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(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification Number)
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code
(925) 842-1000
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Name of Each Exchange
on Which Registered
Common
stock, par value $.75 per share
New
York Stock Exchange, Inc.
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act.
Yes þ No o
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act.
Yes o No þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days.
Yes þ No o
Indicate by check mark whether the registrant has submitted
electronically and posted on its corporate Web site, if any,
every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of
Regulation S-T
(§ 232.405 of this chapter) during the preceding
12 months (or for such shorter period that the registrant
was required to submit and post such
files). Yes þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
(§ 229.405 of this chapter) is not contained herein,
and will not be contained, to the best of registrant’s
knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this
Form 10-K
or any amendment to this
Form 10-K. 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):
Large
accelerated filer þ
Accelerated filer o
Non-accelerated filer o
(Do not check if a smaller
reporting company)
Smaller reporting company o
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the
Act). Yes o No þ
Aggregate market value of the voting and non-voting common
equity held by non-affiliates computed by reference to the price
at which the common equity was last sold, or the average bid and
asked price of such common equity, as of the last business day
of the registrant’s most recently completed second fiscal
quarter — $132,865,210,015 (As of June 30, 2009)
Number of Shares of Common Stock outstanding as of
February 19, 2010 — 2,008,352,638
Notice of the 2010 Annual Meeting and 2010 Proxy Statement, to
be filed pursuant to
Rule 14a-6(b)
under the Securities Exchange Act of 1934, in connection with
the company’s 2010 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 Chevron’s operations that are based on
management’s current expectations, estimates and
projections about the petroleum, chemicals and other
energy-related industries. Words such as
“anticipates,”“expects,”“intends,”“plans,”“targets,”“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 company’s control and are difficult to predict.
Therefore, actual outcomes and results may differ materially
from what is expressed or forecasted in such forward-looking
statements. The reader should not place undue reliance on these
forward-looking statements, which speak only as of the date of
this report. Unless legally required, Chevron undertakes no
obligation to update publicly any forward-looking statements,
whether as a result of new information, future events or
otherwise.
Among the important factors that could cause actual results to
differ materially from those in the forward-looking statements
are: changing crude-oil and natural-gas prices; changing
refining, marketing and 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 company’s
joint-venture partners to fund their share of operations and
development activities; the potential failure to achieve
expected net production from existing and future crude-oil and
natural-gas development projects; potential delays in the
development, construction or
start-up of
planned projects; the potential disruption or interruption of
the company’s net production or manufacturing facilities or
delivery/transportation networks due to war, accidents,
political events, civil unrest, severe weather or crude-oil
production quotas that might be imposed by the Organization of
Petroleum Exporting Countries; the potential liability for
remedial actions or assessments under existing or future
environmental regulations and litigation; significant investment
or product changes under existing or future environmental
statutes, regulations and litigation; the potential liability
resulting from other pending or future litigation; the
company’s future acquisition or disposition of assets and
gains and losses from asset dispositions or impairments;
government-mandated sales, divestitures, recapitalizations,
industry-specific taxes, changes in fiscal terms or restrictions
on scope of company operations; foreign-currency movements
compared with the U.S. dollar; the effects of changed
accounting rules under generally accepted accounting principles
promulgated by
rule-setting
bodies; and the factors set forth under the heading “Risk
Factors” on pages 30 through 32 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.
Chevron Corporation,* a Delaware corporation, manages its
investments in subsidiaries and affiliates and provides
administrative, financial, management and technology support to
U.S. and international subsidiaries that engage in fully
integrated petroleum operations, chemicals operations, mining
operations, power generation and energy services. 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 and
converting natural gas 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. Chemicals operations include the manufacture and marketing
of commodity petrochemicals, plastics for industrial uses, and
fuel and lubricant oil additives.
A list of the company’s major subsidiaries is presented on
pages E-23
and E-24. As
of December 31, 2009, Chevron had approximately
64,000 employees (including about 4,000 service station
employees). Approximately 31,500 employees (including about
3,500 service station employees), or 49 percent, were
employed in U.S. operations.
Overview
of Petroleum Industry
Petroleum industry operations and profitability are influenced
by many factors, 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,
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
world’s 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 of changes in the company’s
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 and national petroleum companies in the
sale or acquisition of various goods or services in many
national and international markets.
Operating
Environment
Refer to pages FS-2 through FS-9 of this
Form 10-K
in Management’s Discussion and Analysis of Financial
Condition and Results of Operations for a discussion of the
company’s current business environment and outlook.
* 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.
Chevron’s primary objective is to create stockholder value
and achieve sustained financial returns from its operations that
will enable it to outperform its competitors. In the upstream,
the company’s strategies are to grow profitably in core
areas, build new legacy positions and commercialize the
company’s equity natural-gas resource base while growing a
high-impact global gas business. In the downstream, the
strategies are to improve returns and selectively grow, with a
focus on integrated value creation. The company also continues
to invest in renewable-energy technologies, with an objective of
capturing profitable positions.
(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, 2009, and assets as
of the end of 2009 and 2008 — for the United States
and the company’s international geographic
areas — are in Note 11 to the Consolidated
Financial Statements beginning on
page FS-40.
Similar comparative data for the company’s investments in
and income from equity affiliates and property, plant and
equipment are in Notes 12 and 13 on pages FS-43 through
FS-45.
Total expenditures for 2009 were $22.2 billion, including
$1.6 billion for the company’s share of
equity-affiliate expenditures. In 2008 and 2007, expenditures
were $22.8 billion and $20 billion, respectively,
including the company’s share of affiliates’
expenditures of $2.3 billion in both periods.
Of the $22.2 billion in expenditures for 2009, about
three-fourths, or $17.1 billion, was related to upstream
activities. Approximately the same percentage was also expended
for upstream operations in 2008 and 2007. International upstream
accounted for about 80 percent of the worldwide upstream
investment in 2009 and about 70 percent in 2008 and 2007,
reflecting the company’s continuing focus on opportunities
available outside the United States.
In 2010, the company estimates capital and exploratory
expenditures will be $21.6 billion, including
$1.6 billion of spending by affiliates. About
80 percent of the total, or $17.3 billion, is budgeted
for exploration and production activities, with
$13.2 billion of that amount for projects outside the
United States.
Refer also to a discussion of the company’s capital and
exploratory expenditures on
page FS-12.
4 Volumes
represent Chevron’s share of production by affiliates,
including Tengizchevroil (TCO) in Kazakhstan and Petroboscan,
Petroindependiente and Petropiar in Venezuela.
5 Volumes
include natural gas consumed in operations of 521 million
and 520 million cubic feet per day in 2009 and 2008,
respectively.
Worldwide oil-equivalent production, including volumes from oil
sands (refer to footnote 2 above), was 2.7 million barrels
per day, up about 7 percent from 2008. The increase was
mostly associated with the
start-up of
the Blind Faith and Tahiti fields in the U.S. Gulf of
Mexico in late 2008 and the second quarter 2009, respectively,
the commencement of operations in the third quarter 2008 at the
Agbami Field in Nigeria, and the expansion at Tengiz in
Kazakhstan. Refer to the “Results of Operations”
section beginning on
page FS-6
for a detailed discussion of the factors explaining the
2007-2009
changes in production for crude oil and natural gas liquids, and
natural gas.
The company estimates that its average worldwide oil-equivalent
production in 2010 will be approximately 2.73 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 company’s
major crude-oil and natural-gas development projects.
Refer to Table IV on
page FS-69
for the company’s average sales price per barrel of crude
oil, condensate and natural gas liquids and per thousand cubic
feet of natural gas produced and the average production cost per
oil-equivalent barrel for 2009, 2008 and 2007.
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 company’s
fractional interests in gross wells.
3
Canadian synthetic oil is not
produced through wells and therefore is not presented in the
table above.
Refer to Table V beginning on
page FS-69
for a tabulation of the company’s proved net crude-oil and
natural-gas reserves by geographic area, at the beginning of
2007 and each year-end from 2007 through 2009, and an
accompanying discussion of major changes to proved reserves by
geographic area for the three-year period ending
December 31, 2009. During 2009, the company provided
crude-oil and natural-gas reserves estimates for 2008 to the
Department of Energy, Energy Information Administration (EIA)
that agree with the 2008 reserve volumes in Table V. This
reporting fulfilled the requirement that such estimates be
consistent with, and not differ more than 5 percent from,
the information furnished to the Securities and Exchange
Commission (SEC) in the company’s 2008 Annual Report on
Form 10-K.
During 2010, the company will file estimates of crude-oil and
natural-gas reserves with the Department of Energy, EIA,
consistent with the 2009 reserve data reported in Table V.
The net proved-reserve balances at the end of each of the three
years 2007 through 2009 are shown in the table below:
Net
Proved Reserves at December 31
2009
2008
2007
Liquids* — Millions of barrels
Consolidated Companies
4,610
4,735
4,665
Affiliated Companies
2,363
2,615
2,422
Natural Gas — Billions of cubic feet
Consolidated Companies
22,153
19,022
19,137
Affiliated Companies
3,896
4,053
3,003
Total Oil-Equivalent — Millions of barrels
Consolidated Companies
8,303
7,905
7,855
Affiliated Companies
3,012
3,291
2,922
*
Crude oil, condensate and natural
gas liquids. 2009 liquids amount for consolidated companies
includes 460 million barrels of synthetic oil produced from
oil sands mining operations in Canada in accordance with the
adoption of the new SEC definition of oil and gas producing
activity.
At December 31, 2009, the company owned or had under lease
or similar agreements undeveloped and developed crude-oil and
natural-gas properties located throughout the world. The
geographical distribution of the company’s acreage is shown
in the following table.
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 company’s fractional interests in gross acreage.
2
Table does not include mining
acreage associated with the synthetic oil production in Canada.
At year-end 2009, undeveloped gross and net acreage totaled 235
and 31, respectively. Developed gross and net acreage totaled 35
and 7, respectively. Developed acreage is acreage associated
with productive mines. Undeveloped acreage is acreage on which
mines have not been established and that may contain undeveloped
proved reserves.
3
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 2010,
2011 and 2012 if production is not established by certain
required dates are 13,526, 9,784 and 3,662, respectively.
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 has no fixed and determinable
delivery commitments to third-parties or affiliates.
Outside the United States, the company is contractually
committed to deliver to third parties a total of
821 billion cubic feet of natural gas from 2010 through
2012 from Australia, 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 company’s
proved developed reserves in Australia, Colombia, Denmark and
the Philippines.
Refer to Table I on
page FS-64
for details associated with the company’s development
expenditures and costs of proved property acquisitions for 2009,
2008 and 2007.
The table below summarizes the company’s net interest in
productive and dry development wells completed in each of the
past three years and the status of the company’s
development wells drilling at December 31, 2009. 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
Completed1,2
at
12/31/093
2009
2008
2007
Gross
Net
Prod.
Dry
Prod.
Dry
Prod.
Dry
United States
47
22
582
3
846
4
875
5
Africa
6
2
40
—
33
—
43
—
Asia
38
22
580
—
665
1
597
—
Other
11
4
43
—
41
—
52
—
Total Consolidated Companies
102
50
1,245
3
1,585
5
1,567
5
Equity in Affiliates
1
—
6
—
16
—
3
—
Total Including Affiliates
103
50
1,251
3
1,601
5
1,570
5
1
2008 and 2007 conformed to 2009
geographic 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.
3
Represents wells in the process of
drilling, including wells for which drilling was not completed
and which were temporarily suspended at the end of 2009. 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 company’s fractional interests in gross wells.
The following table summarizes the company’s net interests
in productive and dry exploratory wells completed in each of the
last three years and the number of exploratory wells drilling at
December 31, 2009. “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
12/31/093
2009
2008
2007
Gross
Net
Prod.
Dry
Prod.
Dry
Prod.
Dry
United States
3
1
4
5
8
2
4
8
Africa
6
2
2
1
2
1
6
2
Asia
1
—
9
1
9
2
13
9
Other
4
3
5
4
44
2
43
6
Total Consolidated Companies
14
6
20
11
63
7
66
25
Equity in Affiliates
—
—
—
—
—
—
—
—
Total Including Affiliates
14
6
20
11
63
7
66
25
1
2008 and 2007 conformed to 2009
geographic 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 2009. 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 company’s
fractional interests in gross wells.
Refer to Table I on
page FS-64
for detail of the company’s exploration expenditures and
costs of unproved property acquisitions for 2009, 2008 and 2007.
Chevron’s 2009 key upstream activities, some of which are
also discussed in Management’s Discussion and Analysis of
Financial Condition and Results of Operations beginning on
page FS-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-42.
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 company’s share of costs for projects that are less
than wholly owned.
Chevron has production and exploration activities in most of the
world’s major hydrocarbon basins. The company’s
upstream strategy is to grow profitably in core areas, build new
legacy positions and commercialize the company’s equity
natural-gas resource base while growing a high-impact global gas
business. The map at left indicates Chevron’s primary areas
of production and exploration.
a)
United
States
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 2009 was
717,000 barrels per day.
In California, the company has significant production in the
San Joaquin Valley. In 2009, average net oil-equivalent
production was 211,000 barrels per day, composed of
191,000 barrels of crude oil, 91 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).
Average net oil-equivalent production during 2009 for the
company’s combined interests in the Gulf of Mexico shelf
and deepwater areas, and the onshore fields in the region was
243,000 barrels per day. The daily oil-equivalent
production comprised 149,000 barrels of crude oil,
484 million cubic feet of natural gas and
14,000 barrels of natural gas liquids.
During 2009, Chevron was engaged in various development and exploration activities in the deepwater Gulf of Mexico. The 75 percent-owned and operated Blind Faith development, which achieved first oil in the fourth quarter 2008, reached maximum total production of 70,000 barrels per day of oil-equivalent in 2009. Blind Faith has an estimated production life of 20 years.
At the 58 percent-owned and operated Tahiti Field, first oil was achieved in the second quarter 2009. Maximum total production of 135,000 barrels per day of oil-equivalent was achieved in the third quarter 2009. A second development phase is under evaluation, including additional development drilling and a probable waterflood, with a final investment decision planned formid-2010. The waterflood includes water injection topsides
equipment, subsea equipment and water injection wells. Tahiti
has an estimated production life of 30 years. As of the end
of 2009, proved reserves had been recognized for the first
development phase of the Tahiti Field.
The company is participating in the ultra-deepwater Perdido
Regional Development. The project encompasses the installation
of a producing host facility to service multiple fields,
including Chevron’s 33.3 percent-owned Great White,
60 percent-owned Silvertip and 57.5 percent-owned
Tobago. Chevron has a 37.5 percent interest in the Perdido
Regional Host. All of these fields and the production facility
are partner-operated. Activities during 2009 included
installation of the topsides on the spar, installation of
umbilicals,
hook-up and
commissioning of the facility systems, and ongoing development
drilling. First oil is expected in the first half of 2010, with
the facility designed to handle 130,000 barrels of
oil-equivalent per day. The project has an expected life of
approximately 25 years. Proved reserves have been
recognized for the project.
The company has a 60 percent-owned and operated interest in
Big Foot. Two successful appraisal wells have been drilled, the
most recent in the first quarter 2009. The company also acquired
the rights to an adjacent block during 2009. The project entered
front-end engineering and design (FEED) in October 2009 and a
final investment decision is expected in late 2010. Total
maximum production from the project is expected to be
63,000 barrels of oil-equivalent per day. At the end of
2009, proved reserves had not been recognized.
The Caesar and Tonga partnerships for properties located in a
number of blocks in the Green Canyon area have formed a unit
agreement for the area, with Chevron having a 20.3 percent
nonoperated working interest. A final investment decision on the
joint Caesar-Tonga project was made in the first quarter 2009.
Development plans include four wells and a subsea tie-back to a
nearby third-party production facility. Two development
sidetracks were completed during the year. Proved reserves have
been recognized for the project and first oil is expected in
2011.
The Jack and St. Malo fields are located within 25 miles of
each other and are being considered for joint development.
Chevron has a 50 percent-owned interest in Jack and a
51 percent-owned interest in St. Malo, following the
anticipated acquisition of an additional 9.8 percent equity
interest in St. Malo in March 2010. Both fields are company
operated. The project entered FEED in May 2009 and a final
investment decision is expected in late 2010. The facility is
planned to have an initial design capacity of
150,000 barrels of oil-equivalent per day and
start-up is
expected in 2014. At the end of 2009, proved reserves had not
been recognized.
Deepwater exploration activities in 2009 and early 2010 included
participation in 10 exploratory wells — five wildcat,
three appraisal and two delineation. Exploratory work included
the following:
•
Buckskin — 55 percent-owned and operated. A
successful wildcat discovery was announced in February 2009. The
first appraisal well is scheduled to begin drilling in the
second quarter 2010.
•
Knotty Head — 25 percent nonoperated working
interest. The first appraisal well began drilling in October
2009 at this 2005 discovery.
•
Puma — 21.8 percent nonoperated working interest.
An appraisal well completed drilling in early 2009. Leases were
relinquished in mid-2009.
•
Tubular Bells — 30 percent nonoperated working
interest. Studies to screen and evaluate future development
alternatives were continuing at the end of 2009.
At the end of 2009, the company had not 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
contracted capacity of 1 billion cubic feet per day at the
third-party Sabine Pass liquefied natural gas (LNG)
regasification terminal in Louisiana. The
20-year
capacity reservation agreement became effective in July 2009 and
enables import of natural gas for the North America market. In
September 2009, Chevron began to utilize a portion of the
reserved capacity under this agreement.
Chevron has also contracted 1.6 billion cubic feet per day
of capacity in a third-party pipeline system connecting the
Sabine Pass LNG terminal to the natural-gas pipeline grid. The
new pipeline, which was placed in service in July 2009, provides
access to two major salt dome storage fields and 10 major
interstate pipeline systems, including an interconnect with
Chevron’s Sabine Pipeline, which connects to the Henry Hub.
An interconnect to Chevron’s Bridgeline Pipeline is
scheduled to be completed in the third quarter 2010. The Henry
Hub interconnects to nine interstate and four intrastate
pipelines and is the pricing point for natural gas futures
contracts traded on the New York Mercantile Exchange.
Outside California and the Gulf of Mexico, the company manages
operations across the mid-continental United States and Alaska.
During 2009, the company’s U.S. production outside
California and the Gulf of Mexico averaged 263,000 net
oil-equivalent barrels per day, composed of 94,000 barrels
of crude oil, 824 million cubic feet of natural gas and
31,000 barrels of natural gas liquids.
In the Piceance Basin in northwestern Colorado, additional
production came on line in September 2009 from the
company’s 100 percent-owned and operated natural-gas
development. Development drilling, which began in 2007,
surpassed 190 wells in 2009, with 81 completed wells
available to supply natural gas to the central processing
facility. Construction of compression and dehydration facilities
to produce 65 million cubic feet per day of natural gas was
completed in the third quarter 2009. Future work is expected to
be completed in multiple stages. The full development plan
includes drilling more than 2,000 wells from multi-well
pads over the next 30 to 40 years. Proved reserves for
subsequent stages of the project had not been recognized at
year-end 2009.
In Africa, the company is engaged in exploration and production
activities in Angola, Chad, Democratic Republic of the Congo,
Nigeria and Republic of the Congo. Net oil-equivalent production
in Africa averaged 433,000 barrels per day during 2009.
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 2009 averaged 150,000 barrels of oil-equivalent per day.
The company operates the 39.2 percent-owned Block 0, which averaged 105,000 barrels per day of net liquids production in 2009. The Block 0 concession extends through 2030.
Initial production from the northern portion of the Mafumeira Field in Block 0 occurred in July 2009, and total maximum crude-oil production of 42,000 barrels per day was achieved in first quarter 2010. Front-end engineering and design (FEED) started in January 2010 on Mafumeira Sul, a project to develop the southern portion of the Mafumeira Field. A final investment decision is expected in 2011. Maximum production from
Mafumeira Sul is expected to be 95,000 barrels of crude oil per day. At year-end 2009, no proved reserves had been recognized for this project.
In the Greater Vanza/Longui Area of Block 0, development
concept selection was under way and continued into 2010. FEED is
planned for 2011. FEED activities continued on the south
extension of the N’Dola Field development. At year-end
2009, no proved reserves had been recognized for these projects.
Four gas management projects in Block 0 are expected to
eliminate routine flaring of natural gas by injecting excess
natural gas into various reservoirs. The Takula Flare and Relief
Modification Project and the Cabinda Gas Plant Project entered
service in June 2009 and December 2009, respectively. These
projects are expected to reduce flaring by up to 60 million
cubic feet per day. Work continued on the Nemba Enhanced
Secondary Recovery and Flare Reduction Project and the Malongo
Flare and Relief Modification Project, which are scheduled for
start-up in
the fourth quarter 2010 and in 2011, respectively.
Also in Block 0, a successful two-well exploration and
appraisal program was completed. The exploration well was
completed in March 2009, and the appraisal well was completed in
May 2009. Drilling began on another exploration well in November
2009 and was completed in the first quarter 2010. The results
are under evaluation.
In the 31 percent-owned Block 14, net production in
2009 averaged 33,000 barrels of liquids per day from the
Benguela Belize — Lobito Tomboco development and the
Kuito, Tombua and Landana fields. Development and production
rights for the various fields in Block 14 expire between
2027 and 2029.
Development of the Tombua and Landana fields continued in 2009.
First production occurred in August 2009 from new production
facilities that were installed in late 2008. Proved developed
reserves were recognized at start of production. Development
drilling is expected to continue, with maximum total daily
production of 100,000 barrels of crude oil anticipated in
2011.
During 2009, studies to evaluate development alternatives for
the Lucapa Field continued. The project is expected to enter
FEED in the fourth quarter 2010. A successful appraisal well was
completed in the fourth quarter 2009 in the Malange area. As of
the end of 2009, development of the Negage Field was suspended
until cooperative arrangements between Angola and Democratic
Republic of the Congo could be finalized. At the end of 2009,
proved reserves had not been recognized for these projects.
The 39.2 percent-owned and operated Malongo Terminal Oil
Export project was completed in November 2009. The new export
system more than doubled export capacity from the area, which
includes Blocks 0 and 14. In the 20 percent-owned
Block 2 and the 16.3 percent-owned FST areas, combined
production during 2009 averaged 3,000 barrels of net
liquids per day.
Equity Affiliate Operations: In addition to the
exploration and producing activities in Angola, Chevron has a
36.4 percent ownership interest in the Angola LNG affiliate
that began construction in early 2008 of an onshore natural gas
liquefaction plant located in Soyo, Angola. The plant is
designed to process more than 1 billion cubic feet of
natural gas per day. Construction continued on schedule during
2009 with plant
start-up
scheduled for 2012. The life of the LNG plant is estimated to be
in excess of 20 years. Proved reserves have been recognized
for the producing operations associated with this project.
Angola — Republic of the Congo Joint Development
Area: Chevron operates and holds a 31.3 percent
interest in the Lianzi Development Area located between Angola
and Republic of the Congo. In late 2008, the development project
entered FEED, which continued through 2009. No proved reserves
have been recognized for Lianzi.
Republic of the Congo: Chevron has a
31.5 percent nonoperated working interest in the Nkossa,
Nsoko and Moho-Bilondo exploitation permits and a
29.3 percent nonoperated working interest in the Kitina
exploitation permit, all of which are offshore. The development
and production rights for Nkossa, Nsoko and Kitina expire in
2027, 2018 and 2019, respectively. Net production from the
Republic of the Congo fields averaged 21,000 barrels of
oil-equivalent per day in 2009.
In May 2009, a successful exploration well was drilled in the
Moho-Bilondo exploitation permit area. Development alternatives
were being evaluated during 2009. The Moho-Bilondo subsea
development project, which started production in 2008, is
expected to achieve maximum total production of
90,000 barrels of crude oil per day in the third quarter
2010. Chevron’s development and production rights for
Moho-Bilondo expire in 2030.
Democratic Republic of the Congo: Chevron has a
17.7 percent nonoperated working interest in an offshore
concession. Daily net production in 2009 averaged
3,000 barrels of oil-equivalent.
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 an approximate
21 percent interest in two affiliates that own the
pipeline. Average daily net production from the Chad fields in
2009 was 27,000 barrels of oil-equivalent. In September
2009, first production was achieved at the Timbre Field in the
Doba area. The Chad producing operations are conducted under a
concession that expires in 2030.
Libya: After an unsuccessful exploration well was
completed, the company elected to relinquish its
100 percent interest in the onshore Block 177
exploration license in the fourth quarter 2009.
Nigeria: Chevron holds a 40 percent interest in 13 concessions in the onshore and near-offshore region of the Niger Delta. The company operates under a joint-venture arrangement in this region with the Nigerian National Petroleum Corporation, which owns a 60 percent interest. The company also owns varying interests in deepwater offshore blocks. In 2009, the company’s net oil-equivalent production in Nigeria averaged 232,000 barrels per day, composed of 225,000 barrels of liquids and 48 million cubic feet of natural gas.
In deepwater Oil Mining Lease (OML) 127 and OML 128, the 68.2 percent-owned and operated Agbami Field reached maximum total liquids production of 250,000 barrels per day in August 2009, following
completion of development drilling. In December 2009, a subsequent 10-well development program was initiated and is expected to offset field decline. The leases that contain the Agbami Field expire in 2023 and 2024.
Also in the deepwater area, the Aparo Field in OML 132 and OML 140 and the 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 2009 on a final unitization agreement between Chevron and
partners in OML 118. At the end of 2009, no proved reserves were
recognized for this project.
