized in the financial
statements and the amount taken or expected to be taken in a tax return. The company does not
expect that settlement of income tax liabilities associated with uncertain tax positions will have
a material effect on its results of operations, consolidated financial position or liquidity.
The Emergency Economic Stabilization Act of 2008, which contained a number of energy and tax-related
provisions, known as the Energy Improvement and Extension Act of 2008 (the Act), was signed into
U.S. law in October 2008. The Act includes two provisions that affect Chevrons tax liability,
beginning in the fourth quarter of 2008. The Act freezes at 6 percent the domestic manufacturers
deduction on income from U.S. oil and gas operations that was scheduled to increase to 9 percent in
2010. Effective in 2009, the Act expands the current foreign tax credit (FTC) limitation for
Foreign Oil and Gas Extraction Income to also include foreign downstream income, known as Foreign
Oil Related Income. This change is expected to impact Chevrons utilization of FTCs.
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, 2008, the company had approximately $2.1 billion of
suspended exploratory wells included in properties, plant and equipment, an increase of $458
million from 2007. The 2007 balance reflected an increase of $421 million from 2006.
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 $2.1 billion of suspended wells at year-end 2008 is uncertain pending
future activities, including normal project evaluation and additional drilling.
Refer
to Note 20, beginning on page FS-48, for additional discussion of suspended wells.
Equity Redetermination For oil and gas producing operations, ownership agreements may provide
for periodic reassessments of equity interests in estimated crude oil and natural gas reserves.
These activities, individually or together, may result in gains or losses that could be material to
earnings in any given period. One such equity redetermination process has been under way since 1996
for Chevrons interests in four producing zones at the Naval Petroleum Reserve at Elk Hills,
California, for the time when the remaining interests in these zones were owned by the U.S.
Department of Energy. A wide range remains for a possible net settlement amount for the four zones.
For this range of settlement, Chevron estimates its maximum possible net before-tax liability at
approximately $200 million, and the possible maximum net amount that could be owed to Chevron is
estimated at about $150 million. The timing of the settlement and the exact amount within this
range of estimates are uncertain.
Other Contingencies Chevron receives claims from and submits
claims to customers; trading partners; U.S. federal, state and local regulatory bodies;
governments; contractors; insurers; and suppliers. The amounts of these claims, individually and in
the aggregate, may be significant and take lengthy periods to resolve.
The company and its affiliates also continue to review and analyze their operations and may close, abandon, sell,
exchange, acquire or restructure assets to achieve operational or strategic benefits and to improve
competitiveness and profitability. These activities, individually or together, may result in gains
or losses in future periods.
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 con-
FS-17
|
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|
|
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|
Managements Discussion and Analysis of
Financial Condition and Results of Operations |
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sidered
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 2008 at approximately $3.1 billion for its
consolidated companies. Included in these expenditures were approximately $1.3 billion of
environmental capital expenditures and $1.8 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 2009, total worldwide
environmental capital expenditures are
estimated at $2.2 billion. These
capital costs are in addition to the
ongoing costs of complying with
environmental regulations and the
costs to remediate previously
contaminated sites.
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 or assumptions is according to
the disclosure guidelines of the Securities and
Exchange Commission (SEC), wherein:
|
1. |
|
the nature of the estimates or
assumptions is material due to the levels of
subjectivity and judgment neces- |
|
|
|
sary to
account for highly uncertain matters or the
susceptibility of such matters to change; and |
|
2. |
|
the impact of the estimates and
assumptions on the companys financial
condition or operating performance is
material. |
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 that require ... geological and engineering
data (that) demonstrate with reasonable certainty
(reserves) to be recoverable in future years from known
reservoirs under existing economic and operating
conditions, i.e., prices and costs as of the date the
estimate is made. 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, 2008, and to Table VII, Changes in the
Standardized Measure of Discounted Future Net Cash
Flows From Proved Reserves on page FS-74 for estimates
of proved-reserve values for each of the three years
ended December 31, 2008, which were based on year-end
prices at the time. Note 1 to the Consolidated
Financial Statements, beginning on page FS-32, 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-20, 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-32. The
development and selection of accounting estimates
FS-18
and
assumptions, including those deemed critical, and
the associated disclosures in this discussion have
been discussed by management with the Audit Committee
of the Board of Directors.
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 22, beginning on page FS-51, includes
information on the funded status of the companys
pension and OPEB plans at the end of 2008 and 2007; the
components of pension and OPEB expense for the three
years ending December 31, 2008; and the underlying
assumptions for those periods.
Pension and OPEB expense is recorded on the
Consolidated Statement of Income in Operating
expenses or Selling, general and administrative
expenses and applies to all business segments. The
year-end 2008 and 2007 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 funded status of
overfunded pension plans is recorded as a long-term
asset in Deferred charges and other assets. The
funded status of underfunded or unfunded pension and
OPEB plans is recorded in Accrued liabilities or
Reserves for employee benefit plans. Amounts yet to
be recognized as components of pension or OPEB expense
are recorded 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 68 percent of
the companys pension plan assets, has remained at 7.8
percent since 2002. For the 10 years ending December
31, 2008, actual asset returns averaged 3.7 percent for
this plan. The actual asset returns for the 10 years
ending December 31, 2007, averaged 8.7 percent. The
actual return for 2008 was negative and was associated
with the broad decline in the financial markets in the
second half of the year.
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, 2008,
the company selected a 6.3 percent discount rate for
the major U.S. pension and postretirement plans. This
rate was selected based on a cash flow analysis that
matched estimated future benefit payments to the
Citigroup Pension Discount Yield Curve as of year-end
2008. The discount rates at the end of 2007 and 2006
were 6.3 percent and 5.8 percent, respectively.
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 2008 was
$770 million. 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 2008 by approximately $70 million. A 1
percent increase in the discount rate for this same
plan, which accounted for about 61 percent of the
companywide pension obligation, would have reduced
total pension plan expense for 2008 by approximately
$140 million.
An increase in the discount rate would decrease
the pension obligation, thus changing the funded status
of a plan recorded on the Consolidated Balance Sheet.
The total pension liability on the Consolidated Balance
Sheet at December 31, 2008, for underfunded plans was
approximately $4.0 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 $250 million, which would have decreased
the plans underfunded status from approximately $2.0
billion to $1.8 billion. Other plans would be less
under-funded 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 2008, the companys pension plan contributions
were $839 million (including $577 million to the U.S.
plans). In 2009, the company estimates contributions
will be approximately $800 million. Actual contribution
amounts are
FS-19
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Managements Discussion and Analysis of
Financial Condition and Results of Operations |
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dependent upon plan-investment results,
changes in pension obligations, regulatory requirements
and other economic factors. Additional funding may be
required if investment returns are insufficient to
offset increases in plan obligations.
For the companys OPEB plans, expense for 2008
was $179 million and the total liability, which reflected the unfunded status of the plans at the end of
2008, was $2.9 billion.
As an indication of discount rate sensitivity to
the determination of OPEB expense in 2008, a 1 percent
increase in the discount rate for the companys primary
U.S. OPEB plan, which accounted for about 67 percent of
the companywide OPEB expense, would have decreased OPEB
expense by approximately $20 million. A 0.25 percent
increase in the discount rate for the same plan, which
accounted for about 86 percent of the companywide OPEB
liabilities, would have decreased total OPEB
liabilities at the end of 2008 by approximately $56
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 7 percent in 2009 and gradually drop
to 5 percent for 2017 and beyond. As an indication of
the health care cost-trend rate sensitivity to the
determination of OPEB expense in 2008, a 1 percent
increase in the rates for the main U.S. OPEB plan,
which accounted for 86 percent of the companywide OPEB
liabilities, would have increased OPEB expense $8
million.
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 22,
beginning on page FS-51, for information on the $6.0
billion of before-tax actuarial losses recorded by
the company as of December 31, 2008; a description of
the method used to amortize those costs; and an
estimate of the costs to be recognized in expense
during 2009.
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.
No major individual impairments of PP&E were
recorded for the three years ending December 31, 2008.
An estimate as to the sensitivity to 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
FS-20
of sale of a particular asset or
asset group in any period has been deemed more likely
than not, an impairment review is performed, and if the
estimated net proceeds exceed the carrying value of the
asset or asset group, no impairment charge is required.
Such calculations are reviewed each period until the
asset or asset group is disposed of. Assets that are
not impaired on a held-and-used basis could possibly
become impaired if a decision is made to sell such
assets. That is, the assets would be impaired if they
are classified as held-for-sale and the estimated
proceeds from the sale, less costs to sell, are less
than the assets associated carrying values.
Business Combinations Purchase-Price Allocation Accounting
for business combinations requires the
allocation of the companys purchase price to the
various assets and liabilities of the acquired business
at their respective fair values. The company uses all
available information to make these fair value
determinations, and for major acquisitions, may hire an
independent appraisal firm to assist in making fair
value estimates. In some instances, assumptions with
respect to the timing and amount of future revenues and
expenses associated with an asset might have to be used
in determining its fair value. Actual timing and amount
of net cash flows from revenues and expenses related
to that asset over time may differ materially from
those initial estimates, and if the timing is delayed
significantly or if the net cash flows decline significantly, the asset could become impaired. Effective
January 1, 2009, the accounting for business
combinations will change. Refer to Note 19 on page
FS-48.
Goodwill Goodwill
resulting from a business
combination is not subject to amortization. As required
by FASB Statement No. 142, Goodwill and Other
Intangible Assets, the company tests such goodwill at
the reporting unit level for impairment on an annual
basis and between annual tests if an event occurs or
circumstances change that would more likely than not
reduce the fair value of a reporting unit below its
carrying amount.
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 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 records 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 ben-
efits are recognized only
if management determines the tax position is more
likely than not (i.e., likelihood greater than 50
percent) to be allowed by the tax jurisdiction. For
additional discussion of income tax uncertainties,
refer to Note 16 beginning on page FS-45. Refer also to
the business segment discussions elsewhere in this
section for the effect on earnings from losses
associated with certain litigation, and environmental
remediation and tax matters for the three years ended
December 31, 2008.
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
FASB Statement No. 141 (revised 2007), Business
Combinations (FAS 141-R) In
December 2007, the FASB
issued FAS 141-R, which became effective for business
combination transactions having an acquisition date on
or after January 1, 2009. This standard requires the
acquiring entity in a business combination to recognize
the assets acquired, the liabilities assumed, and any
noncontrolling interest in the acquiree at the
acquisition date to be measured at their respective
fair values. It also requires acquisition-related
costs, as well as restructuring costs the acquirer
expects to incur for which it is not obligated at
acquisition date, to be recorded against income rather
than included in purchase-price determination. Finally,
the standard requires recognition of contingent
arrangements at their acquisition-date fair values,
with subsequent changes in fair value generally reflected in income.