Chevron operates and holds a 95 percent interest in the
deepwater Nsiko discovery on OML 140. Development activities
continued in 2009, with FEED expected to start after commercial
terms are resolved. At the end of 2009, 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 a floating
production, storage and offloading vessel. Development drilling
started in June 2009. Production
start-up is
scheduled for 2012, and maximum total production of
180,000 barrels of crude oil per day is expected to be
achieved within one year of
start-up.
Total costs for the project are estimated at $8.4 billion.
Usan has an estimated production life of 20 years. Proved
reserves have been recognized for this project.
Chevron participated in one successful deepwater exploration
well during 2009 in Oil Prospecting License (OPL) 223. The
company has a 30 percent nonoperated working interest in
the license. At the end of 2009, proved reserves had not been
recognized for the exploration project.
In the Niger Delta, construction on the Phase 3A expansion of
the Escravos Gas Plant (EGP) was completed in late 2009 and
start of production is expected in March 2010. EGP Phase 3A
scope includes offshore natural-gas gathering and compression
infrastructure and the addition of a second natural-gas
processing facility. The modifications are designed to 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. 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 2012. The engineering, procurement,
construction, and installation contract for the pipelines was
awarded and work commenced in late 2009. Proved reserves have
been recognized for these projects.
The 40 percent-owned and operated Onshore Asset Gas
Management project is designed to restore approximately
125 million cubic feet per day of natural-gas production
from certain onshore fields that have been shut in since 2003
due to civil unrest. Natural gas from these fields is sold in
the Nigerian domestic gas market. The main
on-site
construction contracts are expected to be awarded in the second
quarter 2010.
Refer to page 25 for a discussion of the planned
gas-to-liquids
facility at Escravos.
Equity Affiliate Operations: Chevron holds a
19.5 percent interest in the OKLNG Free Zone Enterprise
(OKLNG) affiliate, which will operate the Olokola LNG project.
OKLNG plans to build a multi-train natural-gas liquefaction
facility and marine terminal located northwest of Escravos. At
the end of 2009, timing of the final investment decision remains
uncertain. The company has not recognized proved reserves
associated with this project.
Refer to “Pipelines” under “Transportation
Operations” beginning on page 26 for a discussion of
the West African Gas Pipeline operations.
Major producing countries in Asia include Azerbaijan,
Bangladesh, Indonesia, Kazakhstan, the Partitioned Zone located
between Saudi Arabia and Kuwait, and Thailand. During 2009, net
oil-equivalent production averaged 1,044,000 barrels per
day in Asia.
Azerbaijan: Chevron holds a 10.3 percent nonoperated working interest in the Azerbaijan International Operating Company (AIOC), which produces crude oil in the Caspian Sea from the Azeri-Chirag-Gunashli (ACG) project. Chevron also has an 8.9 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 BTC operations.)
In 2009, the company’s daily net production from AIOC averaged 30,000 barrels of oil-equivalent. The final investment decision on the next development phase is expected in the first half 2010. 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 2009, Karachaganak net oil-equivalent production averaged 69,000 barrels per day, composed of 42,000 barrels of liquids and 161 million cubic feet of natural gas. In 2009, access to the Caspian Pipeline Consortium (CPC) and Atyrau-Samara (Russia) pipelines enabled approximately 184,000 barrels per day (33,000 net barrels) of Karachaganak liquids to be sold at world-market
prices. The remaining liquids were sold into Russian markets.
During 2009, work continued on a fourth train that is designed
to increase total export of processed liquids by
56,000 barrels per day. The fourth train is expected to
start-up in
2011.
During 2009, Chevron and its 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 project design and
achieving project milestones. Karachaganak operations are
conducted under a
40-year PSC
that expires in 2038.
Equity Affiliate Operations:The company
holds a 50 percent interest in Tengizchevroil (TCO), which
is operating and developing the Tengiz and Korolev crude-oil
fields, located in western Kazakhstan, under a
40-year
concession that expires in 2033. Chevron’s net
oil-equivalent production in 2009 from these fields averaged
274,000 barrels per day, composed of 226,000 barrels
of crude oil and natural gas liquids and 289 million cubic
feet of natural gas.
In 2009, TCO continued
ramp-up of
the Sour Gas Injection (SGI) and Second Generation Plant (SGP)
facilities. 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. TCO is evaluating
options for another expansion project based on SGI/SGP
technologies.
During 2009, the majority of TCO’s crude-oil production was
exported through the Caspian Pipeline Consortium (CPC) pipeline
that runs from Tengiz in Kazakhstan to tanker-loading facilities
at Novorossiysk on the Russian coast of the Black Sea. The
balance was shipped via other export routes, which 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.)
Turkey: Chevron holds a 25 percent nonoperated
working interest in the Silopi licenses in southeast Turkey,
which is on trend with production in Iraq’s northern Zagros
Fold Belt. An exploration well in the Lale prospect completed
drilling in the first quarter 2010, and is under evaluation.
Bangladesh: Chevron holds interests in three
operated PSCs covering onshore Blocks 12, 13 and 14 and
offshore Block 7. The company has a 98 percent
interest in Blocks 12, 13 and 14. Government approval of a
2009 farm-out in Block 7 was received in February 2010,
reducing the company’s interest from 88 percent to
43 percent. The farm-out was to GS Caltex, a 50
percent-owned affiliate of the company. Net oil-equivalent
production from these operations in 2009 averaged
66,000 barrels per day, composed of 387 million cubic
feet of natural gas and 2,000 barrels of liquids. In 2009,
a final investment decision was achieved after the government
approved the development of a compression project that is
expected to support additional production starting in 2012 from
the Bibiyana, Jalalabad and Moulavi Bazar natural-gas fields.
Proved reserves have been recognized for this project. The
government also approved an amendment to the PSC for
Blocks 13 and 14 that allows the company to acquire
additional
3-D seismic
over the Jalalabad Field. Also in 2009, the company acquired
seismic data on Block 7. Evaluation and data processing is
under way, and an exploration well is planned to be completed by
2011.
Cambodia: Chevron operates the
1.2 million-acre
(4,709 sq-km) Block A, located offshore in the Gulf of Thailand,
and expects to reduce its ownership to 30 percent pending
government approval of the farm-out that is anticipated in the
second quarter 2010. In 2009, commercial evaluation of the
prospects continued. The company was granted an extension for
the Block A exploration period to the third quarter 2010 in
exchange for the obligation to drill three exploration wells.
Information gained from the drilling program is expected to
provide improved definition of the resource in the block. Proved
reserves had not been recognized as of the end of 2009.
Myanmar: Chevron has a 28.3 percent nonoperated
working interest in a PSC for the production of natural gas from
the Yadana and Sein fields offshore in the Andaman Sea. The
company also has a 28.3 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
Thailand’s PTT Public Company Limited (PTT). The
company’s average net natural gas production in 2009 was
76 million cubic feet per day. During 2009, the platform
for a compression project was completed. Project
start-up is
expected in 2011.
Thailand: Chevron has operated and nonoperated working interests in several different offshore blocks. The company’s net oil-equivalent production in 2009 averaged 198,000 barrels per day, composed of 65,000 barrels of crude oil and condensate and 794 million cubic feet of natural gas. All of the company’s 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 eight operating areas, and Blocks 10 through 13 and B12/27 produce crude oil, condensate and natural
gas from 16 operating areas.
Chevron has a 16 percent nonoperated working interest in
Blocks 14A, 15A, 16A, G9/48 and G8/50, known collectively
as the Arthit Field.
During 2009, construction at the 69.8 percent-owned and
operated Platong Gas II project continued. The project is
designed to add 420 million cubic feet per day of
processing capacity in 2012. Proved reserves have been
recognized for this project. Concessions for Blocks 10
through 13 expire in 2022.
During 2009, 14 exploration wells were drilled in the Gulf of
Thailand, 13 were successful and one nonoperated well in the
Arthit Field was unsuccessful. Two
3-D seismic
surveys and geological studies for Block G4/50 were also
completed in 2009. At the end of 2009, proved reserves had not
been recognized for these activities. Three exploratory wells in
Block G4/50 are planned for the second quarter 2010. For Blocks
G6/50 and G7/50, one exploration well is scheduled in each block
for completion by the third quarter 2010. 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 42.4 percent interest in a PSC that
includes Blocks B and 48/95, and a 43.4 percent interest in
another PSC for Block 52/97. In August 2009, Chevron
reduced its ownership interest in a third operated PSC to
20 percent in Block B122 offshore eastern Vietnam. No
production occurred in these areas during 2009.
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, a floating storage
and offloading vessel, field pipelines and a central processing
platform. The project is expected to enter front-end engineering
and design (FEED) in the first quarter 2010, and a final
investment decision is expected in 2011. Maximum total
production is planned to be about 500 million cubic feet of
natural gas per day. At the end of 2009, proved reserves had not
been recognized for this project.
In conjunction with the Vietnam Gas Project, a
Petrovietnam-operated pipeline will be required to support the
offshore development. Chevron will have a 28.7 percent
interest in the pipeline, which is planned to transport natural
gas from the offshore development to customers in southern
Vietnam.
During the year, the company continued to analyze well results
and seismic processing from Block B and Block 52/97. In
Block 122,
2-D seismic
data processing and geologic studies were completed. An
exploration well is planned for 2011. Proved reserves had not
been recognized as of the end of 2009. Future activity in
Block 122 may be affected by an ongoing territorial
dispute between Vietnam and China.
China: Chevron has one operated and three nonoperated working interests in several areas. Net oil-equivalent production from the nonoperated areas in 2009 averaged 19,000 barrels per day, composed of 17,000 barrels of crude oil and condensate and 16 million cubic feet of natural gas.
The company holds a 49 percent-owned and 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. During 2009, general infrastructure for the plant site and well pads progressed. Development drilling and the construction and installation of additional
processing facilities and gathering systems are expected to start in 2010. Proved reserves have been recognized for this project. The PSC for Chuandongbei expires in 2038.
In the South China Sea, the company has nonoperated working interests of 32.7 percent in Blocks 16/08 and 16/19 located in the Pearl River Delta Mouth Basin, 24.5 percent in the QHD-32-6 Field in Bohai Bay, and 16.2 percent in the unitized and producing BZ 25-1 and BZ 19-4 crude-oil fields in Bohai Bay Block 11/19. In
November 2009, a storm damaged the floating production, storage
and offloading (FPSO) vessel utilized by the company’s
nonoperated assets in Block 11/19. Temporary and permanent
recovery options are under development and production is
expected to fully resume in 2012.
The joint development of the HZ25-3 and HZ25-1 crude-oil fields
in Block 16/19 continued through the end of 2009. First
production was delayed from the third quarter 2009 and is
expected to be fully restored in the fourth quarter 2010
following damage to the FPSO vessel caused by a typhoon that
struck the area in September 2009.
In 2009, Chevron relinquished its nonoperated working interest
in four exploration blocks in the Ordos Basin. Government
approval is expected in mid-2010.
Indonesia: Chevron’s 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 and
90 percent in the MFK (Mountain Front Kuantan) PSC. 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 inthe
East Java Sea Basin. Chevron’s interests in these PSCs
range from 25 percent to 40 percent.
The company’s net oil-equivalent production in 2009 from
all of its interests in Indonesia averaged 243,000 barrels
per day. The daily oil-equivalent rate comprised
199,000 barrels of liquids and 268 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 world’s largest steamflood
developments. The North Duri Development is divided into
multiple expansion areas. The first expansion in Area 12 started
steam injection in June 2009. Maximum total daily production
from Area 12 is estimated at 34,000 barrels of crude oil in
2012. A final investment decision regarding North Duri Area 13
is expected by year-end 2010. The Rokan PSC expires in 2021.
Chevron advanced its development plans for the Gendalo and Gehem
deepwater natural-gas fields located in the Kutei Basin. FEED
started in December 2009, with completion dependent upon
achieving project milestones and receipt of government
approvals. The Bangka deepwater natural-gas project was
progressed during the year under a revised, lower-cost
development plan. The project is expected to enter FEED in the
second quarter 2010. Under the terms of the PSCs for both
projects, the company’s 80 percent-owned and operated
interest is expected to be reduced to 72 percent in 2010
with the farm-in of an Indonesian company. At the end of 2009,
the company had not recognized proved reserves for either of
these projects.
Also in the Kutei Basin, first production at the Seturian Field
occurred in September 2009, which is providing natural gas to a
state-owned refinery. During 2009, evaluation of the
50 percent-owned and operated Sadewa project in the Kutei
Basin was suspended.
A drilling campaign continued through 2009 in South Natuna Sea
Block B to provide additional supply for long-term natural-gas
sales contracts with additional development drilling planned for
2010. The North Belut development project achieved first
production in November 2009. The South Belut development project
was under review during the year.
A two-well exploration program was conducted in the Central
Sumatra Basin in 2009. One commercial discovery was made in the
Rokan Block, and a second well in the Siak Block resulted in a
dry hole. Chevron’s working interests in two exploration
blocks in western Papua, West Papua I and West Papua III, are
expected to be reduced to 51 percent interests in 2010.
Completion of geological studies for those blocks was ongoing at
year-end 2009, and
2-D seismic
acquisition is planned for the second half 2010.
In West Java, Chevron operates the wholly owned Salak geothermal
field with a total power-generation 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 with a total
capacity of 259 megawatts. Chevron also operates a
95 percent-owned
300-megawatt
cogeneration facility in support of CPI’s operation in
North Duri, Sumatra.
Partitioned Zone (PZ): Chevron holds a 30-year 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 PZ between Saudi Arabia and Kuwait. Under the agreement, the company has rights to this 50 percent interest in the hydrocarbon resource and pays royalty and taxes on the associated volumes produced until 2039.
During 2009, the company’s average net oil-equivalent production was 105,000 barrels per day, composed of 101,000 barrels of crude oil and 21 million cubic feet of natural gas. In June 2009, steam injection was initiated in the second phase of a steamflood pilot project.
The pilot is an application of steam injection into a carbonate
reservoir and, if successful, could significantly increase heavy
oil recovery. The Central Gas Utilization Project was initiated
in 2009 to assess alternatives to increase natural-gas
utilization and eliminate routine flaring. A final investment
decision is expected in 2011. No reserves have been recognized
for these projects.
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 2009 averaged 27,000 barrels
per day, composed of 137 million cubic feet of natural gas
and 4,000 barrels of condensate. Chevron also develops and
produces geothermal resources under an agreement with the
Philippine government. Chevron expects to sign a new
25-year
contract with the government by the end of 2010 to operate the
steam fields, which supply geothermal resources to the 637
megawatt geothermal facilities.
d) Other
“Other” is composed of Australia, Argentina, Brazil,
Colombia, Trinidad and Tobago, Venezuela, Canada, Greenland,
Denmark, Faroe Islands, the Netherlands, Norway, Poland and the
United Kingdom. Net oil-equivalent production from countries
included in this section averaged 484,000 barrels per day
during 2009. In addition, the company’s share of production
from oil sands (for upgrading into synthetic oil) from the
Athabasca Oil Sands Project in Canada was 26,000 barrels
per day.
Australia: During 2009, the average net oil-equivalent production from Chevron’s interests in Australia was 108,000 barrels per day, composed of 35,000 barrels of liquids and 434 million cubic feet of natural gas.
Chevron has a 16.7 percent nonoperated working interest in the North West Shelf (NWS) Venture offshore Western Australia. Daily net production from the project during 2009 averaged 26,000 barrels of crude oil and condensate, 433 million cubic feet of natural gas, and 5,000 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.
The NWS Venture continues to progress two major capital projects that achieved final investment decision in 2008. Fabrication of
platform topsides for the North Rankin 2 project commenced in June 2009. The project is designed to recover remaining low-pressure natural gas from the North Rankin and Perseus natural-gas fields to meet gas supply needs and includes necessary tie-ins to, and refurbishment of, the North Rankin A platform. Upon completion, both platforms are
designed to be operated as a single integrated facility. The
project is scheduled to start production in 2013. Proved
reserves have been recognized for the project.
The NWS Venture is also advancing plans to extend the period of
crude-oil production. The NWS Oil Redevelopment Project is
designed to replace the present floating production, storage and
offloading vessel and a portion of existing subsea
infrastructure that services production from the Cossack,
Hermes, Lambert and Wanaea offshore fields. In 2009, work
commenced on conversion of the replacement vessel. The project
is expected to
start-up in
early 2011 and 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 4,000 barrels per day in
2009. Chevron’s interests in these operations are
57.1 percent for Barrow and 51.4 percent for Thevenard.
Also off the northwest coast of Australia, Chevron holds
significant equity interests in the large natural-gas resource
of the Greater Gorgon Area. The company initially held a
50 percent ownership interest across most of the area and
is the operator of the Gorgon Project. Chevron and its
joint-venture partners are proceeding with the combined
development of Gorgon and nearby natural-gas fields as one
large-scale project. Environmental approval from the Australian
Commonwealth Government was issued in August 2009. In September
2009, the company announced the final investment decision and
total estimated project costs for the first phase of development
of $37 billion (AU$ 43 billion). The
project’s scope includes a three-train,
15 million-metric-ton-per-year LNG facility; a carbon
sequestration project; and a domestic natural-gas plant. Natural
gas for the project is expected to be supplied from the Gorgon
and Io/Jansz fields.
In 2009, long-term, binding agreements were finalized with four
Asian customers for the delivery of about 4.4 million
metric tons per year of LNG from the Gorgon Project. Equity
sales agreements with three of the customers reduced
Chevron’s interest in the project to 47.3 percent at
the end of 2009. Nonbinding Heads of Agreements (HOA) for
delivery of an additional 2.1 million metric tons per year
of LNG were also signed with three additional Asian customers in
2009 and early 2010. Negotiations continue to finalize binding
sales agreements, which would bring LNG delivery commitments to
a combined total of about 90 percent of Chevron’s
share of LNG from the project. During 2009, the company
recognized proved reserves for the Greater Gorgon Area fields
included in the project. First production of natural gas from
these fields is expected in 2014. The project’s estimated
economic life exceeds 40 years from the time of
start-up.
Development of the company’s majority-owned and operated
Wheatstone and Iago fields, located offshore Western Australia,
continued with the project entering front-end engineering and
design (FEED) in July 2009. Chevron operates the project and
plans to supply natural gas to its 75 percent-owned and
operated LNG facilities from two 100 percent-owned licenses
comprising the majority of the Wheatstone Field and part of the
nearby Iago Field. In October 2009, agreements were signed with
two companies to join the Wheatstone Project as combined
25 percent LNG facility owners and suppliers of natural gas
for the project’s first two LNG trains. In December 2009
and January 2010, nonbinding HOAs were signed with two Asian
customers to take delivery of 4.9 million tons of LNG per
year from the project, representing about 60 percent of the
total LNG available from the foundation project. In addition,
under these same HOAs the parties would acquire a combined
16.8 percent nonoperated working interest in the Wheatstone
Field licenses and a 12.6 percent interest in the
foundation natural-gas processing facilities at the final
investment decision. At the end of 2009, the company had not
recognized proved reserves for this project.
In the Browse Basin, the company continued engineering and
survey work on two potential development concepts for the
Brecknock, Calliance and Torosa fields. At the end of 2009,
proved reserves had not been recognized.
In May 2009, the company announced the successful completion of
a well at the Clio prospect to further explore and appraise the
66.7 percent-owned Block WA-205-P. In 2009 and early 2010,
the company also announced natural-gas discoveries at the
Kentish Knock prospect in the 50 percent-owned Block
WA-365-P, the Achilles and Satyr prospects in the
50 percent-owned Block WA-374-P and the Yellowglen prospect
in the 50 percent-owned WA-268-P Block. All prospects are
Chevron-operated. At the end of 2009, proved reserves had not
been recognized.
Argentina: Chevron holds operated interests in eight concessions in the Neuquen Basin. Working interests range from 18.8 percent to 100 percent. Net oil-equivalent production in 2009 averaged 38,000 barrels per day, composed of 33,000 barrels of crude oil and natural gas liquids and 27 million cubic feet of natural gas. The company also holds a 14 percent interest in the Oleoductos del Valle S.A. pipeline. In 2009, Chevron sold its oil and gas concession in the Austral Basin and its interest in the Confluencia Field in the Neuquen Basin.
Brazil: Chevron holds working interests in three deepwater blocks in the Campos Basin. Chevron also holds a nonoperated working interest in one block in the Santos Basin. Net oil-equivalent production in 2009 averaged 2,000 barrels per day.
The Frade Field, located in the Campos Basin, achieved first oil in June 2009. Chevron
is the operator and has a 51.7 percent interest in the field. Additional development drilling is under way, with an estimated maximum total production of 72,000 oil-equivalent barrels per day. The concession that includes the Frade project expires in 2025.
In the partner-operated Campos Basin Block BC-20, two areas — 37.5 percent-owned Papa-Terra and 30 percent-owned Maromba — were retained for developmentfollowing the end of the exploration phase of this block. The Papa-Terra project progressed through FEED, and a
final investment decision was made in January 2010. The project
operator estimates total costs of $5.2 billion and expects
first production in 2013. The facility is expected to be capable
of producing up to 140,000 barrels of crude oil per day.
Evaluation of design options for Maromba continued into 2010. At
the end of 2009, proved reserves had not been recognized for
these projects.
In the Santos Basin, evaluation of investment options continued
into 2010 for the 20 percent-owned and partner-operated
Atlanta and Oliva fields. At the end of 2009, proved reserves
had not been recognized for these fields.
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 245 million cubic feet of natural gas in 2009.
Trinidad and Tobago: Company interests include
50 percent ownership in three partner-operated blocks in
the East Coast Marine Area offshore Trinidad, which includes the
Dolphin and Dolphin Deep producing natural-gas fields and the
Starfish discovery. Chevron also holds a 50 percent
operated interest in the Manatee area of Block 6(d). Net
production in 2009 averaged 199 million cubic feet of
natural gas per day. Incremental production associated with a
new domestic sales agreement commenced at Dolphin in the 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), Venezuela’s 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. In February 2010, a
Chevron-led consortium was selected to participate in a
heavy-oil project composed of three blocks in the Orinoco Oil
Belt of eastern Venezuela. The consortium is expected to acquire
a 40 percent interest in the project, with PDVSA holding
the remaining interest.
The Loran Field in Block 2 is projected to provide the
initial supply of natural gas for Delta Caribe LNG (DCLNG) Train
1, Venezuela’s first LNG train. A DCLNG framework agreement
was signed in 2008, which provides Chevron with
a 10 percent nonoperated interest in the first train and
the associated offshore pipeline. An interim operating agreement
governing activities prior to a final investment decision was
signed by Chevron and its Train 1 partners in March 2009. In May
2009, the company relinquished part of Block 3 and retained
the portion containing the 2005 Macuira natural-gas discovery.
An unsuccessful exploration well was drilled in the
Cardon III block in 2009. The company plans to continue to
evaluate exploration potential in the Cardon III block in
2010. At the end of 2009, proved reserves had not been
recognized in these exploratory blocks.
Equity Affiliate Operations: Chevron also holds
interests in two affiliates located in western Venezuela and in
one affiliate in the Orinoco Belt. Chevron has a 30 percent
interest in the Petropiar affiliate that operates the Hamaca
heavy-oil production and upgrading project located in
Venezuela’s Orinoco Belt, a 39.2 percent interest in
the Petroboscan affiliate that operates the Boscan Field in the
western part of the country, and a 25.2 percent interest in
the Petroindependiente affiliate that operates the LL-652 Field
in Lake Maracaibo. The company’s share of average net
oil-equivalent production during 2009 from these operations was
54,000 barrels per day, composed of 51,000 barrels of
crude oil and natural gas liquids and 23 million cubic feet
of natural gas.
Canada: Company activities in Canada include nonoperated working interests of 26.9 percent in the Hibernia Field and 26.6 percent in the Hebron Field, both offshore eastern Canada, and 20 percent in the Athabasca Oil Sands Project (AOSP) and operated interests of 60 percent in the Ells River Oil Sands Project. Excluding volumes mined at AOSP, average net oil-equivalent production during 2009 was 28,000 barrels per day, composed of 27,000 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 the working interest owners are also pursuing development of the Hibernia Southern Extension (HSE). Development of the HSE nonunitized area was approved by the provincial regulator in 2009, and the first producing well for the project was completed at year-end.
In February 2010, binding agreements were signed with the
Government of Newfoundland and Labrador on the development of
the HSE unitized area, providing Chevron with a
23.6 percent nonoperated working interest in the unitized
area.
For Hebron, agreements were reached during 2008 with the
Government of Newfoundland and Labrador that allow development
activities to begin. At the end of 2009, proved reserves had not
been recognized for this project.
At AOSP, the company’s production from oil sands (for
upgrading into synthetic oil) averaged 26,000 barrels per
day during 2009. The first phase of an expansion project is
under way and is expected to increase total production from oil
sands by 100,000 barrels per day. 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 $14.3 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 production from oil
sands through wells rather than through mining operations.
Additional field appraisal activity is not planned in the
near-term. At the end of 2009, proved reserves had not been
recognized.
The company also holds exploration leases in the Mackenzie Delta
and Beaufort Sea region, including a 34 percent nonoperated
working interest in the offshore Amauligak discovery. Three
exploration wells were drilled on company leases in the
Mackenzie Delta region in 2009, and assessment of development
concept alternatives for Amauligak continues. The company holds
additional exploration acreage in eastern Labrador and the
Orphan Basin. In 2009, the company was also successful in
acquiring a western Canada lease position to explore for shale
gas. At the end of 2009, proved reserves had not been recognized
for any of these areas.