FASB
Staff Position FAS 141(R)-a Accounting for Assets Acquired and
Liabilities Assumed in a Business Combination (FSP FAS
141(R)-a) In February 2009, the FASB approved
for issuance FSP FAS 141(R)-a, which became effective for business
combinations having an acquisition date on or after January 1,
2009. This standard requires an asset or liability arising from a
contingency in a business combination to be recognized at fair value
if fair value can be reasonably determined. If it cannot be
reasonably determined then the asset or liability will need to be
recognized in accordance with FASB Statement No. 5, Accounting for
Contingencies, and FASB Interpretation No. 14, Reasonable Estimation
of the Amount of the Loss.
FASB Statement No. 160, Noncontrolling Interests
in Consolidated Financial Statements, an amendment of
ARB No. 51 (FAS 160) The
FASB issued FAS 160 in
December 2007, which became effective for the company
January 1, 2009, with retroactive adoption of the
Standards presentation and
disclosure requirements for existing minority
interests. This standard requires ownership interests
in subsidiaries held by parties other than the parent
to be presented within the
FS-21
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Managements Discussion and Analysis of
Financial Condition and Results of Operations |
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equity section of the
Consolidated Balance Sheet but separate from the
parents equity. It also requires the amount of
consolidated net income attributable to the parent and
the noncontrolling interest to be clearly identified
and presented on the face of the Consolidated
Statement of Income. Certain changes in a parents
ownership interest are to be accounted for as equity
transactions and when a subsidiary is deconsolidated,
any noncontrolling equity investment in the former
subsidiary is to be initially measured at fair value.
Implementation of FAS 160 will not significantly
change the presentation of the companys Consolidated
Statement of Income or Consolidated Balance Sheet.
FASB Statement No. 161, Disclosures about
Derivative Instruments and Hedging Activities (FAS 161) In
March 2008, the FASB issued FAS 161, which became
effective for the company on January 1, 2009. This
standard amends and expands the disclosure requirements
of FASB Statement No. 133, Accounting for Derivative
Instruments and Hedging Activities. FAS 161 requires
disclosures related to objectives and strategies for
using derivatives; the fair-value amounts of, and gains
and losses on, derivative instruments; and
credit-risk-related contingent features in derivative
agreements. The companys disclosures for derivative
instruments will
be expanded to include a tabular
representation of the location and fair value amounts
of derivative instruments on the balance sheet, fair
value gains and losses on the income statement and
gains and losses associated with cash flow hedges
recognized in earnings and other comprehensive income.
FASB Staff Position FAS 132(R)-1, Employers
Disclosures about Postretirement Benefit Plan Assets
(FSP FAS 132(R)-1) In
December 2008, the FASB issued
FSP FAS 132(R)-1, which becomes effective with the
companys reporting at December 31, 2009. This standard
amends and expands the disclosure requirements on the
plan assets of defined benefit pension and other
postretirement plans to provide users of financial
statements with an understanding of: how investment
allocation decisions are made; the major categories of
plan assets; the inputs and valuation techniques used
to measure the fair value of plan assets; the effect of
fair-value measurements using significant unobservable
inputs on changes in plan assets for the period; and
significant concentrations of risk within plan assets.
The company does not prefund its other postretirement
plan obligations, and the effect on the companys
disclosures for its pension plan assets as a result of
the adoption of FSP FAS 132(R)-1 will depend on the
companys plan assets at that time.
FS-22
THIS
PAGE INTENTIONALLY LEFT BLANK
FS-23
Quarterly Results and Stock Market Data
Unaudited
|
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
|
|
2007 |
|
Millions of dollars, except per-share amounts |
|
4th Q |
|
|
3rd Q |
|
|
2nd Q |
|
|
1st Q |
|
|
|
4th Q |
|
|
3rd Q |
|
|
2nd Q |
|
|
1st Q |
|
|
|
|
|
|
Revenues and Other Income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales and other operating revenues1 |
|
$ |
43,145 |
|
|
$ |
76,192 |
|
|
$ |
80,962 |
|
|
$ |
64,659 |
|
|
|
$ |
59,900 |
|
|
$ |
53,545 |
|
|
$ |
54,344 |
|
|
$ |
46,302 |
|
Income from equity affiliates |
|
|
886 |
|
|
|
1,673 |
|
|
|
1,563 |
|
|
|
1,244 |
|
|
|
|
1,153 |
|
|
|
1,160 |
|
|
|
894 |
|
|
|
937 |
|
Other income |
|
|
1,172 |
|
|
|
1,002 |
|
|
|
464 |
|
|
|
43 |
|
|
|
|
357 |
|
|
|
468 |
|
|
|
856 |
|
|
|
988 |
|
|
|
|
|
|
Total Revenues and Other Income |
|
|
45,203 |
|
|
|
78,867 |
|
|
|
82,989 |
|
|
|
65,946 |
|
|
|
|
61,410 |
|
|
|
55,173 |
|
|
|
56,094 |
|
|
|
48,227 |
|
|
|
|
|
|
Costs and Other Deductions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased crude oil and products |
|
|
23,575 |
|
|
|
49,238 |
|
|
|
56,056 |
|
|
|
42,528 |
|
|
|
|
38,056 |
|
|
|
33,988 |
|
|
|
33,138 |
|
|
|
28,127 |
|
Operating expenses |
|
|
5,416 |
|
|
|
5,676 |
|
|
|
5,248 |
|
|
|
4,455 |
|
|
|
|
4,798 |
|
|
|
4,397 |
|
|
|
4,124 |
|
|
|
3,613 |
|
Selling, general and administrative expenses |
|
|
1,492 |
|
|
|
1,278 |
|
|
|
1,639 |
|
|
|
1,347 |
|
|
|
|
1,833 |
|
|
|
1,446 |
|
|
|
1,516 |
|
|
|
1,131 |
|
Exploration expenses |
|
|
338 |
|
|
|
271 |
|
|
|
307 |
|
|
|
253 |
|
|
|
|
449 |
|
|
|
295 |
|
|
|
273 |
|
|
|
306 |
|
Depreciation, depletion and amortization |
|
|
2,589 |
|
|
|
2,449 |
|
|
|
2,275 |
|
|
|
2,215 |
|
|
|
|
2,094 |
|
|
|
2,495 |
|
|
|
2,156 |
|
|
|
1,963 |
|
Taxes other than on income1 |
|
|
4,547 |
|
|
|
5,614 |
|
|
|
5,699 |
|
|
|
5,443 |
|
|
|
|
5,560 |
|
|
|
5,538 |
|
|
|
5,743 |
|
|
|
5,425 |
|
Interest and debt expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7 |
|
|
|
22 |
|
|
|
63 |
|
|
|
74 |
|
Minority interests |
|
|
6 |
|
|
|
32 |
|
|
|
34 |
|
|
|
28 |
|
|
|
|
35 |
|
|
|
25 |
|
|
|
19 |
|
|
|
28 |
|
|
|
|
|
|
Total Costs and Other Deductions |
|
|
37,963 |
|
|
|
64,558 |
|
|
|
71,258 |
|
|
|
56,269 |
|
|
|
|
52,832 |
|
|
|
48,206 |
|
|
|
47,032 |
|
|
|
40,667 |
|
|
|
|
|
|
Income Before Income Tax Expense |
|
|
7,240 |
|
|
|
14,309 |
|
|
|
11,731 |
|
|
|
9,677 |
|
|
|
|
8,578 |
|
|
|
6,967 |
|
|
|
9,062 |
|
|
|
7,560 |
|
Income Tax Expense |
|
|
2,345 |
|
|
|
6,416 |
|
|
|
5,756 |
|
|
|
4,509 |
|
|
|
|
3,703 |
|
|
|
3,249 |
|
|
|
3,682 |
|
|
|
2,845 |
|
|
|
|
|
|
Net Income |
|
$ |
4,895 |
|
|
$ |
7,893 |
|
|
$ |
5,975 |
|
|
$ |
5,168 |
|
|
|
$ |
4,875 |
|
|
$ |
3,718 |
|
|
$ |
5,380 |
|
|
$ |
4,715 |
|
|
|
|
|
|
Per-Share of Common Stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
2.45 |
|
|
$ |
3.88 |
|
|
$ |
2.91 |
|
|
$ |
2.50 |
|
|
|
$ |
2.34 |
|
|
$ |
1.77 |
|
|
$ |
2.52 |
|
|
$ |
2.20 |
|
Diluted |
|
$ |
2.44 |
|
|
$ |
3.85 |
|
|
$ |
2.90 |
|
|
$ |
2.48 |
|
|
|
$ |
2.32 |
|
|
$ |
1.75 |
|
|
$ |
2.52 |
|
|
$ |
2.18 |
|
|
|
|
|
|
Dividends |
|
$ |
0.65 |
|
|
$ |
0.65 |
|
|
$ |
0.65 |
|
|
$ |
0.58 |
|
|
|
$ |
0.58 |
|
|
$ |
0.58 |
|
|
$ |
0.58 |
|
|
$ |
0.52 |
|
Common Stock Price Range High2 |
|
$ |
82.20 |
|
|
$ |
99.08 |
|
|
$ |
103.09 |
|
|
$ |
94.61 |
|
|
|
$ |
94.86 |
|
|
$ |
94.84 |
|
|
$ |
84.24 |
|
|
$ |
74.95 |
|
Low2 |
|
$ |
57.83 |
|
|
$ |
77.50 |
|
|
$ |
86.74 |
|
|
$ |
77.51 |
|
|
|
$ |
83.79 |
|
|
$ |
80.76 |
|
|
$ |
74.83 |
|
|
$ |
66.43 |
|
|
|
|
|
|
1 Includes excise, value-added and similar taxes: |
|
$ |
2,080 |
|
|
$ |
2,577 |
|
|
$ |
2,652 |
|
|
$ |
2,537 |
|
|
|
$ |
2,548 |
|
|
$ |
2,550 |
|
|
$ |
2,609 |
|
|
$ |
2,414 |
|
2 End of day price. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The companys common stock is listed on the New York Stock Exchange (trading symbol: CVX). As of
February 20, 2009, stockholders of record numbered approximately
205,000. There are no restrictions
on the companys ability to pay dividends.