Greenland: Processing of the
2-D seismic
survey acquired over License 2007/26 in Block 4 offshore
West Greenland in 2008 continued in 2009, and evaluation will
commence in the first-half 2010. Chevron has a 29.2 percent
nonoperated working interest in this exploration license.
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 2009 from DUC averaged 55,000 barrels per day, composed of 35,000 barrels of crude oil and 119 million cubic feet of natural gas. DUC development activity in the region includes the ongoing Halfdan Phase IV project, which achieved first production in July 2009.
Faroe Islands: Chevron withdrew from License 008 in 2009, but continues to assess exploration opportunities in the area.
Netherlands: Chevron operates and holds interests ranging from 34.1 percent to 80 percent in eight blocks in the Dutch sector of the North Sea. In 2009, the company’s net oil-equivalent production from the five producing blocks was 9,000 barrels per
day, composed of 2,000 barrels of crude oil and 41 million cubic feet of natural gas. In 2009 Chevron divested its 48 percent interest in the L11/b license.
Norway:The company holds a 7.6 percent
interest in the partner-operated Draugen Field. The
company’s net production averaged 5,000 barrels of
oil-equivalent per day during 2009. In 2009, Chevron was awarded
a 40 percent working interest as operator of the
exploration license PL 527 in the deepwater portion of the
Norwegian Sea. Data acquisition was completed on a
2-D seismic
survey, and evaluation is under way.
Poland: In December 2009, Chevron was awarded three
five-year exploration licenses in the Zwierzyniec, Kransnik and
Frampol concessions, and in February 2010, Chevron acquired the
exploration rights to the Grabowiec concession. Chevron has a
100 percent-owned and operated interest in these four
concessions to explore for shale gas.
United Kingdom:The company’s average net
oil-equivalent production in 2009 from 10 offshore fields was
110,000 barrels per day, composed of 73,000 barrels of
crude oil and natural gas liquids and 222 million cubic
feet of natural gas. Most of the production was from the
85 percent-owned and operated Captain Field, the
23.4 percent-owned and operated Alba Field and the
32.4 percent-owned and jointly operated Britannia Field.
Evaluation of development alternatives continued during 2009 for
the 19.4 percent-owned and partner-operated Clair Phase 2
project west of the Shetland Islands. In the
40 percent-owned and operated Rosebank/Lochnagar area
northwest of the Shetland Islands, an exploration well in
Rosebank North was completed in the second quarter 2009 and an
appraisal well in Rosebank/Lochnagar was completed in the third
quarter 2009. Also northwest of the Shetland Islands, a
three-well exploration and appraisal drilling program was
completed in 2009 at the Cambo prospect. Technical studies have
commenced to select a preferred development alternative.
Additional exploration drilling in the region is expected to
occur in the second-half 2010. As of the end of 2009, proved
reserves had not been recognized for any of these prospects.
In February 2010, the company sold its 10 percent nonoperated
interest in the Laggan/Tormore discovery.
The company sells natural gas and natural gas liquids from its
producing operations under a variety of contractual
arrangements. In addition, the company also makes third-party
purchases and sales of natural gas and natural gas liquids in
connection with its trading activities.
During 2009, U.S. and international sales of natural gas
were 5.9 billion and 4.1 billion cubic feet per day,
respectively, which includes the company’s share of equity
affiliates’ sales. Outside the United States, substantially
all of the natural-gas sales from the company’s producing
interests are from operations in Australia, Bangladesh,
Kazakhstan, Indonesia, Latin America, the Philippines, Thailand
and the United Kingdom.
U.S. and international sales of natural gas liquids were
161 thousand and 111 thousand barrels per day, respectively, in
2009. Substantially all of the international sales of natural
gas liquids are from company operations in Africa, Australia and
Indonesia.
Refer to “Selected Operating Data,” on
page FS-10
in Management’s Discussion and Analysis of Financial
Condition and Results of Operations, for further information on
the company’s sales volumes of natural gas and natural gas
liquids. Refer also to “Delivery Commitments” on
page 8 for information related to the company’s
delivery commitments for the sale of crude oil and natural gas.
At the end of 2009, the company had a refining network capable
of processing more than 2 million barrels of crude oil per
day. Operable capacity at December 31, 2009, and daily
refinery inputs for 2007 through 2009 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)
Perth Amboy has been idled since
early 2008 and is operated as a terminal.
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 2010.
3
Includes 3,000, 6,000 and
35,000 barrels per day of refinery inputs in 2009, 2008 and
2007, respectively, for interests in refineries that were sold
during those periods.
Average crude oil distillation capacity utilization during 2009
was 91 percent, compared with 87 percent in 2008,
largely a result of improved utilization at the refineries in
Mississippi, Canada and Thailand. At the U.S. fuel
refineries, crude oil distillation capacity utilization averaged
96 percent in 2009, compared with 95 percent in 2008,
and cracking and coking capacity utilization averaged
85 percent and 86 percent in 2009 and 2008,
respectively. Cracking and coking units are the primary
facilities used in fuel refineries to convert heavier feedstocks
into gasoline and other light products.
The company’s refineries in the United States, the United
Kingdom, Canada, South Africa and Australia produce low-sulfur
fuels. During 2009, GS Caltex, the company’s
50 percent-owned affiliate, continued construction on a new
heavy-oil hydrocracker designed to increase high-value product
yield and lower feedstock costs at the Yeosu, South Korea
complex. Project completion is expected in 2010. Modifications
were completed in 2009 that enable the company’s
50 percent-owned Singapore Refining Company’s refinery
to meet regional specifications for clean diesel fuels.
At the Pascagoula Refinery, construction progressed on a
continuous catalytic reformer that is expected to improve
refinery reliability. Planning continued for a premium base-oil
facility at the company’s Pascagoula Refinery. The facility
is being designed to produce approximately 25,000 barrels
per day of premium base oil for use in manufacturing
high-performance lubricants, such as motor oils for consumer and
commercial applications. At the refinery in El Segundo,
California, design, engineering and construction work advanced
during 2009 on projects that will reduce feedstock costs and
improve yields.
At the beginning of 2009, Chevron held a 5 percent interest
in Reliance Petroleum Limited, a company formed by Reliance
Industries Limited to construct a new refinery in Jamnagar,
India. During the year, the company sold its 5 percent
interest to Reliance Industries Limited.
Chevron processes imported and domestic crude oil in its
U.S. refining operations. Imported crude oil accounted for
about 85 percent and 88 percent of Chevron’s
U.S. refinery inputs in 2009 and 2008, respectively.
In Nigeria, Chevron and the Nigerian National Petroleum
Corporation are developing a
33,000 barrel-per-day
gas-to-liquids
facility at Escravos designed to process 325 million cubic
feet per day of natural gas supplied from the Phase 3A expansion
of the Escravos Gas Plant (EGP). At the end of 2009,
construction was under way with two
gas-to-liquids
reactors and the process modules delivered to the site. 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.
The company markets petroleum products under the principal
brands of “Chevron,”“Texaco” and
“Caltex” throughout much of the world. The table below
identifies the company’s and affiliates’ refined
products sales volumes, excluding intercompany sales, for the
three years ended December 31, 2009.
Refined
Products Sales Volumes (Thousands
of Barrels per Day)
2009
2008
2007
United States
Gasolines
720
692
728
Jet Fuel
254
274
271
Gas Oils and Kerosene
226
229
221
Residual Fuel Oil
110
127
138
Other Petroleum
Products1
93
91
99
Total United States
1,403
1,413
1,457
International2
Gasolines
555
589
581
Jet Fuel
264
278
274
Gas Oils and Kerosene
647
710
730
Residual Fuel Oil
209
257
271
Other Petroleum
Products1
176
182
171
Total International
1,851
2,016
2,027
Total
Worldwide2
3,254
3,429
3,484
1
Principally naphtha, lubricants, asphalt and coke.
In the United States, the company markets under the Chevron and
Texaco brands. At year-end 2009, the company supplied directly
or through retailers and marketers approximately 9,600 Chevron-
and Texaco-branded motor vehicle service stations, primarily in
the mid-Atlantic, southern and western states. Approximately 500
of these outlets are company-owned or -leased stations. The
company plans to discontinue, by mid-2010, sales of Chevron- and
Texaco-branded motor fuels in the mid-Atlantic and other eastern
states, where the company sold to retail customers through
approximately 1,100 stations and to commercial and industrial
customers through supply arrangements. Sales in these markets
represent approximately 8 percent of the company’s
total U.S. retail fuels sales volumes. Additionally, in
January 2010, the company sold the rights to the Gulf trademark
in the United States and its territories that it had previously
licensed for use in the U.S. Northeast and Puerto Rico.
Outside the United States, Chevron supplied directly or through
retailers and marketers approximately 12,400 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, and in Australia
through its 50 percent-owned affiliate, Caltex Australia
Limited.
In 2009, the company completed the sale of businesses in Brazil,
Haiti, Nigeria, Benin, Cameroon, Republic of the Congo,
Côte d’Ivoire, Togo, Kenya, Uganda, India, Italy, Peru
and Chile. The company retained its lubricants business in
Brazil. In addition, the company sold its interest in about 465
individual service-station sites in various other countries,
including the United States. The majority of these sites
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 875 airports. The
company also markets an extensive line of lubricant and coolant
products under brand names that include Havoline, Delo, Ursa,
Meropa and Taro.
Pipelines: Chevron owns and operates an extensive
network of crude-oil, refined-product, chemicals,
natural-gas-liquids (NGL) and natural-gas pipelines and other
infrastructure assets in the United States. The company also has
direct or indirect interests in other U.S. and
international pipelines. The company’s ownership interests
in pipelines are summarized in the following table.
Partially owned pipelines are included at the company’s
equity percentage of total pipeline mileage.
2
Excludes gathering lines related to the U.S. and
international crude-oil and natural-gas production function.
3
Includes the company’s share of chemical pipelines managed
by the 50 percent-owned Chevron Phillips Chemical Company
LLC.
During 2009, work progressed on a project that is designed to
expand capacity by about 2 billion cubic feet at the
Keystone natural-gas storage facility near Midland, Texas, which
would bring the total capacity of the facility to nearly
7 billion cubic feet. The project completion is anticipated
in the second quarter 2010.
Work commenced in late 2009 to bring the Cal-Ky Pipeline, which
was decommissioned in 2002, back into crude-oil service as a
supply line for the Pascagoula Refinery. This crude-oil pipeline
is also expected to provide additional outlets for the
company’s equity production. The pipeline is expected to
return to service in 2011. The company is also leading the
evaluation and negotiations associated with a 136 mile,
24-inch
pipeline from the proposed Jack and St. Malo production facility
to Green Canyon 19 in the U.S. Gulf of Mexico. In December
2009, the company sold its interest in the western portion of
the Texaco Expanded NGL Distribution System and its
64 percent ownership interest in Southcap Pipeline Company,
which included Chevron’s 13.4 percent ownership
interest in the Capline Pipeline.
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 2009, CPC transported an
average of approximately 743,000 barrels of crude oil per
day, including 597,000 barrels per day from Kazakhstan and
146,000 barrels per day from Russia. In December 2009,
partners approved the Expansion Project Implementation Plan,
which is expected to increase the pipeline capacity to
1.4 million barrels per day. A final investment decision is
expected in late 2010.
The company has an 8.9 percent interest in the
Baku-Tbilisi-Ceyhan (BTC) affiliate that owns and operates a
pipeline that primarily transports crude oil produced by
Azerbaijan International Operating Company (AIOC) (owned
10.3 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. Compression
facilities are expected to be installed in the second quarter
2010 that are designed to increase capacity to 170 million
cubic feet per day.
Tankers: All tankers in Chevron’s controlled
seagoing fleet were utilized during 2009. At any given time
during 2009, the company had 42 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
company’s controlled fleet.
Consolidated companies only. Excludes tankers chartered on a
voyage basis, those with dead-weight tonnage less than 25,000
and those used exclusively for storage.
2
Tankers chartered for more than one year.
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. The company’s
U.S.-flagged
fleet is engaged primarily in transporting refined products
between the Gulf Coast and the East Coast and from California
refineries to terminals on the West Coast and in Alaska and
Hawaii. As part of its fleet modernization program, the company
has two
U.S.-flagged
tankers scheduled for delivery in 2010 and plans to retire three
U.S.-flagged
product tankers between 2010 and 2011. The new tankers are
expected to bring improved efficiencies to Chevron’s
U.S.-flagged
fleet.
The foreign-flagged vessels are 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. The company’s foreign-flagged
vessels also transport refined products to and from various
locations worldwide.
In addition to the vessels described above, the company owns a
one-sixth interest in each of seven liquefied-natural-gas (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.
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 2009, the
company’s owned and 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.
Chevron Phillips Chemical Company LLC (CPChem) is equally owned
with ConocoPhillips Corporation. At the end of 2009, CPChem
owned or had joint-venture interests in 34 manufacturing
facilities and five research and technical centers in Belgium,
Brazil, China, Colombia, Qatar, Saudi Arabia, Singapore, South
Korea and the United States.
During 2009, CPChem completed construction of the
22 million-pounds-per-year
Ryton®
polyphenylene-sulfide (PPS) manufacturing facility at Borger,
Texas.
Ryton®
PPS is an engineering thermoplastic used in a variety of
applications, including automotives and electronics.
Outside the United States, CPChem’s 35 percent-owned
Saudi Polymers Company continued construction during 2009 on a
petrochemical project in Al Jubail, Saudi Arabia. The
joint-venture project includes an olefins unit and downstream
polyethylene, polypropylene, 1-hexene and polystyrene units.
Project completion is expected in 2011.
CPChem continued construction during 2009 on the
49 percent-owned Q-Chem II project, located in both
Mesaieed and Ras Laffan, Qatar. The project includes a
350,000-metric-ton-per-year high-density polyethylene plant and
a 345,000-metric-ton-per-year normal alpha olefins plant, each
utilizing CPChem proprietary technology. These plants are
located adjacent to the existing Q-Chem I complex. The
Q-Chem II project also includes a separate joint venture to
develop a 1.3 million-metric-ton-per-year ethylene cracker
in Ras Laffan, in which Q-Chem II owns 54 percent of
the capacity rights.
Start-up for
the ethylene cracker is expected in March 2010, and
start-up for
the polyethylene and alpha olefins plants is anticipated in the
third quarter 2010.
Chevron’s Oronite brand lubricant and fuel additives
business is a leading developer, manufacturer and marketer of
performance additives for lubricating oils and fuels. The
company owns and operates facilities in Brazil, France, Japan,
the Netherlands, Singapore and the United States and has equity
interests in facilities in India and Mexico. Oronite lubricant
additives are blended into refined base oil to produce finished
lubricant packages used 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. During 2009, production
began at the detergent expansion facility in Palau Sakra,
Singapore. This additional capacity enhances the company’s
ability to produce detergent components for applications in
marine and automotive engines.
Chevron’s
U.S.-based
mining company produces and markets coal and molybdenum. Sales
occur in both U.S. and international markets.
The company owns and is the operator of a surface coal mine in
Kemmerer, Wyoming, an underground coal mine, North River,
in Alabama, and a surface coal mine in McKinley, New Mexico. The
company continues to actively market for sale its coal reserves
at the North River Mine and elsewhere in Alabama. The decision
was made in late 2009 to suspend production at the McKinley
Mine, and conduct reclamation activities in 2010. The company
also owns a 50 percent interest in Youngs Creek Mining
Company LLC, which was formed to develop a coal mine in northern
Wyoming. Coal sales from wholly owned mines in 2009 were
10 million tons, down about 1 million tons from 2008.
At year-end 2009, Chevron controlled approximately
193 million tons of proven and probable coal reserves in
the United States, including reserves of low-sulfur coal.
The company is contractually committed to deliver between
7 million and 9 million tons of coal per year through
the end of 2012 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 2009,
Chevron controlled approximately 53 million pounds of
proven molybdenum reserves at Questa. Underground development
and production plans at Questa were scaled back in 2009 in
response to weakening prices for molybdenum.
Chevron’s power generation business has interests in 13
power assets with a total operating capacity of more than 3,100
megawatts, primarily through joint ventures in the United States
and Asia. Twelve of these are efficient combined-cycle and
gas-fired cogeneration facilities that utilize waste heat
recovery to produce electricity and support industrial thermal
hosts. The thirteenth facility is a wind farm, located in
Casper, Wyoming, that began operating in late 2009. The
100 percent-owned and operated Casper Wind Farm is a
small-scale wind power facility designed to optimize the
efficient use of a decommissioned refinery site for delivery of
clean, renewable energy to the local utility provider.
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
company’s geothermal operations and renewable energy
projects, refer to page 18 and “Research and
Technology” below.
Chevron Energy Solutions (CES) is a wholly owned subsidiary that
designs and implements sustainable solutions for public
institutions and businesses 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 help governments, educational
institutions and other customers reduce their energy costs and
environmental impact. Major projects completed by CES in 2009
included solar and energy-efficiency installations for the Los
Angeles County Metropolitan Transportation Authority and the
San Jose Unified School District, which were the largest
projects of their kind for a U.S. transit authority and
school district.
The company’s energy technology organization supports
Chevron’s 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 Chevron’s global
operations and business processes.
Chevron Technology Ventures (CTV) manages investments and
projects in emerging energy technologies and their integration
into Chevron’s core businesses. As of the end of 2009, CTV
continued to explore technologies such as next-generation
biofuels and advanced solar.
Chevron’s research and development expenses were
$603 million, $702 million and $510 million for
the years 2009, 2008 and 2007, respectively.
Some of the investments the company makes in the areas described
above are in new or unproven technologies and business
processes, and ultimate technical or commercial successes are
not certain. The company’s overall investment in this area
is not significant to the company’s consolidated financial
position.
Virtually all aspects of the company’s businesses are
subject to various U.S. federal, state and local
environmental, health and safety laws and regulations and to
similar laws and regulations in other countries. These
regulatory requirements continue to change and increase in both
number and complexity and to govern not only the manner in which
the company conducts its operations, but also the products it
sells. Most of the costs of complying with the many laws and
regulations pertaining to its operations are, or are expected to
become, embedded in the normal costs of conducting business.
In 2009, the company’s U.S. capitalized environmental
expenditures were approximately $887 million, representing
approximately 15 percent of the company’s 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 company’s
refineries, oil and gas producing facilities, and marketing
facilities. For 2010, the company estimates U.S. capital
expenditures for environmental control facilities will be
approximately $831 million. The future annual capital costs
are uncertain and will be governed by several factors, including
future changes to regulatory requirements.
Chevron expects an increase in environment-related regulations,
including those that are intended to address concerns about
greenhouse gas emissions and global climate change, in the
countries where it has operations. For instance, under
California’s Global Warming Solutions Act enacted in 2006,
the California Air Resources Board (CARB), charged with
implementing the law, has adopted a new low-carbon fuel standard
intended to reduce the carbon intensity of transportation fuels,
which is expected to apply beginning in 2011. Additionally, CARB
is expected to propose regulations to implement the “cap
and trade” emissions regulation provisions of the law, for
adoption in the second half 2010. The effect of any such
regulation on the company’s business is uncertain.
Refer to Management’s Discussion and Analysis of Financial
Condition and Results of Operations on pages FS-16 through FS-17
for additional information on environmental matters and their
impact on Chevron and on the company’s 2009 environmental
expenditures, remediation provisions and year-end environmental
reserves. Refer also to Item 1A. Risk Factors on pages 30
through 32 for a discussion of greenhouse gas regulation and
climate change.
The company’s Internet Web site is at
www.chevron.com. Information contained on the
company’s Internet Web site is not part of this Annual
Report on
Form 10-K.
The company’s Annual Reports on
Form 10-K,
Quarterly Reports on
Form 10-Q,
Current Reports on
Form 8-K
and any amendments to these reports filed or furnished pursuant
to Section 13(a) or 15(d) of the Securities Exchange Act of
1934 are available free of charge on the company’s 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 SEC’s Web site at www.sec.gov.
Item 1A.
Risk
Factors
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 company’s
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
company’s 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 company’s 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 Chevron’s business will decline if the company
does not successfully develop resources.
The company is in an extractive business; therefore, if Chevron
is not successful in replacing the crude oil and natural gas it
produces with good prospects for future production or through
acquisitions, the company’s business will decline. Creating
and maintaining an inventory of projects depends on many
factors, including obtaining and renewing rights to explore,
develop and produce hydrocarbons; drilling success; ability to
bring long-lead-time, capital-intensive projects to completion
on budget and schedule; and efficient and profitable operation
of mature properties.
The
company’s operations could be disrupted by natural or human
factors.
Chevron operates in both urban areas and remote and sometimes
inhospitable regions. The company’s operations and
facilities are therefore subject to disruption from either
natural or human causes, including hurricanes, floods and other
forms of severe weather, war, civil unrest and other political
events, fires, earthquakes, explosions and system failures, any
of which could result in suspension of operations or harm to
people or the natural environment.
Chevron’s
business subjects the company to liability risks from litigation
or government action.
The company produces, transports, refines and markets materials
with potential toxicity, and it purchases, handles and disposes
of other potentially toxic materials in the course of the
company’s business. Chevron operations also produce
byproducts, which may be considered pollutants. Often these
operations are conducted through joint ventures over which the
company may have limited influence and control. Any of these
activities could result in liability arising from private
litigation or government action, either as a result of an
accidental, unlawful discharge or as a result of new conclusions
on the effects of the company’s operations on human health
or the environment. In addition, to the extent that societal
pressures or political or other factors are involved, it is
possible that such liability could be imposed without regard to
the company’s causation of or contribution to the asserted
damage or to other mitigating factors.
Political
instability could harm Chevron’s business.
The company’s operations, particularly exploration and
production, can be affected by changing economic, regulatory and
political environments in the various countries in which it
operates. As has occurred in the past, actions could be taken by
governments to increase public ownership of the company’s
partially or wholly owned businesses or to impose additional
taxes or royalties.
In certain locations, governments have imposed restrictions,
controls and taxes, and in others, political conditions have
existed that may threaten the safety of employees and the
company’s 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
company’s operations. Those developments have, at times,
significantly affected the company’s related operations and
results and are carefully considered by management when
evaluating the level of current and future activity in such
countries. At December 31, 2009, 26 percent of the
company’s 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 Zone
between Saudi Arabia and Kuwait. Twenty-two percent of the
company’s net proved reserves, including affiliates, were
located in OPEC countries at December 31, 2009.
Regulation
of greenhouse gas emissions could increase Chevron’s
operational costs and reduce demand for Chevron’s
products.
Continued political attention to issues concerning climate
change, the role of human activity in it and potential
mitigation through regulation could have a material impact on
the company’s operations and financial results.
International agreements and national or regional legislation
and regulatory measures to limit greenhouse emissions are
currently in various stages of discussion or implementation. For
instance, the Kyoto Protocol, Australia’s proposed
legislation and California’s Global Warming Solutions Act,
along with other actual or pending federal, state and provincial
regulations, envision a reduction of greenhouse gas emissions
through market-based regulatory programs, technology-based or
performance-based standards or a combination of them. The
company is subject to existing greenhouse gas emissions limits
in jurisdictions where such regulation is currently effective,
including the European Union and New Zealand.
In December 2009, the U.S. Environmental Protection Agency
(EPA) issued a final endangerment finding for greenhouse gases,
which specifically found that emissions of six greenhouse gases
threaten the public health and welfare and that greenhouse gases
from new motor vehicles and engines also contribute to such
pollution. These findings do not themselves impose regulatory
requirements. However, the agency is currently in the process of
promulgating greenhouse gas emission standards for light-duty
vehicles and regulations that would require certain stationary
source facilities that exceed an as-yet undetermined threshold
to obtain permits in advance, which permits could require
implementation of so-called “best available control
technologies.” In June 2009, the U.S. House of
Representatives approved the American Clean Energy and Security
Act. This is known as the Waxman-Markey bill, which includes
provisions for a
cap-and-trade
program, aimed at controlling and reducing emissions of
greenhouse gases in the United States. At this time it is not
possible to predict whether or when the U.S. Senate may act
on climate change legislation, how any bill approved by the
Senate will be reconciled with the Waxman-Markey legislation or
whether any federal legislation will supersede the EPA’s
regulatory actions.
These and other greenhouse gas emissions-related laws, policies
and regulations, may result in substantial capital, compliance,
operating and maintenance costs. The level of expenditure
required to comply with these laws and regulations is uncertain
and is expected to vary by jurisdiction depending on the laws
enacted in each jurisdiction, the company’s activities in
it and market conditions. The company’s exploration and
production of crude oil, natural gas and
various minerals such as coal; the upgrading of production from
oil sands into synthetic oil; power generation; the conversion
of crude oil and natural gas into refined products; the
processing, liquefaction and regasification of natural gas; the
transportation of crude oil, natural gas and related products
and consumers’ or customers’ use of the company’s
products result in greenhouse gas emissions that could well be
regulated. Some of these activities, such as consumers’ and
customers’ use of the company’s products, as well as
actions taken by the company’s competitors in response to
such laws and regulations, are beyond the company’s control.
The effect of regulation on the company’s financial
performance will depend on a number of factors, including, among
others, the sectors covered, the greenhouse gas emissions
reductions required by law, the extent to which Chevron would be
entitled to receive emission allowance allocations or need to
purchase compliance instruments on the open market or through
auctions, the price and availability of emission allowances and
credits, and the impact of legislation or other regulation on
the company’s ability to recover the costs incurred through
the pricing of the company’s products. Material price
increases or incentives to conserve or use alternative energy
sources could reduce demand for products the company currently
sells and adversely affect the company’s sales volumes,
revenues and margins.