FS-24
Managements Responsibility for Financial Statements
To the Stockholders of Chevron Corporation
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, 2008.
The effectiveness of the companys internal control over financial reporting as of December
31, 2008, has been audited by PricewaterhouseCoopers LLP, an independent registered public
accounting firm, as stated in its report included herein.
|
|
|
|
|
|
|
|
|
|
David J. OReilly
|
|
Patricia E. Yarrington
|
|
Mark A. Humphrey |
Chairman of the Board
|
|
Vice President
|
|
Vice President |
and Chief Executive Officer
|
|
and Chief Financial Officer
|
|
and Comptroller |
February 26, 2009
FS-25
Report
of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of Chevron Corporation:
In our opinion, the accompanying consolidated balance
sheets and the related consolidated statements of income,
comprehensive income, stockholders equity and cash flows
present fairly, in all material respects, the
financial position of Chevron Corporation and its
subsidiaries at December 31, 2008 and December 31, 2007
and the results of their
operations and their cash flows for each of the three
years in the period ended December 31, 2008 in conformity
with accounting principles generally accepted in the
United States of America. In addition, in our opinion,
the financial statement schedule listed in the index
appearing under Item 15(a)(2) presents fairly, in all
material respects, the information set forth therein when
read in conjunction with the related consolidated
financial statements. Also in our opinion, the Company
maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2008
based on criteria established in Internal Control
Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission
(COSO). The Companys management is responsible for these
financial statements and financial statement schedule,
for maintaining effective internal control over financial
reporting and for its assessment of the effectiveness of
internal control over financial reporting, included in
the accompanying Managements Report on Internal Control
Over Financial Reporting. Our responsibility is to
express opinions on these financial statements, on the
financial statement schedule, and on the Companys
internal control over financial reporting based on our
integrated audits. We conducted our audits in accordance
with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require
that we plan and perform the audits to obtain reasonable
assurance about whether the financial statements are free
of material misstatement and whether effective internal
control over financial reporting was maintained in all
material respects. Our audits of the financial statements
included examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant
estimates made by management, and evaluating the overall
financial statement presentation. Our audit of internal
control over financial reporting included obtaining an
understanding of internal control over financial
reporting, assessing the risk that a material weakness
exists, and
testing and evaluating the design and
operating effectiveness of internal control based on the
assessed risk. Our audits also included performing such
other procedures as we considered necessary in the
circumstances. We believe that our audits provide a
reasonable basis for our opinions.
As discussed in Note 14 to the Consolidated
Financial Statements, the Company changed its method
of accounting for buy/sell contracts on April 1, 2006.
As discussed in Note 16 to the Consolidated
Financial Statements, the Company changed its method
of accounting for uncertain income tax positions on
January 1, 2007.
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.
/s/PricewaterhouseCoopers LLP
San Francisco, California
February 26, 2009
FS-26
Consolidated
Statement of Income
Millions of dollars, except per-share amounts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31 |
|
|
|
2008 |
|
|
|
2007 |
|
|
2006 |
|
|
|
|
|
|
Revenues and Other Income |
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales and other operating revenues1,2 |
|
$ |
264,958 |
|
|
|
$ |
214,091 |
|
|
$ |
204,892 |
|
Income from equity affiliates |
|
|
5,366 |
|
|
|
|
4,144 |
|
|
|
4,255 |
|
Other income |
|
|
2,681 |
|
|
|
|
2,669 |
|
|
|
971 |
|
|
|
|
|
|
Total Revenues and Other Income |
|
|
273,005 |
|
|
|
|
220,904 |
|
|
|
210,118 |
|
|
|
|
|
|
Costs and Other Deductions |
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased crude oil and products2 |
|
|
171,397 |
|
|
|
|
133,309 |
|
|
|
128,151 |
|
Operating expenses |
|
|
20,795 |
|
|
|
|
16,932 |
|
|
|
14,624 |
|
Selling, general and administrative expenses |
|
|
5,756 |
|
|
|
|
5,926 |
|
|
|
5,093 |
|
Exploration expenses |
|
|
1,169 |
|
|
|
|
1,323 |
|
|
|
1,364 |
|
Depreciation, depletion and amortization |
|
|
9,528 |
|
|
|
|
8,708 |
|
|
|
7,506 |
|
Taxes other than on income1 |
|
|
21,303 |
|
|
|
|
22,266 |
|
|
|
20,883 |
|
Interest and debt expense |
|
|
|
|
|
|
|
166 |
|
|
|
451 |
|
Minority interests |
|
|
100 |
|
|
|
|
107 |
|
|
|
70 |
|
|
|
|
|
|
Total Costs and Other Deductions |
|
|
230,048 |
|
|
|
|
188,737 |
|
|
|
178,142 |
|
|
|
|
|
|
Income Before Income Tax Expense |
|
|
42,957 |
|
|
|
|
32,167 |
|
|
|
31,976 |
|
Income Tax Expense |
|
|
19,026 |
|
|
|
|
13,479 |
|
|
|
14,838 |
|
|
|
|
|
|
Net Income |
|
$ |
23,931 |
|
|
|
$ |
18,688 |
|
|
$ |
17,138 |
|
|
|
|
|
|
Per-Share of Common Stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
11.74 |
|
|
|
$ |
8.83 |
|
|
$ |
7.84 |
|
Diluted |
|
$ |
11.67 |
|
|
|
$ |
8.77 |
|
|
$ |
7.80 |
|
|
|
|
|
|
|
|
|
|
1 Includes excise, value-added and similar taxes. |
|
$ |
9,846 |
|
|
|
$ |
10,121 |
|
|
$ |
9,551 |
|
2
Includes amounts in revenues for buy/sell contracts; associated costs
are in Purchased crude oil and products.
Refer also to Note 14, on page FS-43. |
|
$ |
|
|
|
|
$ |
|
|
|
$ |
6,725 |
|
See accompanying Notes to the Consolidated Financial Statements.
FS-27
Consolidated Statement of Comprehensive Income
Millions of dollars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31 |
|
|
|
2008 |
|
|
|
2007 |
|
|
2006 |
|
|
|
|
|
|
Net Income |
|
$ |
23,931 |
|
|
|
$ |
18,688 |
|
|
$ |
17,138 |
|
|
|
|
|
|
Currency translation adjustment |
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized net change arising during period |
|
|
(112 |
) |
|
|
|
31 |
|
|
|
55 |
|
|
|
|
|
|
Unrealized holding (loss) gain on securities |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) gain arising during period |
|
|
(6 |
) |
|
|
|
17 |
|
|
|
(88 |
) |
Reclassification to net income of net realized loss |
|
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
Total |
|
|
(6 |
) |
|
|
|
19 |
|
|
|
(88 |
) |
|
|
|
|
|
Derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net derivatives gain (loss) on hedge transactions |
|
|
139 |
|
|
|
|
(10 |
) |
|
|
2 |
|
Reclassification to net income of net realized loss |
|
|
32 |
|
|
|
|
7 |
|
|
|
95 |
|
Income taxes on derivatives transactions |
|
|
(61 |
) |
|
|
|
(3 |
) |
|
|
(30 |
) |
|
|
|
|
|
Total |
|
|
110 |
|
|
|
|
(6 |
) |
|
|
67 |
|
|
|
|
|
|
Defined benefit plans |
|
|
|
|
|
|
|
|
|
|
|
|
|
Minimum pension liability adjustment |
|
|
|
|
|
|
|
|
|
|
|
(88 |
) |
Actuarial loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization to net income of net actuarial loss |
|
|
483 |
|
|
|
|
356 |
|
|
|
|
|
Actuarial (loss) gain arising during period |
|
|
(3,228 |
) |
|
|
|
530 |
|
|
|
|
|
Prior service cost |
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization to net income of net prior service credits |
|
|
(64 |
) |
|
|
|
(15 |
) |
|
|
|
|
Prior service (credit) cost arising during period |
|
|
(32 |
) |
|
|
|
204 |
|
|
|
|
|
Defined benefit plans sponsored by equity affiliates |
|
|
(97 |
) |
|
|
|
19 |
|
|
|
|
|
Income taxes on defined benefit plans |
|
|
1,037 |
|
|
|
|
(409 |
) |
|
|
50 |
|
|
|
|
|
|
Total |
|
|
(1,901 |
) |
|
|
|
685 |
|
|
|
(38 |
) |
|
|
|
|
|
Other Comprehensive (Loss) Gain, Net of Tax |
|
|
(1,909 |
) |
|
|
|
729 |
|
|
|
(4 |
) |
|
|
|
|
|
Comprehensive Income |
|
$ |
22,022 |
|
|
|
$ |
19,417 |
|
|
$ |
17,134 |
|
|
|
|
|
|
See accompanying Notes to the Consolidated Financial Statements.
FS-28
Consolidated Balance Sheet
Millions of dollars, except per-share amounts
|
|
|
|
|
|
|
|
|
|
|
|
At December 31 |
|
|
|
2008 |
|
|
|
2007 |
|
|
|
|
|
|
Assets |
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
9,347 |
|
|
|
$ |
7,362 |
|
Marketable securities |
|
|
213 |
|
|
|
|
732 |
|
Accounts and notes receivable (less allowance: 2008 $246; 2007 $165) |
|
|
15,856 |
|
|
|
|
22,446 |
|
Inventories: |
|
|
|
|
|
|
|
|
|
Crude oil and petroleum products |
|
|
5,175 |
|
|
|
|
4,003 |
|
Chemicals |
|
|
459 |
|
|
|
|
290 |
|
Materials, supplies and other |
|
|
1,220 |
|
|
|
|
1,017 |
|
|
|
|
|
|
|
|
Total inventories |
|
|
6,854 |
|
|
|
|
5,310 |
|
Prepaid expenses and other current assets |
|
|
4,200 |
|
|
|
|
3,527 |
|
|
|
|
|
|
Total Current Assets |
|
|
36,470 |
|
|
|
|
39,377 |
|
Long-term receivables, net |
|
|
2,413 |
|
|
|
|
2,194 |
|
Investments and advances |
|
|
20,920 |
|
|
|
|
20,477 |
|
Properties, plant and equipment, at cost |
|
|
173,299 |
|
|
|
|
154,084 |
|
Less: Accumulated depreciation, depletion and amortization |
|
|
81,519 |
|
|
|
|
75,474 |
|
|
|
|
|
|
|
|
Properties, plant and equipment, net |
|
|
91,780 |
|
|
|
|
78,610 |
|
Deferred charges and other assets |
|
|
4,711 |
|
|
|
|
3,491 |
|