Changes
in management’s estimates and assumptions may have a
material impact on the company’s consolidated financial
statements and financial or operations performance in any given
period.
In preparing the company’s periodic reports under the
Securities Exchange Act of 1934, including its financial
statements, Chevron’s management is required under
applicable rules and regulations to make estimates and
assumptions as of a specified date. These estimates and
assumptions are based on management’s best estimates and
experience as of that date and are subject to substantial risk
and uncertainty. Materially different results may occur as
circumstances change and additional information becomes known.
Areas requiring significant estimates and assumptions by
management include measurement of benefit obligations for
pension and other postretirement benefit plans; estimates of
crude oil and natural gas recoverable reserves; accruals for
estimated liabilities, including litigation reserves; and
impairments to property, plant and equipment. Changes in
estimates or assumptions or the information underlying the
assumptions, such as changes in the company’s business
plans, general market conditions or changes in commodity prices,
could affect reported amounts of assets, liabilities or expenses.
Item 1B.
Unresolved
Staff Comments
None.
Item 2.
Properties
The location and character of the company’s crude oil,
natural gas and mining properties and its refining, marketing,
transportation and chemicals facilities are described on
page 3 under Item 1. Business. Information required by
Subpart 1200 of
Regulation S-K
(“Disclosure by Registrants Engaged in Oil and Gas
Producing Activities”) is also contained in Item 1 and
in Tables I through VII on pages FS-64 through FS-77.
Note 13, “Properties, Plant and Equipment,” to
the company’s financial statements is on
page FS-45.
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
Texpet’s 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; 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
Texpet’s remediation was properly conducted and that the
remaining environmental damage reflects Petroecuador’s
failure to timely fulfill its legal obligations and
Petroecuador’s 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
engineer’s report also asserted that an additional
$8.3 billion could be assessed against Chevron for unjust
enrichment. The engineer’s report is not binding on the
court. Chevron also believes that the engineer’s work was
performed and his report prepared in a manner contrary to law
and in violation of the court’s 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, which the
court dismissed. In September 2009, following the disclosure by
Chevron of evidence that the judge participated in meetings in
which businesspeople and individuals holding themselves out as
government officials discussed the case and its likely
outcome, the judge presiding over the case petitioned to
be recused. In late September 2009, the judge was recused, and
in October 2009, the full chamber of the provincial court
affirmed the recusal, resulting in the appointment of a new
judge. Chevron filed motions to annul all of the rulings made by
the prior judge, but the new judge denied these motions. The
court has completed most of the procedural aspects of the case
and could render a judgment at any time. Chevron will continue a
vigorous defense of any attempted imposition of liability.
In the event of an adverse judgment, Chevron would expect to
pursue its appeals and vigorously defend against enforcement of
any such judgment; therefore, the ultimate outcome —
and any financial effect on Chevron — remains
uncertain. 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
engineer’s report, management does not believe the report
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).
Government Proceedings
In November 2008, the California Air Resources Board (CARB)
proposed a civil penalty against the company’s Sacramento,
California, terminal for alleged violations between August and
December 2007 of CARB’s regulations governing the minimum
concentration of additives in gasoline. Due to a computer
programming error, the Sacramento terminal’s automatic
dispensers had failed to inject additive detergent into a
gasoline line.
In November 2008, CARB proposed a civil penalty against the
company’s Richmond, California, refinery for a notice of
violation relating to gasoline that was not properly certified
as to composition. The company corrected the composition
certificates for the gasoline without requiring any change to
the composition of the gasoline. In July 2009, CARB issued the
refinery a notice of violation relating to an error in gasoline
blending that caused the product composition certifications to
be in error. The composition certifications were corrected
without requiring any change to the gasoline. Discussions with
CARB officials relating to all of these matters took place in
the fourth quarter 2009 and continue in 2010.
In July 2009, the Hawaii Department of Health (“DOH”)
alleged that Chevron is obligated to pay stipulated civil
penalties exceeding $100,000 in conjunction with commitments the
company undertook to install and operate certain air pollution
abatement equipment at its Hawaii Refinery pursuant to Clean Air
Act settlement with the United States Environmental Protection
Agency and DOH. The company has disputed many of the allegations.
Item 4.
Submission
of Matters to a Vote of Security Holders
The information on Chevron’s common stock market prices,
dividends, principal exchanges on which the stock is traded and
number of stockholders of record is contained in the Quarterly
Results and Stock Market Data tabulations, on
page FS-24.
CHEVRON
CORPORATION
ISSUER PURCHASES OF EQUITY SECURITIES
Pertains to common shares repurchased during the three-month
period ended December 31, 2009, from company employees for
required personal income tax withholdings on the exercise of the
stock options issued to management and employees under the
company’s broad-based employee stock options, long-term
incentive plans and former Texaco Inc. stock option plans. Also
includes shares delivered or attested to in satisfaction of the
exercise price by holders of certain former Texaco Inc. employee
stock options exercised during the three-month period ended
December 31, 2009.
(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 is authorized for a period of up to three years,
expiring in September 2010, and may be discontinued at any time.
As of December 31, 2009, 118,996,749 shares had been
acquired under this program for $10.1 billion. No share
repurchases occurred in 2009.
Item 6.
Selected
Financial Data
The selected financial data for years 2005 through 2009 are
presented on
page FS-63.
Item 7.
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
The index to Management’s Discussion and Analysis of
Financial Condition and Results of Operations, Consolidated
Financial Statements and Supplementary Data is presented on
page FS-1.
Item 7A.
Quantitative
and Qualitative Disclosures About Market Risk
The company’s discussion of interest rate, foreign currency
and commodity price market risk is contained in
Management’s Discussion and Analysis of Financial Condition
and Results of Operations — “Financial and
Derivative Instruments,” beginning on
page FS-14
and in Note 10 to the Consolidated Financial Statements,
“Financial and Derivative Instruments,” beginning on
page FS-39.
Item 8.
Financial
Statements and Supplementary Data
The index to Management’s Discussion and Analysis,
Consolidated Financial Statements and Supplementary Data is
presented on
page FS-1.
The company’s management has evaluated, with the
participation of the Chief Executive Officer and Chief Financial
Officer, the effectiveness of the company’s disclosure
controls and procedures (as defined in
Rule 13a-15(e)
and
15d-15(e)
under the Securities Exchange Act of 1934 (the “Exchange
Act”) as of the end of the period covered by this report.
Based on this evaluation, the Chief Executive Officer and Chief
Financial Officer concluded that the company’s disclosure
controls and procedures were effective as of December 31,2009.
The company’s management is responsible for establishing
and maintaining adequate internal control over financial
reporting, as such term is defined in Exchange Act
Rule 13a-15(f).
The company’s management, including the Chief Executive
Officer and Chief Financial Officer, conducted an evaluation of
the effectiveness of the company’s internal control over
financial reporting based on the Internal Control —
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on the results
of this evaluation, the company’s management concluded that
internal control over financial reporting was effective as of
December 31, 2009.
The effectiveness of the company’s internal control over
financial reporting as of December 31, 2009, has been
audited by PricewaterhouseCoopers LLP, an independent registered
public accounting firm, as stated in its report included on
page FS-26.
During the quarter ended December 31, 2009, there were no
changes in the company’s internal control over financial
reporting that have materially affected, or are reasonably
likely to materially affect, the company’s internal control
over financial reporting.
The Executive Officers of the Corporation consist of the
Chairman of the Board, the Vice Chairman of the Board and such
other officers of the Corporation who are members of the
Executive Committee.
Name and Age
Current and Prior Positions (up to five years)
Current Areas of Responsibility
J.S. Watson
53
Chairman of the Board and Chief Executive Officer (since 2010)
Chief Executive Officer
Vice Chairman of the Board (2009)
Executive Vice President (2008 to 2009)
Vice President and President of Chevron International Exploration and Production Company (2005 through 2007)
G.L. Kirkland
59
Vice Chairman of the Board and Executive Vice President (since 2010)
Worldwide Exploration and
Production Activities and Global
Executive Vice President (2005 through 2009)
Gas Activities, including Natural
Gas Trading
J.E. Bethancourt
58
Executive Vice President (since 2003)
Technology; Mining; Health,
Environment and Safety; Project
Resources Company; Procurement
C.A. James
55
Executive Vice President (since 2009)
Vice President and General Counsel (2002 to 2009)
Law; Human Resources
M.K. Wirth
49
Executive Vice President (since 2006)
President of Global Supply and Trading (2004
to 2006)
Global Refining, Marketing, Lubricants, and Supply and
Trading, excluding Natural
Gas Trading; Chemicals
P.E. Yarrington
53
Vice President and Chief Financial Officer (since 2009)
Finance
Vice President and Treasurer (2007 through 2008)
Vice President, Policy, Government and Public Affairs (2002 to 2007)
R.H. Pate
47
Vice President and General Counsel (since 2009) Partner and Head
of Global Competition Practice
of Hunton & Williams LLP (2005 to 2009)
Law
The information about directors required by Item 401(a) and
(e) of
Regulation S-K
and contained under the heading “Election of
Directors” in the Notice of the 2010 Annual Meeting and
2010 Proxy Statement, to be filed pursuant to
Rule 14a-6(b)
under the Securities Exchange Act of 1934 (the “Exchange
Act”), in connection with the company’s 2010 Annual
Meeting of Stockholders (the “2010 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 2010 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 2010 Proxy Statement is incorporated by reference into this
Annual Report on
Form 10-K.
The information required by Item 407(d)(4) and (5) of
Regulation S-K
and contained under the heading “Board
Operations — Board Committee Membership and
Functions” in the 2010 Proxy Statement is incorporated by
reference into this Annual Report on
Form 10-K.
There were no changes to the process by which stockholders may
recommend nominees to the Board of Directors during the last
fiscal year.
The information required by Item 402 of
Regulation S-K
and contained under the headings “Executive
Compensation” and “Director Compensation” in the
2010 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 2010 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 2010 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 2010 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 2010 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 2010 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 2010 Proxy Statement is incorporated by reference into
this Annual Report on
Form 10-K.
The information required by Item 407(a) of
Regulation S-K
and contained under the heading “Election of
Directors — Independence of Directors” in the
2010 Proxy Statement is incorporated by reference into this
Annual Report on
Form 10-K.
Item 14.
Principal
Accounting Fees and Services
The information required by Item 9(e) of Schedule 14A
and contained under the heading “Proposal to Ratify the
Independent Registered Public Accounting Firm” in the 2010
Proxy Statement is incorporated by reference into this Annual
Report on
Form 10-K.
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 25th day of February,
2010.
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 25th day of February, 2010.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Key Financial Results
Millions of dollars, except per-share amounts
2009
2008
2007
Net Income Attributable to
Chevron Corporation
$
10,483
$
23,931
$
18,688
Per Share Amounts:
Net Income Attributable to
Chevron Corporation
– Basic
$
5.26
$
11.74
$
8.83
– Diluted
$
5.24
$
11.67
$
8.77
Dividends
$
2.66
$
2.53
$
2.26
Sales and Other
Operating Revenues
$
167,402
$
264,958
$
214,091
Return on:
Capital Employed
10.6
%
26.6
%
23.1
%
Stockholders’ Equity
11.7
%
29.2
%
25.6
%
Earnings by Major Operating Area
Millions of dollars
2009
2008
2007
Upstream – Exploration and Production
United States
$
2,216
$
7,126
$
4,532
International
8,215
14,584
10,284
Total Upstream
10,431
21,710
14,816
Downstream
– Refining, Marketing
and Transportation
United States
(273
)
1,369
966
International
838
2,060
2,536
Total Downstream
565
3,429
3,502
Chemicals
409
182
396
All Other
(922
)
(1,390
)
(26
)
Net Income Attributable to
Chevron Corporation(1),(2)
$
10,483
$
23,931
$
18,688
(1) Includes foreign currency effects:
$(744
)
$ 862
$ (352
)
(2)
Also referred to as “earnings” in the discussions that follow.
Refer to the “Results of Operations” section beginning on page FS-6 for a discussion of
financial results by major operating area for the three years ended December 31, 2009.
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, Indonesia, Kazakhstan, Myanmar, the
Netherlands, Nigeria, Norway, the Partitioned Zone between Saudi Arabia and Kuwait, the
Philippines, Republic of the Congo, Singapore, South Africa, South Korea, Thailand, Trinidad and
Tobago, the United Kingdom, the United States, Venezuela and Vietnam.
Earnings of the company depend 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 company’s
chemicals business and other activities and investments. Earnings for the company in any period may
also be influenced by events or transactions that are infrequent or unusual in nature.
The company’s 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 company’s operations or investments. Those developments
have at times significantly affected the company’s operations and results and are carefully
considered by management when evaluating the level of current and future activity in such
countries.
To sustain its long-term competitive position in the upstream business, the company must
develop and replenish an inventory of projects that offer attractive financial returns for the
investment required. Identifying promising areas for exploration, acquiring the necessary rights to
explore for and to produce crude oil and natural gas, drilling successfully, and handling the many
technical and operational details in a safe and cost-effective manner are all important factors in
this effort. Projects often require long lead times and large capital commitments. 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 company’s 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 company’s financial performance and growth. Refer to the
“Results of Operations” section beginning on FS-6 for discussions of net gains on asset sales
during 2009. Asset dispositions and restructurings may also occur in future periods and could
result in significant gains or losses.
In recent years, 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 company’s operating expenses and capital programs for all business
segments, but particularly for upstream. Softening of these cost pressures started in late 2008 and
continued through most of 2009. Costs began to level out in the fourth quarter 2009. The company
continues to actively manage its schedule of work,
contracting, procurement and supply-chain activities to effectively manage costs. (Refer to the
“Upstream” section below for a discussion of the trend in crude-oil prices.)
The company continues to closely monitor developments in the financial and credit markets, the
level of worldwide economic activity and the implications to the company of movements in prices for
crude oil and natural gas. 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 address potential challenges presented in this environment. (Refer also to
the “Liquidity and Capital Resources” section beginning on FS-11.)
Comments related to earnings trends for the company’s major business areas are as
follows:
Upstream Earnings for the upstream segment are closely aligned with industry 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 company’s 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 businesses. Besides the impact of the fluctuation in prices 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 company’s ability to find or acquire and efficiently produce crude
oil and natural gas, changes in fiscal terms of contracts and changes in tax laws and regulations.
Price levels for capital and exploratory costs and operating expenses associated with the
production of crude oil and
natural gas can also be subject to external factors beyond the company’s control. External factors
include not only the general level of inflation but also commodity prices and prices charged by the
industry’s material and service providers, which can be affected by the volatility of the
industry’s own supply-and-demand conditions for such materials and services. Capital and
exploratory expenditures and operating expenses also can be affected by damage to production
facilities caused by severe weather or civil unrest.
The chart at left shows the trend in benchmark prices for West Texas Intermediate (WTI) crude
oil and U.S. Henry Hub natural gas. Industry price levels for crude oil continued to be volatile
during 2009, with prices for WTI ranging from $34 to $81 per barrel. The WTI price averaged $62 per
barrel for the full-year 2009, compared to $100 in 2008. The decline in prices from 2008 was
largely associated with a weakening in global economic conditions and a reduction in the demand for
crude oil and petroleum products. As of mid-February 2010, the WTI price was about $77.
A differential in crude-oil prices exists between high-quality (high-gravity, low-sulfur)
crudes and those of lower-quality
(low-gravity, high-sulfur). The amount of the differential in any
period is associated with the supply of heavy crude available versus the demand that is a function
of the number of refineries that are able to process this lower-quality feedstock into light
products
(motor gasoline, jet fuel, aviation gasoline and diesel fuel). The differential remained
narrow through 2009 as production declines in the industry have been mainly for lower-quality
crudes.
Chevron produces or shares in the production of heavy crude oil in California, Chad,
Indonesia, the Partitioned Zone between Saudi Arabia and Kuwait, Venezuela and in certain fields in
Angola, China and the United Kingdom
Management’s Discussion and Analysis of Financial Condition and Results of Operations
sector of the North Sea. (See page FS-10 for the company’s average U.S. and international
crude-oil realizations.)
In contrast to price movements in the global market for crude oil, price changes for natural
gas in many regional markets are more closely aligned with supply-and-demand conditions in those
markets. In the United States, prices at Henry Hub averaged about $3.80 per thousand cubic feet
(MCF) during 2009, compared with almost $9 during 2008. At December 31, 2009, and as of
mid-February 2010, the Henry Hub spot price was about $5.70 and $5.50 per MCF, respectively.
Fluctuations in the price for natural gas in the United States are closely associated with customer
demand relative to the volumes produced in North America and the level of inventory in underground
storage. Weaker U.S. demand in 2009 was associated with the economic slowdown.
Certain international natural-gas markets in which the company operates have different supply,
demand and regulatory circumstances, which historically have resulted in lower average sales prices
for the company’s production of natural gas in these locations. Chevron continues to invest in
long-term projects in these locations to install infrastructure to produce and liquefy natural gas
for transport by tanker to other markets where greater demand results in higher prices.
International natural-gas realizations averaged about $4.00 per MCF during 2009, compared with
about $5.20 per MCF during 2008. Unlike prior years, these realizations compared favorably with
those in the United States during 2009, primarily as a result of the deterioration of U.S.
supply-and-demand conditions resulting from the economic slowdown. (See page FS-10 for the
company’s average natural gas realizations for the U.S. and international regions.)
The company’s worldwide net oil-equivalent production in 2009 averaged 2.70 million barrels
per day. About one-fifth of the company’s net oil-equivalent production in 2009 occurred in the
OPEC-member countries of Angola, Nigeria and Venezuela and in the Partitioned Zone between Saudi
Arabia and Kuwait. For the year 2009, the company’s net oil production was reduced by an average of
20,000 barrels per day due to quotas imposed by OPEC. All of the imposed curtailments took place
during the first half of the year. At the December 2009 meeting, members of OPEC supported
maintaining production quotas in effect since December 2008.
The company estimates that oil-equivalent production in 2010 will average approximately 2.73
million barrels per day. This estimate is subject to many factors and uncertainties, including
additional 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. The outlook for future production levels is also
affected by the size and number of economic investment opportunities and, for new large-scale
projects, the time lag between initial exploration and the beginning of production. Investments in
upstream projects generally begin well in advance of the start of the associated crude-oil and
natural-gas production. A significant majority of Chevron’s upstream investment is made outside the
United States.
Refer to the “Results of Operations” section on pages FS-6 through FS-7 for additional
discussion of the company’s upstream business.
Refer to Table V beginning on page FS-69 for a tabulation of the company’s proved net oil and
gas reserves by geographic area, at the beginning of 2007 and each year-end from 2007 through 2009,
and an accompanying discussion of major changes to proved reserves by geographic area for the
three-year period ending December 31, 2009.
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, cost of materials and services, refinery maintenance
programs and disruptions at refineries resulting from unplanned outages due to severe weather,
fires or other operational events.
Other factors affecting profitability for downstream operations include the reliability and
efficiency of the company’s refining and marketing network and the effectiveness of the crude-oil
and product-supply functions. Profitability can also be affected by the volatility of
tanker-charter rates for the company’s shipping operations, which are driven by the industry’s
demand for crude-oil and product tankers. Other factors beyond the company’s control include the
general level of inflation and energy costs to operate the company’s refinery and distribution
network.
The company’s 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
significant ownership interests in refineries in each of these areas except Latin America. The
company completed sales of marketing businesses during 2009 in certain countries in Latin America
and Africa. The company plans to discontinue, by mid-2010, sales of Chevron- and Texaco-branded motor fuels in
the mid-Atlantic and other eastern states, where the company sold to retail customers
through approximately 1,100 stations and to commercial and industrial customers through supply
arrangements. Sales in these markets
represent approximately 8 percent of the company’s total U.S. retail fuel sales volumes. Additionally, in
January 2010, the company sold the rights to the Gulf trademark in the United States and its
territories that it had previously licensed for use in the U.S. Northeast and Puerto Rico.
The company’s refining and marketing margins in 2009 were generally weak due to
challenging industry conditions, including a sharp drop in global demand reflecting the economic
slowdown, excess refined-product supplies and surplus refining capacity. Given these conditions, in
January 2010 the company announced to its employees that high-level evaluations of Chevron’s
refining and marketing organizations had been completed. These evaluations concluded that the
company’s downstream organization should be restructured to improve operating efficiency and
achieve sustained improvement in financial performance. Details of the restructuring will be
further developed over the next three to six months and may include exits from additional markets,
dispositions of assets, reductions in the number of employees and other actions, which may result
in gains or losses in future periods.
Refer to the “Results of Operations” section on pages FS-7 and FS-8 for additional discussion
of the company’s 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
chemical earnings.
Operating Developments
Key operating developments and other events during 2009 and early 2010 included the
following:
Upstream
Angola Production began at the 39.2 percent-owned and operated Mafumeira Norte offshore
project in Block 0 and the 31 percent-owned and operated deepwater Tombua-Landana project in Block
14. Mafumeira Norte is expected to reach maximum total daily production of 42,000 barrels of crude
oil in the third quarter 2010, and the Tombua-Landana project is expected to reach its maximum
total production of approximately 100,000 barrels of crude oil per day in 2011. The company also
discovered crude oil offshore in the 39.2 percent-owned and operated Block 0 concession, extending
a trend of earlier discoveries in the Greater Vanza/Longui Area.
AustraliaThe company and its partners reached final investment decision to proceed with the
development of the Gorgon Project, located offshore Western Australia, in which Chevron has a 47.3
percent-owned and operated interest as of December 31, 2009. In addition, the company finalized
long-term sales agreements for delivery of liquefied natural gas (LNG) from the Gorgon Project with
four Asian customers, three of which also acquired an ownership interest in the project. Nonbinding
Heads of Agreement (HOAs) with three additional Asian customers were also signed in late 2009 and
early 2010 for delivery of LNG from the project. Negotiations continue to finalize binding
sales agreements, which would bring LNG delivery commitments to a combined total of about 90
percent of Chevron’s share of LNG from the project.
The company awarded front-end engineering and design contracts for the first phase of the
Wheatstone natural gas project, also located offshore northwest Australia. The 75
percent-owned and
operated facilities will have LNG processing capacity of 8.6 million metric tons
per year and a
co-located domestic natural-gas plant. The facilities will support development of
Chevron’s interests in the Wheatstone Field and nearby Iago Field. Agreements were signed with two
companies to join the Wheatstone Project as combined 25 percent owners and suppliers of natural gas
for the project’s first two LNG trains. In addition, nonbinding HOAs were signed with two Asian
customers to take delivery of 4.9 million metric tons per year of LNG from the project (about 60 percent of
the total LNG available from the foundation project) and to acquire a 16.8 percent equity interest in the Wheatstone Field licenses and a 12.6 percent
interest in the foundation natural gas processing facilities at the final investment decision.
In May 2009 the company announced the successful
completion of a well at the Clio prospect to
further explore and appraise the 66.7 percent-owned Block WA-205-P. In 2009 and early 2010, the
company also announced natural-gas discoveries at the Kentish Knock prospect in the 50
percent-owned Block WA-365-P, the Achilles and Satyr prospects in the 50 percent-owned Block
WA-374-P and the Yellowglen prospect in the 50 percent-owned
WA-268-P Block. All prospects are
Chevron-operated. Proved reserves have not been recognized for these discoveries.
Brazil Production started at the 51.7 percent-owned and operated deepwater Frade Field, which
is projected to attain maximum total production of 72,000 oil-equivalent barrels per day in 2011.
Also, in early 2010 a final investment decision was reached to develop the 37.5 percent-owned,
partner-operated Papa-Terra Field, where first production is expected in 2013. Project facilities are designed
with a capacity to handle up to 140,000 barrels of crude oil per day.
Republic of the Congo Crude oil was discovered in the northern portion of the 31.5
percent-owned, partner-operated Moho-Bilondo deepwater permit area. This discovery follows two
others made in 2007 in the same permit area.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Venezuela In February 2010, a Chevron-led consortium was named the operator of a heavy-oil
project composed of three blocks in the Orinoco Oil Belt of eastern Venezuela.
United States First oil was achieved at the 58 percent-owned and operated Tahiti Field in the
deepwater Gulf of Mexico, reaching maximum total production of 135,000 barrels of oil-equivalent
per day. The company also discovered crude oil at the Chevron-operated and 55 percent-owned
Buckskin prospect in the deepwater Gulf of Mexico. The first appraisal well is scheduled to begin
drilling in the second quarter 2010.
Downstream
The company sold businesses during 2009 in Brazil, Haiti, Nigeria, Benin, Cameroon, Republic
of the Congo, Côte d’Ivoire, Togo, Kenya, Uganda, India, Italy, Peru and Chile.
Other
Common Stock Dividends The quarterly common stock dividend increased by 4.6 percent in July
2009, to $0.68 per share. 2009 was the 22nd consecutive year that the company increased its annual
dividend payment.
Common Stock Repurchase ProgramThe company did not acquire any shares during 2009 under its $15
billion repurchase program, which began in 2007 and expires in September 2010. As of December 31,2009, 119 million common shares had been acquired under this program for $10.1 billion.
Results of Operations
Major Operating Areas The following section presents the results of operations for the company’s
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 company’s investment in Dynegy prior to its sale in May
2007. Earnings are also presented for the U.S. and international geographic areas of the upstream
and downstream business segments. (Refer to Note 11, beginning on page FS-40, for a discussion of
the company’s “reportable segments,” as defined in accounting standards for segment reporting
(Accounting Standards Codification (ASC) 280)). This section should also be read in conjunction with
the discussion in “Business Environment and Outlook” on pages FS-2 through FS-5.