Goodwill |
|
|
4,619 |
|
|
|
|
4,637 |
|
Assets held for sale |
|
|
252 |
|
|
|
|
|
|
|
|
|
|
|
Total Assets |
|
$ |
161,165 |
|
|
|
$ |
148,786 |
|
|
|
|
|
|
Liabilities and Stockholders Equity |
|
|
|
|
|
|
|
|
|
Short-term debt |
|
$ |
2,818 |
|
|
|
$ |
1,162 |
|
Accounts payable |
|
|
16,580 |
|
|
|
|
21,756 |
|
Accrued liabilities |
|
|
8,077 |
|
|
|
|
5,275 |
|
Federal and other taxes on income |
|
|
3,079 |
|
|
|
|
3,972 |
|
Other taxes payable |
|
|
1,469 |
|
|
|
|
1,633 |
|
|
|
|
|
|
Total Current Liabilities |
|
|
32,023 |
|
|
|
|
33,798 |
|
Long-term debt |
|
|
5,742 |
|
|
|
|
5,664 |
|
Capital lease obligations |
|
|
341 |
|
|
|
|
406 |
|
Deferred credits and other noncurrent obligations |
|
|
17,678 |
|
|
|
|
15,007 |
|
Noncurrent deferred income taxes |
|
|
11,539 |
|
|
|
|
12,170 |
|
Reserves for employee benefit plans |
|
|
6,725 |
|
|
|
|
4,449 |
|
Minority interests |
|
|
469 |
|
|
|
|
204 |
|
|
|
|
|
|
Total Liabilities |
|
|
74,517 |
|
|
|
|
71,698 |
|
|
|
|
|
|
Preferred stock (authorized 100,000,000 shares, $1.00 par value; none issued) |
|
|
|
|
|
|
|
|
|
Common stock (authorized 6,000,000,000 shares at December 31, 2008, and 4,000,000,000 at
December 31, 2007; $0.75 par value; 2,442,676,580 shares issued at December 31, 2008 and 2007) |
|
|
1,832 |
|
|
|
|
1,832 |
|
Capital in excess of par value |
|
|
14,448 |
|
|
|
|
14,289 |
|
Retained earnings |
|
|
101,102 |
|
|
|
|
82,329 |
|
Notes receivable key employees |
|
|
|
|
|
|
|
(1 |
) |
Accumulated other comprehensive loss |
|
|
(3,924 |
) |
|
|
|
(2,015 |
) |
Deferred compensation and benefit plan trust |
|
|
(434 |
) |
|
|
|
(454 |
) |
Treasury stock, at cost (2008 438,444,795 shares; 2007 352,242,618 shares) |
|
|
(26,376 |
) |
|
|
|
(18,892 |
) |
|
|
|
|
|
Total Stockholders Equity |
|
|
86,648 |
|
|
|
|
77,088 |
|
|
|
|
|
|
Total Liabilities and Stockholders Equity |
|
$ |
161,165 |
|
|
|
$ |
148,786 |
|
|
|
|
|
|
See accompanying Notes to the Consolidated Financial Statements.
FS-29
Consolidated Statement of Cash Flows
Millions of dollars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31 |
|
|
|
2008 |
|
|
|
2007 |
|
|
2006 |
|
|
|
|
|
|
Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
23,931 |
|
|
|
$ |
18,688 |
|
|
$ |
17,138 |
|
Adjustments |
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
9,528 |
|
|
|
|
8,708 |
|
|
|
7,506 |
|
Dry hole expense |
|
|
375 |
|
|
|
|
507 |
|
|
|
520 |
|
Distributions less than income from equity affiliates |
|
|
(440 |
) |
|
|
|
(1,439 |
) |
|
|
(979 |
) |
Net before-tax gains on asset retirements and sales |
|
|
(1,358 |
) |
|
|
|
(2,315 |
) |
|
|
(229 |
) |
Net foreign currency effects |
|
|
(355 |
) |
|
|
|
378 |
|
|
|
259 |
|
Deferred income tax provision |
|
|
598 |
|
|
|
|
261 |
|
|
|
614 |
|
Net (increase) decrease in operating working capital |
|
|
(1,673 |
) |
|
|
|
685 |
|
|
|
1,044 |
|
Minority interest in net income |
|
|
100 |
|
|
|
|
107 |
|
|
|
70 |
|
Increase in long-term receivables |
|
|
(161 |
) |
|
|
|
(82 |
) |
|
|
(900 |
) |
(Increase) decrease in other deferred charges |
|
|
(84 |
) |
|
|
|
(530 |
) |
|
|
232 |
|
Cash contributions to employee pension plans |
|
|
(839 |
) |
|
|
|
(317 |
) |
|
|
(449 |
) |
Other |
|
|
10 |
|
|
|
|
326 |
|
|
|
(503 |
) |
|
|
|
|
|
Net Cash Provided by Operating Activities |
|
|
29,632 |
|
|
|
|
24,977 |
|
|
|
24,323 |
|
|
|
|
|
|
Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(19,666 |
) |
|
|
|
(16,678 |
) |
|
|
(13,813 |
) |
Repayment of loans by equity affiliates |
|
|
179 |
|
|
|
|
21 |
|
|
|
463 |
|
Proceeds from asset sales |
|
|
1,491 |
|
|
|
|
3,338 |
|
|
|
989 |
|