U.S. Upstream – Exploration and Production
Millions of dollars
2009
2008
2007
Earnings
$
2,216
$
7,126
$
4,532
U.S upstream earnings of $2.2 billion in 2009 decreased $4.9 billion from 2008. Lower
prices for crude oil and natural gas reduced earnings by about $5.2 billion between periods, and
gains on asset sales declined by approximately $900 million. Partially offsetting these effects was
a benefit of about $1.3 billion resulting from an increase in net oil-equivalent production. An
approximate $600 million benefit to income from lower operating expenses was more than offset by
higher depreciation expense. The benefit from
lower operating expenses was largely associated with absence of charges for damages related to
the 2008 hurricanes in the Gulf of Mexico.
U.S upstream earnings 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.
The company’s average realization for crude oil and natural gas liquids in 2009 was $54.36 per
barrel, compared with $88.43 in 2008 and $63.16 in 2007. The average natural-gas realization was
$3.73 per thousand cubic feet in 2009, compared with $7.90 and $6.12 in 2008 and 2007,
respectively.
Net oil-equivalent production in 2009 averaged 717,000 barrels per day, up 6.9 percent from
2008 and down 3.5 percent from 2007. The increase between 2008 and 2009 was mainly due to the
start-up of the Blind Faith Field in late 2008 and the Tahiti Field in the
second quarter 2009. The decrease between 2007 and 2008 was mainly due to normal field
declines and the adverse impact of the hurricanes. The net liquids component of oil-equivalent
production for 2009 averaged 484,000 barrels per day, up approximately 15 percent from 2008 and 5
percent compared with 2007. Net natural-gas production averaged 1.4 billion cubic feet per day in
2009, down approximately 7 percent from 2008 and about 18 percent from 2007.
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
2009
2008
2007
Earnings*
$
8,215
$
14,584
$
10,284
*Includes foreign currency effects:
$(571
)
$ 873
$ (417
)
International upstream earnings of $8.2 billion in 2009 decreased $6.4 billion from 2008.
Lower prices for crude oil and natural gas reduced earnings by $7.0 billion, while foreign-currency
effects and higher operating and depreciation expenses decreased income by a total of $2.2 billion.
Partially offsetting these items were benefits of $2.3 billion resulting from an increase in sales
volumes of crude oil and about $500 million associated with asset sales and tax items related to
the Gorgon Project in Australia.
Earnings 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 a reduction to
earnings of $417 million in 2007.
The company’s average realization for crude oil and natural gas liquids in 2009 was $55.97 per
barrel, compared with $86.51 in 2008 and $65.01 in 2007. The average natural-gas realization was
$4.01 per thousand cubic feet in 2009, compared with $5.19 and $3.90 in 2008 and 2007,
respectively.
Net oil-equivalent production of 1.99 million barrels per day in 2009 increased about 7
percent and 6 percent from 2008 and 2007, respectively. The volumes for each year included
production from oil sands in Canada. Absent the impact of prices on certain production-sharing and
variable-royalty agreements, net
oil-equivalent production increased 4 percent in 2009 and 3
percent in 2008, when compared with prior years’ production.
The net liquids component of oil-equivalent production was 1.4 million barrels per day in
2009, an increase of approximately 11 percent from 2008 and 5 percent from
2007. Net natural-gas production of 3.6 billion cubic feet per day in 2009 was down 1 percent and
up 8 percent from 2008 and 2007, 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
2009
2008
2007
Earnings
$
(273
)
$
1,369
$
966
U.S downstream operations lost $273 million in 2009, an earnings decrease of
approximately $1.6 billion from 2008. A decline in refined product margins resulted in
a negative earnings variance of $1.7 billion.
Partially offsetting were lower operating expenses, which benefited
earnings by $300 million. 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 2007 and 2008.
Sales volumes of refined products were 1.40 million barrels per day in 2009, a decrease of 1
percent from 2008. The decline was associated with reduced demand for jet fuel and fuel oil,
principally associated with the downturn in the U.S. economy. Sales volumes of refined products
were 1.41 million barrels per day in 2008, a decrease of 3 percent from 2007. Branded gasoline
sales volumes of 617,000 barrels per day in 2009 were up about 3 percent and down 2 percent from
2008 and 2007, respectively.
Refer to the “Selected Operating Data” table on page FS-10 for a three-year comparison of
sales volumes of gasoline and other refined products and refinery-input volumes.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
International Downstream – Refining, Marketing and Transportation
Millions of dollars
2009
2008
2007
Earnings*
$
838
$
2,060
$
2,536
*Includes foreign currency effects:
$(213
)
$ 193
$ 62
International downstream earnings of $838 million in 2009 decreased about $1.2 billion from
2008. An approximate $2.6 billion decline between periods was associated with weaker margins on the
sale of gasoline and other refined products and the absence
of gains recorded in 2008 on commodity derivative instruments. Foreign-currency effects produced a
negative variance of $400 million. Partially offsetting these items was a $1.0 billion benefit from
lower operating expenses associated mainly with contract labor,
professional services and transportation costs and about a $550 million increase in gains on asset
sales primarily in certain countries in Latin America and Africa. Earnings in 2008 of $2.1 billion
decreased nearly $500 million from 2007. Earnings in 2007 included gains of approximately $1
billion on the sale of assets, which included
marketing assets in the Benelux region of Europe and an interest in a refinery.
The $500 million other improvement 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 from sales of
refined products. Foreign-currency
effects increased earnings by $193 million in 2008, compared with $62 million in 2007.
Refined-product sales volumes were 1.85 million barrels per day in 2009, about 8 percent lower
than in 2008 due mainly to the effects of asset sales and lower demand. Refined-product sales
volumes were 2.02 million barrels per day in 2008, about level with 2007.
Refer to the “Selected Operating Data” table, on page FS-10, for a three-year comparison of
sales volumes of gasoline and other refined products and refinery-input volumes.
Chemicals
Millions of dollars
2009
2008
2007
Earnings*
$
409
$
182
$
396
*Includes foreign currency effects:
$15
$ (18
)
$ (3
)
The chemicals segment includes the company’s Oronite subsidiary and the 50 percent-owned
Chevron Phillips Chemical Company LLC (CPChem). In 2009, earnings were $409 million, compared with
$182 million and $396 million in 2008
and 2007, respectively. For CPChem, the earnings improvement
from 2008 to 2009 reflected lower utility and manufacturing costs as well as the absence of an
impairment recorded in 2008. These benefits were partially offset by
lower margins on the sale of commodity chemicals. For Oronite, earnings increased in 2009 due to
higher margins on sales of lubricant and fuel additives, the effect of which more than offset the
impact of lower sales volumes. In 2008, segment earnings were $182 million, compared with $396
million in 2007. 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 Oronite due to lower volumes and higher operating expenses.
All Other
Millions of dollars
2009
2008
2007
Net Charges*
$
(922
)
$
(1,390
)
$
(26
)
*Includes foreign currency effects:
$ 25
$ (186
)
$ 6
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 company’s interest in
Dynegy, Inc. prior to its sale in May 2007.
Net charges in 2009 decreased $468 million from 2008 due to lower provisions for environmental
remediation at sites
that previously had been closed or sold, favorable foreign-currency effects and lower expenses for
employee compensation and benefits. Net charges in 2008 increased $1.4 billion from 2007. Results
in 2008 included net unfavorable corporate tax items and increased costs of environmental
remediation. Foreign-currency effects also contributed to the increase in net charges from 2007 to
2008. Results in 2007 included a $680 million gain on the sale of the company’s investment in
Dynegy common stock and a loss of approximately $175 million associated with the early redemption
of Texaco Capital Inc. bonds.
Consolidated Statement of Income
Comparative amounts for certain income statement categories are shown below:
Millions of dollars
2009
2008
2007
Sales and other operating revenues
$
167,402
$
264,958
$
214,091
Sales and other operating revenues decreased in 2009, due mainly to lower prices for
crude oil, natural
gas and refined products. Higher 2008 prices resulted in increased revenues compared with
2007.
Millions of dollars
2009
2008
2007
Income from equity affiliates
$
3,316
$
5,366
$
4,144
Income from equity affiliates decreased in 2009 from 2008. Upstream-related affiliate
income declined about $1.3 billion mainly due to lower earnings for Tengizchevroil (TCO) in
Kazakhstan as a result of lower prices for crude oil. Downstream-related affiliate earnings were
lower by approximately $1.0 billion primarily due to weaker margins and an unfavorable swing in
foreign-currency effects. Income from equity affiliates increased in 2008 from 2007 largely due to
improved upstream-related earnings at TCO as a result of higher prices for crude oil. Refer to Note
12, beginning on page FS-43, for a discussion of Chevron’s investments in affiliated companies.
Millions of dollars
2009
2008
2007
Other income
$
918
$
2,681
$
2,669
Other income of $918 million in 2009 included gains of approximately $1.3 billion on
asset sales. Other income of $2.7 billion in 2008 and 2007 included net gains from asset sales of
$1.3 billion and $1.7 billion, respectively. Interest income was approximately $95 million in 2009,
$340 million in 2008 and $600 million in 2007. Foreign-currency effects reduced other income by
$466 million in 2009 while increasing other income by $355 million in 2008 and reducing other
income by $352 million in 2007. In addition, other income in 2008 included approximately $700
million in favorable settlements and other items.
Millions of dollars
2009
2008
2007
Purchased crude oil and products
$
99,653
$
171,397
$
133,309
Crude oil and product purchases in 2009 decreased $71.7 billion from 2008 due to lower
prices for crude oil, natural gas and refined products. 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.
Millions of dollars
2009
2008
2007
Operating, selling, general and administrative expenses
$
22,384
$
26,551
$
22,858
Operating, selling, general and administrative expenses in 2009 decreased approximately
$4.2 billion from 2008 primarily due to $1.4 billion of lower fuel and transportation expenses;
$800 million of decreased costs for contract labor and professional services; absence of uninsured
2008 hurricane-related charges of $700 million; a decrease of about $500 million for environmental
remediation activities; $200 million of lower costs for materials; and $600 million for other
items. Total expenses for 2008 were about $3.7 billion higher than 2007 primarily due to $1.2
billion of higher costs for employee and contract labor and professional services; $600 million of
increased transportation expenses; $700 million of uninsured losses associated with hurricanes in
the Gulf of Mexico in 2008; an increase of about $300 million for environmental remediation
activities; $200 million from higher material expenses; and $700 million from increases for other
items.
Millions of dollars
2009
2008
2007
Exploration expense
$
1,342
$
1,169
$
1,323
Exploration expenses in 2009 increased from 2008 due mainly to higher amounts for well
write-offs in the United States and international operations. Expenses in 2008 declined from 2007
mainly due to lower amounts for well write-offs for operations in the United States.
Millions of dollars
2009
2008
2007
Depreciation, depletion and
amortization
$
12,110
$
9,528
$
8,708
Depreciation, depletion and amortization expenses increased in 2009 from 2008 due to
incremental production related to start-ups for upstream projects in the United States and Africa
and higher depreciation rates for certain other oil and gas producing fields. The increase in 2008
from 2007 was 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.
Millions of dollars
2009
2008
2007
Taxes other than on income
$
17,591
$
21,303
$
22,266
Taxes other than on income decreased in 2009 from 2008 mainly due to lower import duties
for the company’s downstream operations in the United Kingdom. Taxes other than on income decreased in
2008 from 2007 mainly due to lower import duties as a result of the effects of the 2007 sales
Management’s Discussion and Analysis of Financial Condition and Results of Operations
of the company’s Benelux refining and marketing businesses and a decline in import volumes
in the United Kingdom.
Millions of dollars
2009
2008
2007
Interest and debt expense
$
28
$
–
$
166
Interest and debt expense increased in 2009 due to an increase in long-term debt.
Interest and debt expense decreased in 2008 because all interest-related amounts were being
capitalized.
Millions of dollars
2009
2008
2007
Income tax expense
$
7,965
$
19,026
$
13,479
Effective income tax rates were 43 percent in 2009, 44 percent in 2008 and 42 percent in
2007. The rate was lower in 2009 than in 2008 mainly due the effect in 2009 of deferred tax
benefits and relatively low tax rates on asset sales, both related to an international upstream
project. In addition, a greater proportion of before-tax income was earned in 2009 by equity
affiliates than in 2008. (Equity-affiliate income is reported as a single amount on an
after-tax
basis on the Consolidated Statement of Income.) Partially offsetting these items was the effect of
a greater proportion of income earned in 2009 in tax jurisdictions with higher tax rates. The rate
was higher in 2008 compared with 2007 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 company’s investment in Dynegy common stock and the sale of
downstream assets in Europe. Refer also to the discussion of income taxes in Note 15 beginning on
page FS-46.
Selected Operating Data1,2
2009
2008
2007
U.S. Upstream
Net Crude Oil and Natural Gas
Liquids Production (MBPD)
484
421
460
Net Natural
Gas Production (MMCFPD)3
1,399
1,501
1,699
Net Oil-Equivalent Production (MBOEPD)
717
671
743
Sales of Natural Gas (MMCFPD)
5,901
7,226
7,624
Sales of Natural Gas Liquids (MBPD)
17
15
25
Revenues From Net Production
Liquids ($/Bbl)
$
54.36
$
88.43
$
63.16
Natural Gas ($/MCF)
$
3.73
$
7.90
$
6.12
International Upstream
Net Crude Oil and Natural Gas
Liquids Production (MBPD)
1,362
1,228
1,296
Net Natural
Gas Production (MMCFPD)3
3,590
3,624
3,320
Net Oil-Equivalent
Production (MBOEPD)4
1,987
1,859
1,876
Sales of Natural Gas (MMCFPD)
4,062
4,215
3,792
Sales of Natural Gas Liquids (MBPD)
23
17
22
Revenues From Liftings
Liquids ($/Bbl)
$
55.97
$
86.51
$
65.01
Natural Gas ($/MCF)
$
4.01
$
5.19
$
3.90
Worldwide Upstream
Net Oil-Equivalent Production
(MBOEPD)3,4
United States
717
671
743
International
1,987
1,859
1,876
Total
2,704
2,530
2,619
U.S. Downstream
Gasoline Sales (MBPD)5
720
692
728
Other Refined-Product Sales (MBPD)
683
721
729
Total Refined Product Sales (MBPD)
1,403
1,413
1,457
Sales of Natural Gas Liquids (MBPD)
144
144
135
Refinery Input (MBPD)
899
891
812
International Downstream
Gasoline Sales (MBPD)5
555
589
581
Other Refined-Product Sales (MBPD)
1,296
1,427
1,446
Total Refined Product Sales (MBPD)6
1,851
2,016
2,027
Sales of Natural Gas Liquids (MBPD)
88
97
96
Refinery Input (MBPD)
979
967
1,021
1
Includes company share of equity affiliates.
2
MBPD – thousands of barrels per day; MMCFPD – millions of cubic feet per day; MBOEPD
– thousands of barrels of oil-equivalents per day; Bbl – Barrel; MCF = Thousands of cubic
feet. Oil-equivalent gas (OEG) conversion ratio is 6,000 cubic feet of natural gas = 1 barrel
of oil.
3
Includes natural gas consumed in operations (MMCFPD):
Cash, cash equivalents and marketable securities Total balances were $8.8 billion and $9.6
billion at December 31, 2009 and 2008, respectively. Cash provided by operating activities in 2009
was $19.4
billion, compared with $29.6 billion in 2008 and $25.0 billion in 2007.
Cash provided by operating activities was net of contributions to employee pension plans of
approximately $1.7 billion, $800 million and $300 million in 2009, 2008 and 2007, respectively.
Cash provided by investing activities included proceeds and deposits related to asset sales of $2.6
billion in 2009, $1.5 billion in 2008 and $3.3 billion in 2007.
Restricted cash of $123 million and
$367 million associated with various capital-investment projects at December 31, 2009 and 2008,
respectively, was invested in short-term marketable securities and recorded as “Deferred charges
and other assets” on the Consolidated Balance Sheet.
Dividends Dividends paid to common stockholders were approximately $5.3 billion in 2009, $5.2
billion in 2008 and $4.8 billion in 2007. In July 2009, the company increased its quarterly common
stock dividend by 4.6 percent to $0.68 per share.
Debt and capital lease obligations Total debt and capital lease obligations were $10.5 billion
at December 31, 2009, up from $8.9 billion at year-end 2008.
The $1.6 billion increase in total
debt and capital lease obligations during 2009 included the net effect of a $5 billion public bond
issuance, a $350 million issuance of tax-exempt Gulf Opportunity Zone bonds, a $3.2 billion
decrease in commercial paper, and a $400 million payment of principal for Texaco Capital Inc. bonds
that matured in January 2009. The company’s debt and capital lease obligations due within one year,
consisting primarily of commercial paper and the current portion of long-term debt, totaled $4.6
billion at
December 31, 2009, down from $7.8 billion at year-end 2008. Of these amounts, $4.2 billion and
$5.0 billion were reclassified to long-term at the end of each period, respectively. At year-end
2009, settlement of these obligations was not expected to require the use of working capital in
2010, 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 2009, the company had $5.1 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 company’s practice has been to continually replace expiring commitments with new commitments on
substantially the same terms, maintaining levels management believes appropriate. Any borrowings
under the facilities would be unsecured indebtedness at interest rates based on London Interbank
Offered Rate or an average of base lending rates published by specified banks and on terms
reflecting the company’s strong credit rating. No borrowings were outstanding under these
facilities at December 31, 2009. 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. The company intends to file a new
shelf registration statement when the current one expires.
The company has outstanding public bonds issued by Chevron Corporation,
Chevron Corporation Profit Sharing/ Savings Plan Trust Fund, Texaco Capital Inc. and Union Oil
Company of California. All of these securities are the obligations of, or guaranteed by, Chevron
Corporation and are rated AA by Standard and Poor’s Corporation and Aa1 by Moody’s Investors
Service. The company’s U.S. commercial paper is rated A-1+ by Standard and Poor’s and P-1 by
Moody’s. All of these ratings denote high-quality, investment-grade securities.
The company’s future debt level is dependent primarily on results of operations, the
capital-spending program and cash that may be generated from asset dispositions. The company
believes that it has substantial borrowing capacity to meet unanticipated cash requirements and
that during periods of low prices for crude oil and natural gas and narrow margins for refined
products and commodity chemicals, it has the flexibility to increase borrowings and/or modify
capital-spending plans to continue paying the common stock dividend and maintain the company’s
high-quality debt ratings.
Common stock repurchase program In September 2007, the company authorized the acquisition of
up to $15 billion of its common shares 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 (expiring in 2010) and may be discontinued at any time. The company
did not acquire any shares during 2009 and does not plan to acquire any shares in the first
quarter 2010. From the inception of the program, the company has acquired 119 million shares at a
cost of $10.1 billion.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Capital and Exploratory Expenditures
2009
2008
2007
Millions of dollars
U.S.
Int’l.
Total
U.S.
Int’l.
Total
U.S.
Int’l.
Total
Upstream – Exploration and Production
$
3,261
$
13,848
$
17,109
$
5,516
$
11,944
$
17,460
$
4,558
$
10,980
$
15,538
Downstream – Refining, Marketing and
Transportation
1,910
2,511
4,421
2,182
2,023
4,205
1,576
1,867
3,443
Chemicals
210
92
302
407
78
485
218
53
271
All Other
402
3
405
618
7
625
768
6
774
Total
$
5,783
$
16,454
$
22,237
$
8,723
$
14,052
$
22,775
$
7,120
$
12,906
$
20,026
Total, Excluding Equity in Affiliates
$
5,558
$
15,094
$
20,652
$
8,241
$
12,228
$
20,469
$
6,900
$
10,790
$
17,690
Capital and exploratory expenditures Total expenditures for 2009 were $22.2 billion,
including $1.6 billion for the company’s share of equity-affiliate expenditures and $2 billion for
the extension of an upstream concession. In 2008 and 2007, expenditures were $22.8 billion and
$20.0 billion, respectively, including the company’s share of affiliates’ expenditures of
$2.3
billion in both periods.
Of the $22.2 billion of expenditures in 2009, about
three-fourths, or $17.1 billion, is
related to upstream activities. Approximately the same percentage was also expended for upstream
operations in 2008 and 2007. International upstream accounted for about 80 percent of the worldwide upstream investment in 2009 and about
70
percent in 2008 and 2007, reflecting the company’s continuing focus on opportunities available
outside the United States.
The company estimates that in 2010, capital and exploratory expenditures will be $21.6
billion, including $1.6 billion of spending by affiliates. About 80 percent of the total, or $17.3
billion, is budgeted for exploration and production activities, with $13.2 billion of this amount
for projects outside the United States. Spending in 2010 is primarily targeted for exploratory
prospects in the U.S. Gulf of Mexico and major development projects in Angola, Australia, Brazil,
Canada, China, Nigeria, Thailand and the U.S. Gulf of Mexico. Also included is funding for base
business improvements and focused appraisals in core hydrocarbon basins.
Worldwide downstream spending in 2010 is estimated at $3.4 billion, with about $1.6 billion
for projects in the
United States. Major capital outlays include projects under construction at refineries in the
United States and South Korea and construction of gas-to-liquids facilities in support of
associated upstream projects.
Investments in chemicals, technology and other corporate businesses in 2010 are budgeted at
$900 million. Technology investments include projects related to unconventional hydrocarbon
technologies, oil and gas reservoir management, and gas-fired and renewable power generation.
Noncontrolling interestsThe company had noncontrolling interests of $647 million and $469
million at December 31, 2009 and 2008, respectively. Distributions to noncontrolling interests
totaled $71 million and $99 million in 2009 and 2008, respectively.
Pension Obligations In 2009, the company’s pension plan contributions were $1.7 billion
(including $1.5 billion to the U.S. plans and $200 million to the international plans). The
company estimates contributions in 2010 will be approximately $900 million ($600 million for the
U.S. plans and $300 million for the international plans). Actual contribution amounts are
dependent upon investment returns, changes in pension obligations, regulatory environments and
other economic factors. Additional funding may ultimately be required if investment returns are
insufficient to offset increases in plan obligations. 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
2009
2008
2007
Current Ratio
1.4
1.1
1.2
Interest Coverage Ratio
62.3
166.9
69.2
Debt Ratio
10.3
%
9.3
%
8.6
%
Current Ratio – current assets divided by current liabilities. The current ratio in all
periods was adversely affected by the fact that Chevron’s inventories are valued on a Last-In,
First-Out basis. At year-end 2009, the book value of inventory
was lower than replacement costs, based on average acquisition costs during the year, by
approximately $5.5 billion.
Interest Coverage Ratio – income before income tax expense, plus
interest and debt expense and amortization of capitalized interest, less net
income attributable to noncontrolling interests, divided by before-tax interest costs. The
company’s interest coverage ratio in 2009 was lower than 2008 and 2007 due to lower before-tax
income. Debt Ratio – total debt as a percentage of total debt plus Chevron Corporation Stockholders’
Equity. The increase in 2009 over 2008 and 2007 was primarily due to the increase in debt as a
result of the $5 billion issuance of public bonds in 2009.
Guarantees, Off-Balance-
Sheet Arrangements and
Contractual Obligations, and Other Contingencies
Direct Guarantee
Millions of dollars
Commitment Expiration by Period
2011–
2013–
After
Total
2010
2012
2014
2014
Guarantee of non-
consolidated affiliate or joint-venture obligation
$
613
$
–
$
38
$
77
$
498
The company’s 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 over time as certain fees are paid by the affiliate. There are numerous
cross-indemnity agreements with the affiliate and the other partners to permit recovery of any
amounts paid under the guarantee. Chevron 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
company’s 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 2009, 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 origi-
nally 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 Texaco’s 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 had to be asserted by February 2009 for Equilon indemnities and must be asserted
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. Management
does not believe this letter or any other information provides a basis to estimate the amount,
if any, of a range of loss or potential range of loss with respect to either the 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 in the preceding paragraph 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. The
acquirer of those assets shared in certain environmental remediation costs up to a maximum
obligation of $200 million, which had been reached at December 31, 2009. Under the
indemnification agreement, after reaching the $200 million obligation, Chevron is solely
responsible until April 2022, when the indemnification expires. The environmental conditions or
events that are subject to these indemnities must have arisen prior to the sale of the assets
in 1997.
Although the company has provided for known obligations under this indemnity 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.
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 company’s business. The aggregate approximate amounts of required payments under
these various commitments are: 2010 – $7.5 billion; 2011
– $4.3 billion; 2012 – $1.4
billion; 2013 – $1.4 billion; 2014 – $1.0 billion; 2015 and after – $4.1 billion. A portion
of these commitments may ultimately be shared with project
Management’s Discussion and Analysis of Financial Condition and Results of Operations
partners. Total payments under the agreements were approximately $8.1 billion in 2009, $5.1
billion in 2008 and $3.7 billion in 2007.
The following table summarizes the company’s significant contractual obligations:
Contractual Obligations1
Millions of dollars
Payments Due by Period
2011–
2013–
After
Total
2010
2012
2014
2014
On Balance Sheet:2
Short-Term Debt3
$
384
$
384
$
–
$
–
$
–
Long-Term Debt3
9,829
–
5,743
2,041
2,045
Noncancelable Capital
Lease Obligations
499
90
168
104
137
Interest
2,590
317
566
426
1,281
Off-Balance-Sheet:
Noncancelable Operating
Lease Obligations
3,364
568
844
719
1,233
Throughput and
Take-or-Pay Agreements
15,130
6,555
3,825
819
3,931
Other Unconditional
Purchase Obligations4
4,617
1,024
1,906
1,538
149
1
Excludes contributions for pensions and other postretirement benefit plans.
Information on employee benefit plans is contained in Note 21 beginning on page FS-52.
2
Does not include amounts related to the company’s 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
$4.2 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 2011–2012 period.
4
Does not include obligations to purchase the company’s 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 LNG 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 company’s portfolio of financial and derivative
instruments is discussed below. The estimates of financial exposure to market risk discussed below
do not represent the company’s projection of future market changes. The actual impact of future
market changes could differ materially due to factors discussed elsewhere in this report, including
those set forth under the heading “Risk Factors” in Part I, Item 1A, of the company’s 2009 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
these activities were not material to the company’s financial position, results of operations or
cash flows in 2009.
The company’s market exposure positions are monitored and managed on a daily basis by an
internal Risk Control group in accordance with the company’s risk management policies, which have
been approved by the Audit Committee of the company’s Board of Directors.
The derivative commodity instruments used in the company’s risk management and trading
activities consist mainly of futures, options and swap contracts traded on the New York Mercantile
Exchange and on electronic platforms of the Inter-Continental Exchange and Chicago Mercantile
Exchange. In addition, crude oil, natural gas and refined-product swap contracts and option
contracts are entered into principally with major financial institutions and other oil and gas
companies in the “over-the-counter” markets.
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 Chevron’s derivative commodity
instruments in 2009 was a quarterly average decrease of $168 million in total assets and a
quarterly average decrease of $104 million in total liabilities. The company uses a Value-at-Risk
(VaR) model to estimate the potential loss in fair value on a single day from the effect of adverse
changes in market conditions on derivative commodity instruments held or issued, which are recorded
on the balance sheet at December 31, 2009, as derivative commodity instruments in accordance with
accounting standards for derivatives (ASC 815). VaR is the maximum loss not to be exceeded within a
given probability or confidence level over a given period of time. The company’s 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 portfolio’s 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
company’s 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 company’s primary risk exposures in the area of derivative
commodity instruments at December 31, 2009 and 2008. The lower amounts in 2009 were primarily
associated with a decrease in price volatility for these commodities during the year.
Millions of dollars
2009
2008
Crude Oil
$
17
$
39
Natural Gas
4
5
Refined Products
19
45
Foreign CurrencyThe company may enter into foreign-currency derivative contracts to
manage some of its foreign-currency exposures. These exposures include revenue and anticipated
purchase transactions, including foreign-currency capital expenditures and lease commitments. The
foreign-currency derivative contracts, if any, are recorded at fair value on the balance sheet with
resulting gains and losses reflected in income. There were no open foreign-currency derivative
contracts at December 31, 2009.
Interest RatesThe company may enter into interest rate swaps from time to time as part of its
overall strategy to manage the interest rate risk on its debt. Historically, under the terms of the
swaps, net cash settlements were 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 company’s fixed-rate debt, if any, may be accounted for as fair –
value hedges. Interest rate swaps related to floating-rate debt, if any, are recorded at fair value
on the balance sheet with resulting gains and losses reflected in income. At year-end 2009, the
company had no interest rate swaps on floating-rate debt. The company’s only interest rate swaps on
fixed-rate debt matured in January 2009 and the company had no interest rate swaps on
fixed-rate
debt at year-end 2009.
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 Financial Information in Note 24 of the Consolidated Financial
Statements, page FS-61, 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. Chevron is a party to 50 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 company’s ultimate exposure
related to pending lawsuits and claims is not 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.
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 Texpet’s 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; 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 Texpet’s remediation was properly conducted and that the
remaining environmental damage reflects Petroecuador’s failure to timely fulfill its legal
obligations and Petroecuador’s 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 engineer’s report also asserted that an additional $8.3 billion could be assessed
against Chevron for unjust enrichment. The engineer’s report is not binding on the court. Chevron
also believes that the engineer’s work
Management’s Discussion and Analysis of
Financial Condition and Results of Operations
was performed and his report prepared in a manner contrary to law and in violation of
the court’s 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, which the court
dismissed. In September 2009, following the disclosure by Chevron of evidence that the judge
participated in meetings in which businesspeople and individuals holding themselves out as
government officials discussed the case and its likely outcome, the judge presiding over the case
petitioned to be recused. In late September 2009, the judge was recused, and in October 2009, the
full chamber of the provincial court affirmed the recusal, resulting in the appointment of a new
judge. Chevron filed motions to annul all of the rulings made by the prior judge, but the new judge
denied these motions. The court has completed most of the procedural aspects of the case and could
render a judgment at any time. Chevron will continue a vigorous defense of any attempted imposition
of liability.
In the event of an adverse judgment, Chevron would expect to pursue its appeals and vigorously
defend against enforcement of any such judgment; therefore, the ultimate outcome – and any
financial effect on Chevron – remains uncertain. 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 engineer’s report, management does not believe the report 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).
EnvironmentalThe company is subject to loss contingencies pursuant to laws, regulations,
private claims and legal proceedings related to environmental matters that are subject to legal
settlements or that in the future may require the company to take action to correct or ameliorate
the effects on the environment of prior release of chemicals or petroleum substances, including
MTBE, by the company or other parties. Such contingencies may exist for various sites, including,
but not limited to, federal Superfund sites and analogous sites under state laws, refineries,
crude-oil fields, service stations, terminals, land development areas, and mining operations,
whether operating, closed or divested. These future costs are not fully determinable due to such
factors as the unknown magnitude of possible contamination, the unknown timing and extent of the
corrective actions that may be required, the
determination of the company’s 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 company’s competitive position relative to
other U.S. or international petroleum or chemical companies.
The following table displays the annual changes to the company’s before-tax environmental
remediation reserves, including those for federal Superfund sites and analogous sites under state
laws.
Millions of dollars
2009
2008
2007
Balance at January 1
$
1,818
$
1,539
$
1,441
Net Additions
351
784
562
Expenditures
(469
)
(505
)
(464
)
Balance at December 31
$
1,700
$
1,818
$
1,539
Included in the $1,700 million year-end 2009 reserve balance were remediation activities
at approximately 250 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
company’s remediation reserve for these sites at year-end 2009 was $185 million. The federal
Superfund law and analogous state laws provide for joint and several liability for all responsible
parties. Any future actions by the EPA or other regulatory agencies to require Chevron to assume
other potentially responsible parties’ costs at designated hazardous waste sites are not expected
to have a material effect on the company’s results of operations, consolidated financial position
or liquidity.
Of the remaining year-end 2009 environmental reserves balance of $1,515 million, $820 million
related to the company’s U.S. downstream operations, including refineries and other plants,
marketing locations (i.e., service stations and terminals), and pipelines. The remaining $695
million was associated with various sites in international downstream ($107 million), upstream
($369 million), chemicals ($149 million) and other businesses ($70 million). Liabilities at all
sites, whether operating, closed or divested, were primarily associated with the company’s plans
and activities to remediate soil or groundwater contamination or both. These and other activities
include one or more of the following: site assessment; soil excavation; offsite disposal of
contaminants; onsite containment, remediation and/or extraction of petroleum hydrocarbon liquid and
vapor from soil; groundwater extraction and treatment; and monitoring of the natural attenuation of
the contaminants.
The company manages environmental liabilities under specific sets of regulatory requirements,
which in the United States include the Resource Conservation and Recovery Act and various state and
local regulations. No single remediation site at year-end 2009 had a recorded liability that was
material to the company’s results of operations, consolidated financial position or liquidity.
It is likely that the company will continue to incur additional liabilities, beyond those
recorded, for environmental remediation relating to past operations. These future costs are not
fully determinable due to such factors as the unknown magnitude of possible contamination, the
unknown timing and extent of the corrective actions that may be required, the determination of the
company’s liability in proportion to other responsible parties, and the extent to which such costs
are recoverable from third parties.
Under accounting standards for asset retirement obligations
(ASC 410), 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 reasonably estimated.
The liability balance of approximately $10.2 billion for asset retirement obligations at year-end
2009 related primarily to upstream properties.
For the company’s 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 23 on page FS-60, related to the company’s asset retirement obligations and
the discussion of “Environmental Matters” on page FS-18.
Income TaxesThe 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 15 beginning on page FS-46 for a discussion of the periods for which tax returns have
been audited for the company’s 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 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.
Suspended WellsThe 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, 2009, the company had approximately $2.4 billion of
suspended exploratory wells included in properties, plant and equipment, an increase of $317
million from 2008. The 2008 balance reflected an increase of $458 million from 2007.
The future trend of the company’s exploration expenses can be affected by amounts associated
with well write-offs, including wells that had been previously suspended pending determination as
to whether the well had found reserves that could be classified as proved. The effect on
exploration expenses in future periods of the $2.4 billion of suspended wells at year-end 2009 is
uncertain pending future activities, including normal project evaluation and additional drilling.
Refer to Note 19, beginning on page FS-50, 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 Chevron’s 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.
Management’s Discussion and Analysis of
Financial Condition and Results of Operations
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 considered
acceptable at the time but now require investigative or remedial work or both to meet current
standards.
Using definitions and guidelines established by the American Petroleum Institute, Chevron
estimated its worldwide environmental spending in 2009 at approximately $3.5 billion for its
consolidated companies. Included in these expenditures were approximately $1.7 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 2010, total worldwide environmental capital expenditures are estimated at $2.1 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 exist-
ing 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 company’s
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 company’s 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 management’s experience and other information available
prior to the issuance of the financial statements. Materially different results can occur as
circumstances change and additional information becomes known.
The discussion in this section of “critical” accounting estimates and assumptions is according
to the disclosure guidelines of the Securities and Exchange Commission (SEC), wherein:
1.
the nature of the estimates and assumptions is material due to the levels of
subjectivity and judgment necessary to account for highly uncertain matters or the
susceptibility of such matters to change; and
2.
the impact of the estimates and assumptions on the company’s financial condition or
operating performance is material.
Besides those meeting these “critical” criteria, the company makes many other accounting
estimates and assumptions in preparing its financial statements and related disclosures. Although
not associated with “highly uncertain matters,” these estimates and assumptions are also subject to
revision as circumstances warrant, and materially different results may sometimes occur.
For example, the recording of deferred tax assets requires an assessment under the accounting
rules that the future realization of the associated tax benefits be “more likely than not.” Another
example is the estimation of crude-oil and natural-gas reserves under SEC rules, which, effective
December 31, 2009, require “...by analysis of geosciences and engineering data, (the reserves) can be
estimated with reasonable certainty to be economically producible...under existing economic
conditions” where existing economic conditions include prices based on the average price during the
12-month period. Refer to Table V, “Reserve Quantity Information,” beginning on page FS-69,
for the changes in these estimates for the three years ending December 31, 2009, and to Table VII,
“Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves” on
page FS-77 for estimates of
proved-reserve values for each of the three years ended December 31,2009. 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 and assumptions, including those deemed
“critical,” and the associated disclosures in this discussion have been discussed by management
with the Audit Committee of the Board of Directors.
The areas of accounting and the associated “critical” estimates and assumptions made by the
company are as follows:
Pension and Other Postretirement Benefit Plans The determination of pension-plan obligations
and expense is based on a number of actuarial assumptions. Two critical assumptions are the
expected long-term rate of return on plan assets and the discount rate applied to pension plan
obligations. For other postretirement benefit (OPEB) plans, which provide for certain health care
and life insurance benefits for qualifying retired employees and which are not funded, critical
assumptions in determining OPEB obligations and expense are the discount rate and the assumed
health care
cost-trend rates.
Note 21, beginning on page FS-52, includes information on the funded status of the company’s
pension and OPEB plans at the end of 2009 and 2008; the components of pension and OPEB expense for
the three years ending December 31, 2009; and the underlying assumptions for those periods.
Pension and OPEB expense is reported on the Consolidated Statement of Income as “Operating
expenses” or “Selling, general and administrative expenses” and applies to all business segments.
The year-end 2009 and 2008 funded status, measured as the difference between plan assets and
obligations, of each of the company’s pension and OPEB plans is recognized on the Consolidated
Balance Sheet. The
differences related to overfunded pension plans are reported as a long-term asset in “Deferred
charges and other assets.” The differences associated with underfunded or unfunded pension and OPEB
plans are reported as “Accrued liabilities” or “Reserves for employee benefit plans.” Amounts yet
to be recognized as components of pension or OPEB expense are reported in “Accumulated other
comprehensive loss.”
To estimate the long-term rate of return on pension assets, the company uses a process that
incorporates actual historical asset-class returns and an assessment of expected future performance
and takes into consideration external actuarial advice and asset-class factors. Asset allocations
are periodically updated using pension plan asset/liability studies, and the determination of the
company’s 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 69 percent of the company’s
pension plan assets, has remained at 7.8 percent since 2002. For the 10 years ending December 31,2009, actual asset returns averaged 3.7 percent for this plan. The actual return for 2009 was 15.7
percent and was associated with the broad recovery in the financial markets.
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, 2009, the company selected a 5.3
percent discount rate for the major U.S. pension plan and 5.8 percent for its OPEB plan. These
rates were selected based on a cash flow analysis that matched estimated future benefit payments to
the Citigroup Pension Discount Yield Curve as of year-end 2009. The discount rates at the end of
2008 and 2007 were 6.3 percent for both years for the U.S. pension and OPEB plans.
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 2009 was $1.1 billion. As an
indication of the sensitivity of pension expense to the long-term rate of return assumption, a 1
percent increase in the expected rate of return on assets of the company’s primary U.S. pension
plan would have reduced total pension plan expense for 2009 by approximately $50 million. A 1
percent increase in the discount rate for this same plan, which accounted for about 61 percent of
the
Management’s Discussion and Analysis of
Financial Condition and Results of Operations
companywide pension obligation, would have reduced total pension plan expense for 2009
by approximately $150 million.
An increase in the discount rate would decrease the pension obligation, thus changing the
funded status of a plan reported on the Consolidated Balance Sheet. The total pension liability on
the Consolidated Balance Sheet at December 31, 2009, for underfunded plans was approximately $3.8
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 company’s primary U.S.
pension plan would have reduced the plan obligation by approximately $300 million, which would have
decreased the plan’s underfunded status from approximately $1.6 billion to $1.3 billion. Other
plans would be less underfunded as discount rates increase. The actual rates of return on plan
assets and discount rates may vary significantly from estimates because of unanticipated changes in
the world’s financial markets.
In 2009, the company’s pension plan contributions were $1.7 billion (including $1.5 billion to
the U.S. plans). In 2010, the company estimates contributions will be approximately $900 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.
For the company’s OPEB plans, expense for 2009 was $164 million and the total liability,
which reflected the unfunded status of the plans at the end of 2009, was $3.1 billion.
As an indication of discount rate sensitivity to the determination of OPEB expense in 2009, a
1 percent increase in the discount rate for the company’s primary U.S. OPEB plan, which accounted
for about 69 percent of the companywide OPEB expense, would have decreased OPEB expense by
approximately $11 million. A 0.25 percent increase in the discount rate for the same plan, which
accounted for about 84 percent of the companywide OPEB liabilities, would have decreased total OPEB
liabilities at the end of 2009 by approximately $65 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 2010 and gradually drop to 5 percent for 2018 and beyond. As an indication of the health
care cost-trend rate sensitivity to the determination of OPEB expense
in 2009, a 1 percent
increase in the rates for the main U.S. OPEB plan, which accounted for 84 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 21, beginning on page FS-52, for information on the $6.7 billion of before-tax actuarial
losses recorded by the company as of December 31, 2009; a description of the method used to
amortize those costs; and an estimate of the costs to be recognized in expense during 2010.
Impairment of Properties, Plant and Equipment and Investments in AffiliatesThe 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 company’s 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 company’s business plans and long-term investment decisions.
No major individual impairments of PP&E and Investments were recorded for the three years
ending December 31, 2009. A sensitivity analysis of the impact on earnings for these periods if
other assumptions had been used in impairment reviews and impairment calculations is not
practicable, given the broad range of the company’s 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 company’s 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 investment’s 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 investee’s financial
performance, and the company’s ability and intention to retain its investment for a period that
will be sufficient to allow for any anticipated recovery in the investment’s market value.
Differing assumptions could affect whether an investment is impaired in any period or the amount of
the impairment, and are not subject to sensitivity analysis.
From time to time, the company performs impairment reviews and determines whether any
write-down in the carrying value of an asset or asset group is required. For example, when
significant downward revisions to crude-oil and natural-gas reserves are made for any single field
or concession, an impairment review is performed to determine if the carrying value of the asset
remains recoverable. Also, if the expectation of sale of a particular asset or asset group in any
period has been deemed more likely than not, an impairment review is performed, and if the
estimated net proceeds exceed the carrying value of the asset or asset group, no impairment charge
is required. Such calculations are reviewed each period until the asset or asset group is disposed
of. Assets that are not impaired on a held-and-used basis could possibly become impaired if a
decision is made to sell such assets. That is, the assets would be impaired if they are classified
as held-for-sale and the estimated proceeds from the sale, less costs to sell, are less than the
assets’ associated carrying values.
Goodwill Goodwill resulting from a business combination is not subject to amortization. As
required by accounting standards for goodwill (ASC 350), the company tests such goodwill at the
reporting unit level for impairment on an annual basis and between annual tests if an event occurs
or circumstances change that would more likely than not reduce the fair value of a reporting unit
below its carrying amount.
Contingent Losses Management also makes judgments and estimates in recording liabilities for
claims, litigation, tax matters and environmental remediation. Actual costs can frequently vary
from estimates for a variety of reasons. For example, the costs from settlement of claims and
litigation can vary from estimates based on differing interpretations of laws, opinions on
culpability and assessments on the amount of damages. Similarly, liabilities for environmental
remediation are subject to change because of changes in laws, regulations and their interpretation,
the determination of
additional information on the extent and nature of site contamination, and improvements in
technology.
Under the accounting rules, a liability is generally recorded for these types of contingencies
if management determines the loss to be both probable and estimable. The company generally reports
these losses as “Operating expenses” or “Selling, general and administrative expenses” on the
Consolidated Statement of Income. An exception to this handling is for income tax matters, for
which benefits are recognized only if management determines the tax position is “more likely than
not” (i.e., likelihood greater than 50 percent) to be allowed by the tax jurisdiction. For
additional discussion of income tax uncertainties, refer to Note 15 beginning on page FS-46. Refer
also to the business segment discussions elsewhere in this section for the effect on earnings from
losses associated with certain litigation, environmental remediation and tax matters for the three
years ended December 31, 2009.
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
The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting
Principles – a replacement of FASB Statement No. 162 (FAS 168) In June 2009, the FASB issued FAS
168, which became effective for the company in the quarter ending September 30, 2009. This standard
established the FASB Accounting Standards Codification (ASC) system as the single authoritative
source of U.S. generally accepted accounting principles (GAAP) and superseded existing literature
of the FASB, Emerging Issues Task Force, American Institute of CPAs and other sources. The ASC did
not change GAAP, but organized the literature into about 90 accounting Topics. Adoption of the ASC
did not affect the company’s accounting.
Employer’s Disclosures About Postretirement Benefit Plan Assets (FSP FAS 132(R)-1) In December
2008, the FASB issued FSP FAS 132(R)-1, which was subsequently codified into ASC 715, Compensation
– Retirement Benefits, and became effective with the company’s reporting at December 31, 2009. This
standard amended and expanded the disclosure requirements for the plan assets of defined benefit
pension and other postretirement plans. Refer to information beginning on page FS-52 in Note 21,
Employee Benefits, for these disclosures.
Transfers and Servicing (ASC 860), Accounting for Transfers of Financial Assets (ASU 2009-16)
The FASB issued ASU 2009-16 in December 2009. This standard became effective for the company on
January 1, 2010. ASU 2009-16
changes how companies account for transfers of financial assets and eliminates the concept of
qualifying special-purpose entities. Adoption of the guidance is not expected to have an impact on
the company’s results of operations, financial position or liquidity.
Consolidation (ASC 810), Improvements to Financial Reporting by Enterprises Involved With
Variable Interest Entities (ASU 2009-17) The FASB issued ASU 2009-17 in December 2009. This
standard became effective for the companyJanuary 1, 2010. ASU 2009-17 requires the enterprise to
qualitatively assess if it is the primary beneficiary of a variable-interest entity (VIE), and, if
so, the VIE must be consolidated. Adoption of the standard is not expected to have a material
impact on the company’s results of operations, financial position or liquidity.
Extractive
Industries – Oil and Gas (ASC 932), Oil and Gas Reserve Estimation and Disclosures
(ASU 2010-03) In January 2010, the FASB issued ASU 2010-03, which became effective for the company
on December 31, 2009. The standard amends certain sections of
ASC 932, Extractive Industries – Oil
and Gas, to align them with the requirements in the Securities and Exchange Commission’s final
rule, Modernization of the Oil and Gas Reporting Requirements (the final rule). The final rule was
issued on December 31, 2008. Refer to Table V – Reserve Quantity Information, beginning on page
FS-69, for additional information on the final rule and the impact of adoption.
Less: Net income attributable to noncontrolling interests
32
15
16
17
6
32
34
28
Net Income Attributable to Chevron Corporation
$
3,070
$
3,831
$
1,745
$
1,837
$
4,895
$
7,893
$
5,975
$
5,168
Per-Share of Common Stock
Net Income Attributable to Chevron Corporation
– Basic
$
1.54
$
1.92
$
0.88
$
0.92
$
2.45
$
3.88
$
2.91
$
2.50
– Diluted
$
1.53
$
1.92
$
0.87
$
0.92
$
2.44
$
3.85
$
2.90
$
2.48
Dividends
$
0.68
$
0.68
$
0.65
$
0.65
$
0.65
$
0.65
$
0.65
$
0.58
Common Stock Price Range – High2
$
79.64
$
72.64
$
72.67
$
77.35
$
82.20
$
99.08
$
103.09
$
94.61
– Low2
$
68.14
$
61.40
$
63.75
$
56.46
$
57.83
$
77.50
$
86.74
$
77.51
1 Includes excise, value-added
and similar taxes:
$
2,086
$
2,079
$
2,034
$
1,910
$
2,080
$
2,577
$
2,652
$
2,537
2 End of day price.
The company’s common stock is listed on the New York Stock Exchange (trading symbol:
CVX). As of February 19, 2010, stockholders of record numbered approximately 195,000. There
are no restrictions on the company’s ability to pay dividends.
Management’s 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 management’s best estimates and judgment.
As stated in its report included herein, the independent registered public accounting firm of
PricewaterhouseCoopers LLP has audited the company’s 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.
Management’s Report on Internal Control Over Financial Reporting
The company’s management is responsible for establishing and maintaining adequate internal control
over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). The company’s
management, including the Chief Executive Officer and Chief Financial Officer, conducted an
evaluation of the effectiveness of the company’s internal control over financial reporting based on
the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of
the Treadway Commission. Based on the results of this evaluation, the company’s management
concluded that internal control over financial reporting was effective as of December 31, 2009.
The effectiveness of the company’s internal control over financial reporting as of
December 31, 2009, has been audited by PricewaterhouseCoopers LLP, an independent registered
public accounting firm, as stated in its report included herein.
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, equity and cash flows present fairly, in all material
respects, the financial position of Chevron Corporation and its subsidiaries at December 31, 2009
and December 31, 2008 and the results of their operations and their cash flows for each of the
three years in the period ended December 31, 2009 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, 2009 based on
criteria established in Internal Control – Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO). The Company’s 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 Management’s 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 Company’s internal control over financial reporting
based on our integrated audits. We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those standards require that we plan and
perform the audits to obtain reasonable assurance about whether the financial statements are free
of material misstatement and whether effective internal control over financial reporting was
maintained in all material respects. Our audits of the financial statements included examining, on
a test basis, evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. Our
audit of
internal control over financial reporting included obtaining an understanding of internal
control over financial reporting, assessing the risk that a material weakness exists, and testing
and evaluating the design and operating effectiveness of internal control based on the assessed
risk. Our audits also included performing such other procedures as we considered necessary in the
circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s 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 company’s 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 company’s 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.
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 1
Summary of Significant Accounting Policies
General Exploration and production (upstream) operations consist of exploring for, developing and
producing crude oil and natural gas and 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.
The company’s Consolidated Financial Statements are prepared in accordance with accounting
principles generally accepted in the United States of America. These require the use of estimates
and assumptions that affect the assets, liabilities, revenues and expenses reported in the
financial statements, as well as amounts included in the notes thereto, including discussion and
disclosure of contingent liabilities. Although the company uses its best estimates and judgments,
actual results could differ from these estimates as future confirming events occur.
The nature of the company’s operations and the many countries in which it operates subject the
company to changing economic, regulatory and political conditions. The company does not believe it
is vulnerable to the risk of near-term severe impact as a result of any concentration of its
activities.
Subsidiary and Affiliated Companies The Consolidated Financial Statements include the accounts of
controlled subsidiary companies more than 50 percent-owned and variable-interest entities in which
the company is the primary beneficiary. Undivided interests in oil and gas joint ventures and
certain other assets are consolidated on a proportionate basis. Investments in and advances to
affiliates in which the company has a substantial ownership interest of approximately 20 percent to
50 percent or for which the company exercises significant influence but not control over policy
decisions are accounted for by the equity method. As part of that accounting, the company
recognizes gains and losses that arise from the issuance of stock by an affiliate that results in
changes in the company’s proportionate share of the dollar amount of the affiliate’s equity
currently in income.