Net sales of marketable securities |
|
|
483 |
|
|
|
|
185 |
|
|
|
142 |
|
Net sales (purchases) of other short-term investments |
|
|
432 |
|
|
|
|
(799 |
) |
|
|
|
|
|
|
|
|
|
Net Cash Used for Investing Activities |
|
|
(17,081 |
) |
|
|
|
(13,933 |
) |
|
|
(12,219 |
) |
|
|
|
|
|
Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net borrowings (payments) of short-term obligations |
|
|
2,647 |
|
|
|
|
(345 |
) |
|
|
(677 |
) |
Repayments of long-term debt and other financing obligations |
|
|
(965 |
) |
|
|
|
(3,343 |
) |
|
|
(2,224 |
) |
Proceeds from issuances of long-term debt |
|
|
|
|
|
|
|
650 |
|
|
|
|
|
Cash dividends common stock |
|
|
(5,162 |
) |
|
|
|
(4,791 |
) |
|
|
(4,396 |
) |
Dividends paid to minority interests |
|
|
(99 |
) |
|
|
|
(77 |
) |
|
|
(60 |
) |
Net purchases of treasury shares |
|
|
(6,821 |
) |
|
|
|
(6,389 |
) |
|
|
(4,491 |
) |
|
|
|
|
|
Net Cash Used for Financing Activities |
|
|
(10,400 |
) |
|
|
|
(14,295 |
) |
|
|
(11,848 |
) |
|
|
|
|
|
Effect of Exchange Rate Changes
on Cash and Cash Equivalents |
|
|
(166 |
) |
|
|
|
120 |
|
|
|
194 |
|
|
|
|
|
|
Net Change in Cash and Cash Equivalents |
|
|
1,985 |
|
|
|
|
(3,131 |
) |
|
|
450 |
|
Cash and Cash Equivalents at January 1 |
|
|
7,362 |
|
|
|
|
10,493 |
|
|
|
10,043 |
|
|
|
|
|
|
Cash and Cash Equivalents at December 31 |
|
$ |
9,347 |
|
|
|
$ |
7,362 |
|
|
$ |
10,493 |
|
|
|
|
|
|
See accompanying Notes to the Consolidated Financial Statements.
FS-30
Consolidated Statement of Stockholders Equity
Shares in thousands; amounts in millions of dollars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
|
|
2007 |
|
|
2006 |
|
|
|
Shares |
|
|
Amount |
|
|
|
Shares |
|
|
Amount |
|
|
Shares |
|
|
Amount |
|
|
|
|
|
|
Preferred Stock |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
$ |
|
|
|
|
|
|
|
$ |
|
|
|
|
|
|
|
Common Stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1 |
|
|
2,442,677 |
|
|
$ |
1,832 |
|
|
|
|
2,442,677 |
|
|
$ |
1,832 |
|
|
|
2,442,677 |
|
|
$ |
1,832 |
|
Balance at December 31 |
|
|
2,442,677 |
|
|
$ |
1,832 |
|
|
|
|
2,442,677 |
|
|
$ |
1,832 |
|
|
|
2,442,677 |
|
|
$ |
1,832 |
|
|
|
|
|
|
Capital in Excess of Par |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1 |
|
|
|
|
|
$ |
14,289 |
|
|
|
|
|
|
|
$ |
14,126 |
|
|
|
|
|
|
$ |
13,894 |
|
Treasury stock transactions |
|
|
|
|
|
|
159 |
|
|
|
|
|
|
|
|
163 |
|
|
|
|
|
|
|
232 |
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31 |
|
|
|
|
|
$ |
14,448 |
|
|
|
|
|
|
|
$ |
14,289 |
|
|
|
|
|
|
$ |
14,126 |
|
|
|
|
|
|
Retained Earnings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1 |
|
|
|
|
|
$ |
82,329 |
|
|
|
|
|
|
|
$ |
68,464 |
|
|
|
|
|
|
$ |
55,738 |
|
Net income |
|
|
|
|
|
|
23,931 |
|
|
|
|
|
|
|
|
18,688 |
|
|
|
|
|
|
|
17,138 |
|
Cash dividends on common stock |
|
|
|
|
|
|
(5,162 |
) |
|
|
|
|
|
|
|
(4,791 |
) |
|
|
|
|
|
|
(4,396 |
) |
Adoption of EITF 04-6, Accounting for Stripping
Costs Incurred during Production in the
Mining Industry |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(19 |
) |
Adoption of FIN 48, Accounting for Uncertainty
in Income Taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(35 |
) |
|
|
|
|
|
|
|
|
Tax benefit from dividends paid on
unallocated ESOP shares and other |
|
|
|
|
|
|
4 |
|
|
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31 |
|
|
|
|
|
$ |
101,102 |
|
|
|
|
|
|
|
$ |
82,329 |
|
|
|
|
|
|
$ |
68,464 |
|
|
|
|
|
|
Notes Receivable Key Employees |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
$ |
(1 |
) |
|
|
|
|
|
$ |
(2 |
) |
|
|
|
|
|
Accumulated Other Comprehensive Loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|