Investments are assessed for possible impairment when events indicate that the fair value of
the investment may be below the company’s carrying value. When such a condition is deemed to be
other than temporary, the carrying value of the investment is written down to its fair value, and
the amount of the write-down is included in net income. In making the determination as to whether a
decline is other than temporary, the company considers such factors as the
duration and extent of the decline, the investee’s financial performance, and the company’s ability
and intention to retain its investment for a period that will be sufficient to allow for any
anticipated recovery in the investment’s market value. The new cost basis of investments in these
equity investees is not changed for subsequent recoveries in fair value.
Differences between the company’s carrying value of an equity investment and its underlying
equity in the net assets of the affiliate are assigned to the extent practicable to specific assets
and liabilities based on the company’s analysis of the various factors giving rise to the
difference. When appropriate, the company’s share of the affiliate’s reported earnings is adjusted
quarterly to reflect the difference between these allocated values and the affiliate’s historical
book values.
Derivatives The majority of the company’s activity in derivative commodity instruments is intended
to manage the financial risk posed by physical transactions. For some of this derivative activity,
generally limited to large, discrete or infrequently occurring transactions, the company may elect
to apply fair value or cash flow hedge accounting. For other similar derivative instruments,
generally because of the short-term nature of the contracts or their limited use, the company does not apply hedge accounting, and
changes in the fair value of those contracts are reflected in current income. For the company’s
commodity trading activity and foreign currency exposures, gains and losses from derivative
instruments are reported in current income. Interest rate swaps – hedging a portion of the
company’s fixed-rate debt – are accounted for as fair value hedges, whereas interest rate swaps
relating to a portion of the company’s floating-rate debt are recorded at fair value on the
Consolidated Balance Sheet, with resulting gains and losses reflected in income. Where Chevron is a
party to master netting arrangements, fair value receivable and payable amounts recognized for
derivative instruments executed with the same counterparty are offset on the balance sheet.
Short-Term Investments All short-term investments are classified as available for sale and are in
highly liquid debt securities. Those investments that are part of the company’s cash management
portfolio and have original maturities of three months or less are reported as “Cash equivalents.”
The balance of the short-term investments is reported as “Marketable securities” and is
marked-to-market, with any unrealized gains or losses included in “Other comprehensive income.”
Inventories Crude oil, petroleum products and chemicals are generally stated at cost, using a
Last-In, First-Out (LIFO) method. In the aggregate, these costs are below market. “Materials,
supplies and other” inventories generally are stated at average cost.
Note 1 Summary of Significant Accounting Policies - Continued
Properties, Plant and Equipment The successful efforts method is used for crude-oil and natural-gas
exploration and production activities. All costs for development wells, related plant and
equipment, proved mineral interests in crude oil and natural gas properties, and related asset
retirement obligation (ARO) assets are capitalized. Costs of exploratory wells are capitalized
pending determination of whether the wells found proved reserves. Costs of wells that are assigned
proved reserves remain capitalized. Costs also are capitalized for exploratory wells that have
found crude-oil and natural gas reserves even if the reserves cannot be classified as proved when
the drilling is completed, provided the exploratory well has found a sufficient quantity of
reserves to justify its completion as a producing well and the company is making sufficient
progress assessing the reserves and the economic and operating viability of the project. All other
exploratory wells and costs are expensed. Refer to Note 19, beginning on page FS-50, for additional
discussion of accounting for suspended exploratory well costs.
Long-lived assets to be held and used, including proved crude-oil and natural-gas properties,
are assessed for possible impairment by comparing their carrying values with their associated
undiscounted future net before-tax cash flows. Events that can trigger assessments for possible
impairments include write-downs of proved reserves based on field performance, significant
decreases in the market value of an asset, significant change in the extent or manner of use of or
a physical change in an asset, and a more-likely-than-not expectation that a long-lived asset or
asset group will be sold or otherwise disposed of significantly sooner than the end of its
previously estimated useful life. Impaired assets are written down to their estimated fair values,
generally their discounted future net before-tax cash flows. For proved crude-oil and natural-gas
properties in the United States, the company generally performs the impairment review on an
individual field basis. Outside the United States, reviews are performed on a country, concession,
development area or field basis, as appropriate. In the refining, marketing, transportation and
chemicals areas, impairment reviews are generally done on the basis of a refinery, a plant, a
marketing area or marketing assets by country. Impairment amounts are recorded as incremental
“Depreciation, depletion and amortization” expense.
Long-lived assets that are held for sale are evaluated for possible impairment by comparing
the carrying value of the asset with its fair value less the cost to sell. If the net book value
exceeds the fair value less cost to sell, the asset is considered impaired and adjusted to the
lower value.
As required under accounting standards for asset retirement and environmental obligations
(Accounting Standards Codification (ASC) 410), the fair value of a liability for an ARO is recorded
as an asset and a liability when there is a
legal obligation associated with the retirement of a long-lived asset and the amount can be
reasonably estimated. Refer also to Note 23, on page FS-60, relating to AROs.
Depreciation and depletion of all capitalized costs of proved crude-oil and natural-gas
producing properties, except mineral interests, are expensed using the unit-of-production method
generally by individual field, as the proved developed reserves are produced. Depletion expenses
for capitalized costs of proved mineral interests are recognized using the unit-of-production
method by individual field as the related proved reserves are produced. Periodic valuation
provisions for impairment of capitalized costs of unproved mineral interests are expensed.
Depreciation and depletion expenses for mining assets are determined using the
unit-of-production method as the proved reserves are produced. The capitalized costs of all other
plant and equipment are depreciated or amortized over their estimated useful lives. In general, the
declining-balance method is used to depreciate plant and equipment in the United States; the
straight-line method generally is used to depreciate international plant and equipment and to
amortize all capitalized leased assets.
Gains or losses are not recognized for normal retirements of properties, plant and equipment
subject to composite group amortization or depreciation. Gains or losses from abnormal retirements
are recorded as expenses and from sales as “Other income.”
Expenditures for maintenance (including those for
planned major maintenance projects), repairs and minor renewals to maintain facilities in operating
condition are generally expensed as incurred. Major replacements and renewals are capitalized.
Goodwill Goodwill resulting from a business combination is not subject to amortization. As required
by accounting standards for goodwill (ASC 350), the company tests such goodwill at the reporting
unit level for impairment on an annual basis and between annual tests if an event occurs or
circumstances change that would more likely than not reduce the fair value of a reporting unit
below its carrying amount.
Environmental Expenditures Environmental expenditures that relate to ongoing operations or to
conditions caused by past operations are expensed. Expenditures that create future benefits or
contribute to future revenue generation are capitalized.
Liabilities related to future remediation costs are recorded when environmental assessments or
cleanups or both are probable and the costs can be reasonably estimated. For the company’s U.S. and
Canadian marketing facilities, the accrual is based in part on the probability that a future
remediation commitment will be required. For crude-oil, natural-gas and mineral-producing
properties, a liability for an ARO is made,
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 1 Summary of Significant Accounting Policies - Continued
following accounting standards for asset retirement and environmental obligations. Refer to Note
23, on page FS-60, for a discussion of the company’s AROs.
For federal Superfund sites and analogous sites under state laws, the company records a
liability for its designated share of the probable and estimable costs and probable amounts for
other potentially responsible parties when mandated by the regulatory agencies because the other
parties are not able to pay their respective shares.
The gross amount of environmental liabilities is based on the company’s best estimate of
future costs using currently available technology and applying current regulations and the
company’s own internal environmental policies. Future amounts are not discounted. Recoveries or
reimbursements are recorded as assets when receipt is reasonably assured.
Currency Translation The U.S. dollar is the functional currency for substantially all of the
company’s consolidated operations and those of its equity affiliates. For those operations, all
gains and losses from currency translations are currently included in income. The cumulative
translation effects for those few entities, both consolidated and affiliated, using functional
currencies other than the U.S. dollar are included in “Currency translation adjustment” on the
Consolidated Statement of Equity.
Revenue Recognition Revenues associated with sales of crude oil, natural gas, coal, petroleum and
chemicals products, and all other sources are recorded when title passes to the customer, net of
royalties, discounts and allowances, as applicable. Revenues from natural gas production from
properties in which Chevron has an interest with other producers are generally recognized on the
entitlement method. Excise, value-added and similar taxes assessed by a governmental authority on a
revenue-producing transaction between a seller and a customer are presented on a gross basis. The
associated amounts are shown as a footnote to the Consolidated Statement of Income on page FS-27.
Purchases and sales of inventory with the same counterparty that are entered into in contemplation
of one another (including buy/sell arrangements) are combined and recorded on a net basis and
reported in “Purchased crude oil and products” on the Consolidated Statement of Income.
Stock Options and Other Share-Based Compensation The company issues stock options and other
share-based compensation to its employees and accounts for these transactions under the accounting
standards for share-based compensation (ASC 718). For equity awards, such as stock options, total
compensation cost is based on the grant date fair value
and for liability awards, such as stock appreciation rights, total compensation cost is based on
the settlement value. The company recognizes stock-based compensation expense for all awards over
the service period required to earn the award, which is the shorter of the vesting period or the
time period an employee becomes eligible to retain the award at retirement. Stock options and stock
appreciation rights granted under the company’s Long-Term Incentive Plan have graded vesting
provisions by which one-third of each award vests on the first, second and third anniversaries of
the date of grant. The company amortizes these graded awards on a straight-line basis.
Note 2
Noncontrolling Interests
The company adopted accounting standards for noncontrolling interests (ASC 810) in the
consolidated financial statements effective January 1, 2009, and retroactive to the earliest period
presented. Ownership interests in the company’s subsidiaries held by parties other than the parent
are presented separately from
the parent’s equity on the Consolidated Balance Sheet. The amount of consolidated net income
attributable to the parent and the noncontrolling interests are both presented on the face of the
Consolidated Statement of Income. The term “earnings” is defined as “Net Income Attributable to
Chevron Corporation.”
Activity for the equity attributable to noncontrolling interests for 2009,
2008 and 2007 is as follows:
2009
2008
2007
Balance at January 1
$
469
$
204
$
209
Net income
80
100
107
Distributions to noncontrolling interests
(71
)
(99
)
(77
)
Other changes, net
169
264
(35
)
Balance at December 31
$
647
$
469
$
204
Note 3
Equity
Retained earnings at December 31, 2009 and 2008, included approximately $8,122 and $7,951,
respectively, for the company’s share of undistributed earnings of equity affiliates.
At December 31, 2009, about 94 million shares of Chevron’s common stock remained available for
issuance from the 160 million shares that were reserved for issuance under the Chevron Corporation
Long-Term Incentive Plan (LTIP). In addition, approximately 342,000 shares remain available for
issuance from the 800,000 shares of the company’s common stock that were reserved for awards under
the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan
(Non-Employee
Directors’ Plan).
Information Relating to the Consolidated Statements of Cash Flows
Year ended December 31
2009
2008
2007
Net
(increase) decrease in operating working
capital was composed of the following:
(Increase)
decrease in accounts and
notes receivable
$
(1,476
)
$
6,030
$
(3,867
)
Decrease (increase) in inventories
1,213
(1,545
)
(749
)
Increase in
prepaid expenses and
other current assets
(264
)
(621
)
(370
)
(Decrease) increase in accounts
payable and accrued liabilities
(1,121
)
(4,628
)
4,930
(Decrease)
increase in income and
other taxes payable
(653
)
(909
)
741
Net
(increase) decrease in operating
working capital
$
(2,301
)
$
(1,673
)
$
685
Net cash
provided by operating
activities includes the following
cash payments for interest and
income taxes:
Interest paid on debt
(net of capitalized interest)
$
–
$
–
$
203
Income taxes
$
7,537
$
19,130
$
12,340
Net sales of
marketable securities
consisted of the following
gross amounts:
Marketable securities sold
$
157
$
3,719
$
2,160
Marketable securities purchased
(30
)
(3,236
)
(1,975
)
Net sales of marketable securities
$
127
$
483
$
185
In accordance with accounting standards for cash-flow classifications for stock options (ASC
718), the “Net (increase) decrease in operating working capital” includes reductions of $25, $106
and $96 for excess income tax benefits associated with stock options exercised during 2009, 2008
and 2007, respectively. These amounts are offset by an equal amount in “Net sales (purchases) of
treasury shares.”
The “Net sales (purchases) of treasury shares” represents the cost of common shares purchased less
the cost of shares issued for
share-based compensation plans. Purchases totaled $6, $8,011 and
$7,036 in 2009, 2008 and 2007, respectively. Purchases in 2008 and 2007 included shares purchased
under the company’s common stock repurchase programs.
In 2009, “Net sales (purchases) of other short-term investments” consisted of $123 in
restricted cash associated with
capital-investment projects at the company’s Pascagoula,
Mississippi refinery and the Angola liquefied-natural-gas project that was invested in short-term
securities and reclassified from “Cash and cash equivalents” to “Deferred charges and other assets”
on the Consolidated Balance Sheet. The company issued $350 and $650, in 2009 and 2007 respectively,
of tax exempt Mississippi Gulf Opportunity Zone Bonds as a source of funds for Pascagoula Refinery
projects.
The Consolidated Statement of Cash Flows for 2009 excludes changes to the Consolidated Balance
Sheet that did not affect cash. In 2008, “Net sales (purchases) of treasury shares” excludes $680 of treasury
shares acquired in exchange for a U.S. upstream property and $280 in cash. The carrying value of
this property in “Properties, plant and equipment” on the Consolidated Balance Sheet was not
significant. In 2008, a $2,450 increase in “Accrued liabilities” and a corresponding increase to
“Properties, plant and equipment, at cost” were considered non-cash transactions and excluded from
“Net (increase) decrease in operating
working
capital” and “Capital expenditures.” In 2009, the payments related to these “Accrued
liabilities” were excluded from “Net (increase) decrease in operating working capital” and were
reported as “Capital expenditures.” The amount is related to upstream operating agreements outside
the United States. “Capital expenditures” in 2008 excludes a $1,400 increase in “Properties, plant
and equipment” related to the acquisition of an additional interest in an equity affiliate that
required a change to the consolidated method of accounting for the investment during 2008. This
addition was offset primarily by reductions in “Investments and advances” and working capital and
an increase in “Non-current deferred income tax” liabilities. Refer also to Note 23, on page FS-60,
for a discussion of revisions to the company’s AROs that also did not involve cash receipts or
payments for the three years ending December 31, 2009.
The major components of “Capital expenditures” and the reconciliation of this amount to the
reported capital and exploratory expenditures, including equity affiliates, are presented in the
following table:
Year ended December 31
2009
2008
2007
Additions to properties, plant
and equipment1
$
16,107
$
18,495
$
16,127
Additions to investments
942
1,051
881
Current-year dry-hole expenditures
468
320
418
Payments for other liabilities
and assets, net2
2,326
(200
)
(748
)
Capital expenditures
19,843
19,666
16,678
Expensed exploration expenditures
790
794
816
Assets acquired through capital
lease obligations and other
financing obligations
19
9
196
Capital and exploratory expenditures,
excluding equity affiliates
20,652
20,469
17,690
Company’s share of expenditures
by equity affiliates
1,585
2,306
2,336
Capital and exploratory expenditures,
including equity affiliates
$
22,237
$
22,775
$
20,026
1 Excludes noncash additions of $985 in 2009, $5,153 in 2008 and $3,560 in 2007.
2 2009 includes payments of $2,450 for accruals recorded in 2008.
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 5
Summarized Financial Data – Chevron U.S.A. Inc.
Chevron U.S.A. Inc. (CUSA) is a major subsidiary of Chevron Corporation. CUSA and its subsidiaries
manage and operate most of Chevron’s U.S. businesses. Assets include those related to the
exploration and production of crude oil, natural gas and natural gas liquids and those associated
with the refining, marketing, supply and distribution of products derived from petroleum, excluding
most of the regulated pipeline operations of Chevron. CUSA also holds the company’s investment in
the Chevron Phillips Chemical Company LLC joint venture, which is accounted for using the equity
method.
During 2008, Chevron implemented legal reorganizations in which certain Chevron subsidiaries
transferred assets to or under CUSA. The summarized financial information for CUSA and its
consolidated subsidiaries presented in the table below gives retroactive effect to the
reorganizations as if they had occurred on January 1, 2007. However, the financial information in
the following table may not reflect the financial position and operating results in the future or
the historical results in the periods presented if the reorganization actually had occurred on that
date. The summarized financial information for CUSA and its consolidated subsidiaries is as
follows:
Year ended December 31
2009
2008
2007
Sales and other operating
revenues
$
121,553
$
195,593
$
153,574
Total costs and other deductions
120,053
185,788
147,509
Net income attributable to CUSA
1,141
7,318
5,191
At December 31
2009
2008
Current assets
$
23,286
$
32,760
Other assets
32,827
31,806
Current liabilities
16,098
14,322
Other liabilities
14,625
14,049
Total CUSA net equity
25,390
36,195
Memo: Total debt
$6,999
$ 6,813
The amount for the years ended December 31, 2008, and December 31, 2007, for “Net income
attributable to CUSA” and the balances at December 31, 2008, for “Other liabilities” and “Total
CUSA net equity” have been adjusted by immaterial amounts associated with the allocation of
income-tax liabilities among Chevron Corporation subsidiaries.
Note 6
Summarized Financial Data – Chevron Transport Corporation Ltd.
Chevron Transport Corporation Ltd. (CTC), incorporated in Bermuda, is an indirect, wholly owned
subsidiary of
Chevron Corporation. CTC is the principal operator of Chevron’s international tanker
fleet and is engaged in the marine transportation of crude oil and refined petroleum products. Most
of CTC’s shipping revenue is derived from providing transportation services to other Chevron
companies. Chevron Corporation has fully and unconditionally guaranteed this subsidiary’s
obligations in connection with certain debt securities issued by a third party. Summarized
financial information for CTC and its consolidated subsidiaries is as follows:
Year ended December 31
2009
2008
2007
Sales and other operating revenues
$
683
$
1,022
$
667
Total costs and other deductions
810
947
713
Net income attributable to CTC
(124
)
120
(39
)
At December 31
2009
2008
Current assets
$
377
$
482
Other assets
173
172
Current liabilities
115
98
Other liabilities
90
88
Total CTC net equity
345
468
There were no restrictions on CTC’s ability
to pay dividends or make loans or advances at
December 31, 2009.
Note 7
Summarized Financial Data – Tengizchevroil LLP
Chevron has a 50 percent equity ownership interest in Tengizchevroil LLP (TCO). Refer to Note 12,
on page FS-43, for a discussion of TCO operations.
Summarized financial information for 100 percent of TCO is presented in the following table:
Certain noncancelable leases are classified as capital leases, and the leased assets are included
as part of “Properties, plant and equipment, at cost” on the Consolidated Balance Sheet. Such
leasing arrangements involve tanker charters, crude-oil production and processing equipment,
service stations, office buildings, and other facilities. Other leases are classified as operating
leases and are not capitalized. The payments on such leases are recorded as expense. Details of the
capitalized leased assets are as follows:
At December 31
2009
2008
Upstream
$
510
$
491
Downstream
332
399
Chemicals and all other
171
171
Total
1,013
1,061
Less: Accumulated amortization
585
522
Net capitalized leased assets
$
428
$
539
Rental expenses incurred for operating
leases during 2009, 2008 and 2007 were as follows:
Year ended December 31
2009
2008
2007
Minimum rentals
$
2,179
$
2,984
$
2,419
Contingent rentals
7
6
6
Total
2,186
2,990
2,425
Less: Sublease rental income
41
41
30
Net rental expense
$
2,145
$
2,949
$
2,395
Contingent rentals are based on factors other than the passage of time, principally sales
volumes at leased service stations. Certain leases include escalation clauses for adjusting rentals
to reflect changes in price indices, renewal options ranging up to 25 years, and options to
purchase the leased property during or at the end of the initial or renewal lease period for the
fair market value or other specified amount at that time.
At December 31, 2009, the estimated future minimum lease payments (net of noncancelable
sublease rentals) under operating and capital leases, which at inception had a non-cancelable term
of more than one year, were as follows:
At December 31
Operating
Capital
Leases
Leases
Year: 2010
568
90
2011
438
81
2012
406
87
2013
372
60
2014
347
44
Thereafter
1,233
137
Total
$
3,364
$
499
Less: Amounts representing interest
and executory costs
(104
)
Net present values
395
Less: Capital lease obligations
included in short-term debt
(94
)
Long-term capital lease obligations
$
301
Note 9
Fair Value Measurements
Accounting standards for fair-value measurement (ASC 820) establish a framework for measuring fair
value and stipulate disclosures about fair-value measurements. The standards apply to recurring and
nonrecurring financial and nonfinancial assets and liabilities that require or permit fair-value
measurements. ASC 820 became effective for Chevron on January 1, 2008, for all financial assets and
liabilities and recurring nonfinancial assets and liabilities. On January 1, 2009, the standard
became effective for nonrecurring nonfinancial assets and liabilities. Among the required
disclosures is the fair-value hierarchy of inputs the company uses to value an asset or a
liability. The three levels of the fair-value hierarchy are described as follows:
Level 1: Quoted prices (unadjusted) in active markets for identical assets and liabilities. For the
company, Level 1 inputs include exchange-traded futures contracts for which the parties are willing
to transact at the exchange-quoted price and marketable securities that are actively traded.
Level 2: Inputs other than Level 1 that are observable, either directly or indirectly. For the
company, Level 2 inputs include quoted prices for similar assets or liabilities, prices obtained
through third-party broker quotes, and prices that can be corroborated with other observable inputs
for substantially the complete term of a contract.
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 9 Fair Value Measurements - Continued
Level 3: Unobservable inputs. The company does not use Level 3 inputs for any of its recurring
fair-value measurements. Level 3 inputs may be required for the determination of fair value
associated with certain nonrecurring measurements of nonfinancial assets and liabilities. In 2009,
the company used Level 3 inputs to determine the fair value of certain nonrecurring nonfinancial
assets.
The fair-value hierarchy for recurring assets and liabilities measured at fair value at
December 31, 2009, and December 31, 2008, is as follows:
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Prices in Active
Prices in Active
Markets for
Other
Markets for
Other
Identical
Observable
Unobservable
Identical
Observable
Unobservable
At December 31
Assets/Liabilities
Inputs
Inputs
At December 31
Assets/Liabilities
Inputs
Inputs
2009
(Level 1)
(Level 2)
(Level 3)
2008
(Level 1)
(Level 2)
(Level 3)
Marketable Securities
$
106
$
106
$
–
$
–
$
213
$
213
$
–
$
–
Derivatives
127
14
113
–
805
529
276
–
Total Recurring Assets
at Fair Value
$
233
$
120
$
113
$
–
$
1,018
$
742
$
276
$
–
Derivatives
$
101
$
20
$
81
$
–
$
516
$
98
$
418
$
–
Total Recurring
Liabilities
at Fair Value
$
101
$
20
$
81
$
–
$
516
$
98
$
418
$
–
Marketable Securities The company calculates fair value for its marketable securities based on
quoted market prices for identical assets and liabilities. The fair values reflect the cash that
would have been received if the instruments were sold at December 31, 2009. Marketable securities
had average maturities of less than one year.
Derivatives The company records its derivative
instruments – other than any commodity derivative
contracts that are designated as normal purchase and normal sale – on the Consolidated Balance
Sheet at fair value, with virtually all the offsetting amount to the Consolidated Statement of
Income. For derivatives with identical or similar provisions as contracts that are publicly traded
on a regular basis, the company uses the market values of the publicly traded instruments as an
input for fair-value calculations.
The company’s derivative instruments principally include crude-oil, natural-gas and
refined-product futures, swaps, options and forward contracts. Derivatives classified as Level 1
include futures, swaps and options contracts traded in active markets such as the New York
Mercantile Exchange.
Derivatives classified as Level 2 include swaps, options, and forward contracts principally
with financial institutions and other oil and gas companies, the fair values for which are obtained
from third-party broker quotes, industry pric-
ing services and exchanges. The company obtains multiple sources of pricing information for the
Level 2 instruments. Since this pricing information is generated from observable market data, it
has historically been very consistent. The company does not materially adjust this information. The
company incorporates internal review, evaluation and assessment procedures, including a comparison
of Level 2 fair values derived from the company’s internally developed forward curves (on a sample
basis) with the pricing information to document reasonable, logical and supportable fair-value
determinations and proper level of classification.
Impairments of “Properties, plant and equipment”During 2009 and in accordance with the accounting
standard for the impairment or disposal of long-lived assets (ASC 360), long-lived assets
“held and
used” with a carrying amount of $949 were written down to a fair value of $490, resulting in a
before-tax loss of $459. The fair values were determined from internal cash-flow models, using
discount rates consistent with those used by the company to evaluate cash flows of other assets of
a similar nature. Long-lived assets
“held for sale” with a carrying amount of $160 were written
down to a fair value of $68, resulting in a before-tax loss of $92. The fair values were determined
based on bids received from prospective buyers.
The fair-value hierarchy for nonrecurring assets and liabilities measured at fair value during
2009 is presented in the following table.
Assets and Liabilities Measured at Fair Value on a Non-recurring Basis
Prices in Active
Other
Loss (Before Tax)
Year Ended
Markets for
Observable
Unobservable
Year Ended
December 31
Identical Assets
Inputs
Inputs
December 31
2009
(Level 1)
(Level 2)
(Level 3)
2009
Properties, plant and equipment,
net (held and used)
$
490
$
–
$
–
$
490
$
459
Properties, plant and equipment, net
(held for sale)
68
–
68
–
92
Total Nonrecurring Assets at Fair Value
$
558
$
–
$
68
$
490
$
551
Assets and Liabilities Not Required to Be Measured at Fair Value The company holds cash
equivalents in U.S. and non-U.S. portfolios. The instruments held are primarily time deposits and
money market funds. The fair values reflect the cash that would have been received or paid if the
instruments were settled at year-end. Cash equivalents had carrying/fair values of $6,396 and
$7,058 at December 31, 2009 and 2008, respectively, and average maturities under 90 days. The
balance at December 31, 2009, includes $123 of investments for restricted funds related to an
international upstream development project and Pascagoula Refinery projects, which are included in
“Deferred charges and other assets” on the Consolidated Balance Sheet. Long-term debt of $5,705 and
$1,221 had estimated fair values of $6,229 and $1,414 at December 31, 2009 and 2008, respectively.
Fair values of other financial instruments at the end of 2009 and 2008 were not material.
Note 10
Financial and Derivative Instruments
Derivative Commodity Instruments Chevron is exposed to market risks related to price
volatility of crude oil, refined products, natural gas, natural gas liquids, liquefied natural gas
and refinery feedstocks.
The company uses derivative commodity instruments to manage these exposures on a portion of
its activity, including firm commitments and anticipated transactions for the pur-
chase, sale and storage of crude oil, refined products, natural gas, natural gas liquids and
feedstock for company refineries. From time to time, the company also uses derivative commodity
instruments for limited trading purposes.
The company’s derivative commodity instruments principally include crude-oil, natural-gas and
refined-product futures, swaps, options and forward contracts. None of the company’s derivative
instruments is designated as a hedging instrument, although certain of the company’s affiliates
make such designation. The company’s derivatives are not material to the company’s financial
position, results of operations or liquidity. The company believes it has no material market or
credit risks to its operations, financial position or liquidity as a result of its commodities and
other derivatives activities.
The company uses International Swaps and Derivatives Association agreements to govern
derivative contracts with certain counterparties to mitigate credit risk. Depending on the nature
of the derivative transactions, bilateral collateral arrangements may also be required. When the
company is engaged in more than one outstanding derivative transaction with the same counterparty
and also has a legally enforceable netting agreement with that counterparty, the net mark-to-market exposure represents the
netting of the positive and negative exposures with that counterparty and is a reasonable measure
of the company’s credit risk exposure. The company also uses other netting agreements with certain
counterparties with which it conducts significant transactions to mitigate credit risk.
Derivative instruments measured at fair value at December 31, 2009, and December 31, 2008, and
their classification on the Consolidated Balance Sheet and Consolidated Statement of Income are as
follows:
Consolidated Balance Sheet: Fair Value of Derivatives Not Designated as Hedging Instruments
Foreign Currency The company may enter into currency derivative contracts to manage some of
its foreign currency exposures. These exposures include revenue and anticipated purchase
transactions, including foreign currency capital expenditures and lease commitments. The currency
derivative contracts, if any, are recorded at fair value on the balance sheet with resulting gains
and losses reflected in income. There were no open currency derivative contracts at December 31,2009.
Interest Rates The company may enter into interest rate swaps from time to time as part of its
overall strategy to manage the interest rate risk on its debt. Historically, under the terms of the
swaps, net cash settlements were 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 company’s fixed-rate debt, if any, may be accounted for as fair value
hedges. Interest rate swaps related to floating-rate debt, if any, are recorded at fair value on
the balance sheet with resulting gains and losses reflected in income. At year-end 2009, the
company had no interest rate swaps. The company’s only interest rate swaps on fixed-rate debt
matured in January 2009.
Concentrations of Credit Risk The company’s financial instruments that are exposed to
concentrations of credit risk consist primarily of its cash equivalents, marketable securities,
derivative financial instruments and trade receivables. The company’s short-term investments are
placed with a wide array of financial institutions with high credit ratings. This diversified
investment policy limits the company’s exposure both to credit risk and to concentrations of credit
risk. Similar standards of diversity and creditworthiness are applied to the company’s
counterparties in derivative instruments.
The trade receivable balances, reflecting the company’s diversified sources of revenue, are
dispersed among the company’s broad customer base worldwide. As a result, the company believes
concentrations of credit risk are limited. The company routinely assesses the financial strength of
its customers. When the financial strength of a customer is not considered sufficient, requiring
Letters of Credit is a principal method used to support sales to customers.
Note 11
Operating Segments and Geographic Data
Although each subsidiary of Chevron is responsible for its own affairs, Chevron Corporation
manages its investments in these subsidiaries and their affiliates. For this purpose, the
investments are grouped as follows: upstream – exploration and production; downstream – refining,
marketing and transportation; chemicals; and all other. The first three of these groupings
represent the company’s “reportable segments” and “operating segments” as defined in accounting
standards for segment reporting (ASC 280).
The segments are separately managed for investment purposes under a structure that includes
“segment managers” who report to the company’s “chief operating decision maker” (CODM)
(terms as
defined in ASC 280). The CODM is the company’s Executive Committee, a committee of senior officers
that includes the Chief Executive Officer and that, in turn, reports to the Board of Directors of
Chevron Corporation.
The operating segments represent components of the company, as described in accounting
standards for segment reporting (ASC 280), that engage in activities (a) from which revenues are
earned and expenses are incurred; (b) whose operating results are regularly reviewed by the CODM,
which makes decisions about resources to be allocated to the segments and to assess their
performance; and (c) for which discrete financial information is available.
Segment managers for the reportable segments are directly accountable to and maintain regular
contact with the company’s CODM to discuss the segment’s operating activities and financial
performance. The CODM approves annual capital and exploratory budgets at the reportable segment
level, as well as reviews capital and exploratory funding for major projects and approves major
changes to the annual capital and exploratory budgets. However, business-unit managers within the
operating segments are directly responsible for decisions relating to project implementation and
all other matters connected with daily operations. Company officers who are
Note 11 Operating Segments and Geographic Data - Continued
members of the Executive Committee also have individual management responsibilities and
participate in other committees for purposes other than acting as the CODM.
“All Other” activities include 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 company’s interest in
Dynegy
(through May 2007, when Chevron sold its interest).
The company’s primary country of operation is the United States of America, its country of
domicile. Other components of the company’s operations are reported as “International”
(outside the
United States).
Segment Earnings The company evaluates the performance of its operating segments on an after-tax
basis, without considering the effects of debt financing interest expense or investment interest
income, both of which are managed by the company on a worldwide basis. Corporate administrative
costs and assets are not allocated to the operating segments. However, operating segments are
billed for the direct use of corporate services. Nonbillable costs remain at the corporate level in
“All Other.” Earnings by major operating area are presented in the following table:
Year ended December 31
2009
2008
2007
Segment Earnings
Upstream
United States
$
2,216
$
7,126
$
4,532
International
8,215
14,584
10,284
Total Upstream
10,431
21,710
14,816
Downstream
United States
(273
)
1,369
966
International
838
2,060
2,536
Total Downstream
565
3,429
3,502
Chemicals
United States
198
22
253
International
211
160
143
Total Chemicals
409
182
396
Total Segment Earnings
11,405
25,321
18,714
All Other
Interest expense
(22
)
–
(107
)
Interest income
46
192
385
Other
(946
)
(1,582
)
(304
)
Net Income Attributable
to Chevron Corporation
$
10,483
$
23,931
$
18,688
Segment Assets Segment assets do not include intercompany investments or intercompany
receivables. Segment assets at
year-end 2009 and 2008 are as follows:
At December 31
2009
2008
Upstream
United States
$
24,918
$
26,071
International
74,937
72,530
Goodwill
4,618
4,619
Total Upstream
104,473
103,220
Downstream
United States
18,067
15,869
International
24,824
23,572
Total Downstream
42,891
39,441
Chemicals
United States
2,810
2,535
International
1,066
1,086
Total Chemicals
3,876
3,621
Total Segment Assets
151,240
146,282
All Other*
United States
7,125
8,984
International
6,256
5,899
Total All Other
13,381
14,883
Total Assets – United States
52,920
53,459
Total Assets – International
107,083
103,087
Goodwill
4,618
4,619
Total Assets
$
164,621
$
161,165
*“All Other” assets consist primarily of worldwide cash, cash equivalents and marketable
securities, real estate, information systems, mining operations, power generation businesses,
alternative fuels and technology companies, and assets of the corporate administrative functions.
Segment Sales and Other Operating Revenues Operating segment sales and other operating
revenues, including internal transfers, for the years 2009, 2008 and 2007, are presented in the
table on the following page. Products are transferred between operating segments at internal
product values that approximate market prices.
Revenues for the upstream segment are derived primarily from the production and sale of crude
oil and natural gas, as well as the sale of third-party production of natural gas. Revenues for the
downstream segment are derived from the refining and marketing of petroleum products such as
gasoline, jet fuel, gas oils, lubricants, residual fuel oils and other products derived from crude
oil. This segment also generates revenues from the transportation and trading of refined products,
crude oil and natural gas liquids. Revenues
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 11 Operating Segments and Geographic Data - Continued
for the chemicals segment are derived primarily from the manufacture and sale of additives for
lubricants and fuels. “All Other” activities include revenues from mining operations, power
generation businesses, insurance operations, real estate activities and technology companies.
Other than the United States, no single country accounted for 10 percent or more of the
company’s total sales and other operating revenues in 2009, 2008 and 2007.
Year ended December 31
2009
2008
2007
Upstream
United States
$
9,164
$
23,503
$
18,736
Intersegment
10,278
15,142
11,625
Total United States
19,442
38,645
30,361
International
13,409
19,469
15,213
Intersegment
18,477
24,204
19,647
Total International
31,886
43,673
34,860
Total Upstream
51,328
82,318
65,221
Downstream
United States
57,846
87,515
70,535
Excise and similar taxes
4,573
4,746
4,990
Intersegment
190
447
491
Total United States
62,609
92,708
76,016
International
76,668
122,064
97,178
Excise and similar taxes
3,471
5,044
5,042
Intersegment
106
122
38
Total International
80,245
127,230
102,258
Total Downstream
142,854
219,938
178,274
Chemicals
United States
271
305
351
Excise and similar taxes
-
2
2
Intersegment
194
266
235
Total United States
465
573
588
International
1,231
1,388
1,143
Excise and similar taxes
65
55
86
Intersegment
132
154
142
Total International
1,428
1,597
1,371
Total Chemicals
1,893
2,170
1,959
All Other
United States
665
815
757
Intersegment
964
917
760
Total United States
1,629
1,732
1,517
International
39
52
58
Intersegment
33
33
31
Total International
72
85
89
Total All Other
1,701
1,817
1,606
Segment Sales and Other
Operating Revenues
United States
84,145
133,658
108,482
International
113,631
172,585
138,578
Total Segment Sales and Other
Operating Revenues
197,776
306,243
247,060
Elimination of intersegment sales
(30,374
)
(41,285
)
(32,969
)
Total Sales and Other
Operating Revenues
$
167,402
$
264,958
$
214,091
Segment Income Taxes Segment income tax expense
for the years 2009, 2008 and 2007 is as follows:
Year ended December 31
2009
2008
2007
Upstream
United States
$
1,225
$
3,693
$
2,541
International
7,686
15,132
11,307
Total Upstream
8,911
18,825
13,848
Downstream
United States
(111
)
815
520
International
182
813
400
Total Downstream
71
1,628
920
Chemicals
United States
54
(22
)
6
International
46
47
36
Total Chemicals
100
25
42
All Other
(1,117
)
(1,452
)
(1,331
)
Total Income Tax Expense
$
7,965
$
19,026
$
13,479
Other Segment Information Additional information
for the segmentation of major equity affiliates is
contained in Note 12, beginning on page FS-43.
Information related to properties, plant and equipment
by segment is contained in Note 13, on page FS-45.
Equity in earnings, together with investments in and
advances to companies accounted for using the equity
method and other investments accounted for at or below
cost, is shown in the table below. For certain equity
affiliates, Chevron pays its share of some income taxes
directly. For such affiliates, the equity in earnings
does not include these taxes, which are reported on the
Consolidated Statement of Income as “Income tax
expense.”
Investments and Advances
Equity in Earnings
At December 31
Year ended December 31
2009
2008
2009
2008
2007
Upstream
Tengizchevroil
$
5,938
$
6,290
$
2,216
$
3,220
$
2,135
Petropiar/Hamaca
1,139
1,130
122
317
327
Petroboscan
832
816
171
244
185
Angola LNG Limited
1,853
1,191
(12
)
(8
)
21
Other
686
725
118
206
204
Total Upstream
10,448
10,152
2,615
3,979
2,872
Downstream
GS Caltex Corporation
2,406
2,601
(191
)
444
217
Caspian Pipeline Consortium
852
749
105
103
102
Star Petroleum Refining
Company Ltd.
873
877
(4
)
22
157
Caltex Australia Ltd.
740
723
11
250
129
Colonial Pipeline Company
514
536
51
32
39
Other
1,773
1,664
311
354
318
Total Downstream
7,158
7,150
283
1,205
962
Chemicals
Chevron Phillips Chemical
Company LLC
2,327
2,037
328
158
380
Other
28
25
7
4
6
Total Chemicals
2,355
2,062
335
162
386
All Other
Other
507
567
83
20
(76
)
Total equity method
$
20,468
$
19,931
$
3,316
$
5,366
$
4,144
Other at or below cost
690
989
Total investments and
advances
$
21,158
$
20,920
Total United States
$
4,195
$
4,002
$
511
$
307
$
478
Total International
$
16,963
$
16,918
$
2,805
$
5,059
$
3,666
Descriptions of major affiliates, including significant differences between the company’s
carrying value of its investments and its underlying equity in the net assets of the affiliates,
are as follows:
Tengizchevroil Chevron has a 50 percent equity ownership interest in Tengizchevroil
(TCO), a joint venture formed in 1993 to develop the Tengiz and Korolev crude-oil fields in
Kazakhstan over a 40-year period. At December 31, 2009, the company’s carrying value of its
investment in TCO was about $200 higher than the amount of underlying equity in TCO’s net assets. This difference results from
Chevron acquiring
a portion of its interest in TCO at a value greater than the underlying book value for that portion
of TCO’s net assets. See Note 7, on page FS-36, for summarized financial information for 100
percent of TCO.
Petropiar Chevron has a 30 percent interest in Petropiar, a joint stock company formed in 2008 to
operate the Hamaca heavy-oil production and upgrading project. The project, located in Venezuela’s
Orinoco Belt, has a 25-year contract term. Prior to the formation of Petropiar, Chevron had a 30
percent interest in the Hamaca project. At December 31, 2009, the company’s carrying value of its
investment in Petropiar was approximately $195 less than the amount of underlying equity in
Petropiar’s net assets. The difference represents the excess of Chevron’s underlying equity in
Petropiar’s net assets over the net book value of the assets contributed to the venture.
Petroboscan Chevron has a 39 percent interest in Petroboscan, a joint stock company formed in 2006
to operate the Boscan Field in Venezuela until 2026. Chevron previously operated the field under an
operating service agreement. At December 31, 2009, the company’s carrying value of its investment
in Petroboscan was approximately $275 higher than the amount of underlying equity in Petroboscan’s
net assets. The difference reflects the excess of the net book value of the assets contributed by
Chevron over its underlying equity in Petroboscan’s net assets.
Angola LNG Ltd. Chevron has a 36 percent interest in
Angola LNG Ltd., which will process and
liquefy natural gas produced in Angola for delivery to international markets.
GS Caltex Corporation Chevron owns 50 percent of
GS Caltex Corporation, a joint venture with GS
Holdings. The joint venture imports, refines and markets petroleum products and petrochemicals,
predominantly in South Korea.
Caspian Pipeline Consortium Chevron has a 15 percent interest in the Caspian Pipeline Consortium,
which provides the critical export route for crude oil from both TCO and Karachaganak.
Star Petroleum Refining Company Ltd. Chevron has a 64 percent equity ownership interest in Star
Petroleum Refining Company Ltd. (SPRC), which owns the Star Refinery in Thailand. The Petroleum
Authority of Thailand owns the remaining 36 percent of SPRC.
Caltex Australia Ltd. Chevron has a 50 percent equity ownership interest in Caltex Australia Ltd.
(CAL). The remaining 50 percent of CAL is publicly owned. At December 31, 2009,
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 12 Investments and Advances - Continued
the fair value of Chevron’s share of CAL common stock was approximately $1,120.
Colonial Pipeline Company Chevron owns an approximate 23 percent equity interest in the Colonial
Pipeline Company. The Colonial Pipeline system runs from Texas to New Jersey and transports
petroleum products in a 13-state market.
At December 31, 2009, the company’s carrying value of its
investment in Colonial Pipeline was approximately $550 higher than the amount of underlying equity
in Colonial Pipeline net assets. This difference primarily relates to purchase price adjustments
from the acquisition of Unocal Corporation.
Chevron Phillips Chemical Company LLC Chevron owns 50 percent of Chevron Phillips Chemical Company
LLC. The other half is owned by ConocoPhillips Corporation.
Other Information “Sales and other operating revenues” on the Consolidated Statement of Income
includes $10,391, $15,390 and $11,555 with affiliated companies for 2009, 2008 and 2007,
respectively. “Purchased crude oil and products” includes
$4,631, $6,850 and $5,464 with affiliated
companies for 2009, 2008 and 2007, respectively.
“Accounts and notes receivable” on the Consolidated Balance Sheet includes $1,125 and $701 due
from affiliated companies at December 31, 2009 and 2008, respectively. “Accounts payable” includes
$345 and $289 due to affiliated companies at December 31, 2009 and 2008, respectively.
The following table provides summarized financial information on a 100 percent basis for all
equity affiliates as well as Chevron’s total share, which includes Chevron loans to affiliates of
$2,422 at December 31, 2009.
1 Other than the United States and Nigeria, no other country accounted for 10
percent or more of the company’s net properties, plant and equipment (PP&E) in 2009 and 2008.
Only the United States had more than 10 percent in 2007. Nigeria had net PP&E of $12,463 and
$10,730 for 2009 and 2008, respectively.
2 Net of dry hole expense related to prior years’ expenditures of $84, $55 and $89 in 2009, 2008 and 2007, respectively.
3 Depreciation expense includes accretion expense of $463, $430 and $399 in 2009, 2008 and 2007, respectively.
4 Primarily mining operations, power generation businesses, real estate assets and management information systems.
Note 14
Litigation
MTBE Chevron and many other companies in the petroleum industry have used methyl tertiary butyl
ether (MTBE) as a gasoline additive. Chevron is a party to 50 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 company’s ultimate exposure related to pending lawsuits and claims is not 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.
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
Texpet’s ownership share of the consortium. Pursuant to that agreement, Texpet conducted a
three-year remediation program at a cost of $40. 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; 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
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 14 Litigation - Continued
given to Texpet by the Republic of Ecuador and Petroecuador. With regard to the facts, the company believes that the
evidence confirms that Texpet’s remediation was properly conducted and that the remaining
environmental damage reflects Petroecuador’s failure to timely fulfill its legal obligations and
Petroecuador’s 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 $8,000, 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 engineer’s report also asserted that an additional $8,300 could be assessed
against Chevron for unjust enrichment. The engineer’s report is not binding on the court. Chevron
also believes that the engineer’s work was performed and his report prepared in a manner contrary
to law and in violation of the court’s 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 $18,900 and an increase in the assessment for purported unjust
enrichment to a total of $8,400. Chevron submitted a rebuttal to the revised report, which the
court dismissed. In September 2009, following the disclosure by Chevron of evidence that the judge
participated in meetings in which businesspeople and individuals holding themselves out as
government officials discussed the case and its likely outcome, the judge presiding over the case
petitioned to be recused. In late September 2009, the judge was recused, and in October 2009, the
full chamber of the provincial court affirmed the recusal, resulting in the appointment of a new
judge. Chevron filed motions to annul all of the rulings made by the prior judge, but the new judge
denied these motions. The court has completed most of the procedural aspects of the case and could
render a judgment at any time. Chevron will continue a vigorous defense of any attempted imposition
of liability.
In the event of an adverse judgment, Chevron would expect to pursue its appeals and vigorously
defend against enforcement of any such judgment; therefore, the ultimate outcome – and any
financial effect on Chevron – remains uncertain. 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 engineer’s report, management does not believe the
report 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).
Note 15
Taxes
Income Taxes
Year ended December 31
2009
2008
2007
Taxes on income
U.S. Federal
Current
$
128
$
2,879
$
1,446
Deferred
(147
)
274
225
State and local
Current
216
528
356
Deferred
14
141
(18
)
Total United States
211
3,822
2,009
International
Current
7,154
15,021
11,416
Deferred
600
183
54
Total International
7,754
15,204
11,470
Total taxes on income
$
7,965
$
19,026
$
13,479
In 2009, before-tax income for U.S. operations, including related corporate and other
charges, was $1,310, compared with before-tax income of $10,765 and $7,886 in 2008 and 2007,
respectively. For international operations, before-tax income was $17,218, $32,292 and $24,388 in
2009, 2008 and 2007, respectively. U.S. federal income tax expense was reduced by $204, $198 and
$132 in 2009, 2008 and 2007, respectively, for business tax credits.
The reconciliation between the U.S. statutory federal income tax rate and the company’s
effective income tax rate is explained in the following table:
Year ended December 31
2009
2008
2007
U.S. statutory federal income tax rate
35.0
%
35.0
%
35.0
%
Effect of income taxes from international
operations at rates different
from the U.S. statutory rate
10.4
10.1
8.2
State and local taxes on income, net
of U.S. federal income tax benefit
The company’s effective tax rate decreased from 44.2 percent in 2008 to 43.0
percent in 2009. The rate was lower in 2009 mainly due to the effect of deferred tax benefits and
relatively low tax rates on asset sales, both related to an international upstream project. In
addition, a greater proportion of before-tax income was earned in 2009 by equity affiliates than in
2008. (Equity-affiliate income is reported as a single amount on an after-tax basis on the
Consolidated Statement of Income.) Partially offsetting these items was the effect of a greater
proportion of income earned in 2009 in tax jurisdictions with higher tax rates.
The company records its deferred taxes on a tax-jurisdiction basis and classifies those net
amounts as current or noncurrent based on the balance sheet classification of the related assets or
liabilities. The reported deferred tax balances are composed of the following:
At December 31
2009
2008
Deferred tax liabilities
Properties, plant and equipment
$
18,545
$
18,271
Investments and other
2,350
2,225
Total deferred tax liabilities
20,895
20,496
Deferred tax assets
Foreign tax credits
(5,387
)
(4,784
)
Abandonment/environmental reserves
(4,424
)
(4,338
)
Employee benefits
(3,499
)
(3,488
)
Deferred credits
(3,469
)
(3,933
)
Tax loss carryforwards
(819
)
(1,139
)
Other accrued liabilities
(553
)
(445
)
Inventory
(431
)
(260
)
Miscellaneous
(1,681
)
(1,732
)
Total deferred tax assets
(20,263
)
(20,119
)
Deferred tax assets valuation allowance
7,921
7,535
Total deferred taxes, net
$
8,553
$
7,912
Deferred tax liabilities at the end of 2009 increased by approximately $400 from
year-end 2008. The increase was primarily related to increased temporary differences for
properties, plant and equipment.
Deferred tax assets were essentially unchanged in 2009. Increases related to additional
foreign tax credits arising from earnings in high-tax-rate international jurisdictions (which were
substantially offset by valuation allowances) and to inventory-related temporary differences. These
effects were offset by reductions in deferred credits and tax loss carryforwards primarily
resulting from the usage of tax benefits in international tax jurisdictions.
The overall valuation allowance relates to deferred tax assets for foreign tax credit carryforwards,
tax loss carryforwards and temporary differences. It reduces the deferred tax assets to
amounts that are, in management’s assessment, more likely than not to be realized. Tax loss
carryforwards exist in many international jurisdictions. Whereas some of these tax loss
carryforwards do not have an expiration date, others expire at various times from 2010 through
2036. Foreign tax credit carryforwards of $5,387 will expire between 2010 and 2019.
At December 31, 2009 and 2008, deferred taxes were classified on the Consolidated Balance
Sheet as follows:
At December 31
2009
2008
Prepaid expenses and other current assets
$
(1,825
)
$
(1,130
)
Deferred charges and other assets
(1,268
)
(2,686
)
Federal and other taxes on income
125
189
Noncurrent deferred income taxes
11,521
11,539
Total deferred income taxes, net
$
8,553
$
7,912
Income taxes are not accrued for unremitted earnings of international operations that
have been or are intended to be reinvested indefinitely. Undistributed earnings of international
consolidated subsidiaries and affiliates for which no deferred income tax provision has been made
for possible future remittances totaled $20,458 at December 31, 2009. This amount represents
earnings reinvested as part of the company’s ongoing international business. It is not practicable
to estimate the amount of taxes that might be payable on the eventual remittance of earnings that
are intended to be reinvested indefinitely. At the end of 2009, deferred income taxes were recorded
for the undistributed earnings of certain international operations for which the company no longer
intends to indefinitely reinvest the earnings. The company does not anticipate incurring
significant additional taxes on remittances of earnings that are not indefinitely reinvested.
Uncertain Income Tax Positions Under accounting standards for uncertainty in income taxes (ASC
740-10), a company recognizes a tax benefit in the financial statements for an uncertain tax
position only if management’s assessment is that the position is “more likely than not” (i.e., a
likelihood greater than 50 percent) to be allowed by the tax jurisdiction based solely on the
technical merits of the position. The term “tax position” in the accounting standards for income
taxes (ASC 740-10-20) refers to a position in a previously filed tax return or a position expected
to be taken in a future tax return that is reflected in measuring current or deferred income tax
assets and liabilities for interim or annual periods.
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 15 Taxes - Continued
The following table indicates the changes to the company’s unrecognized tax
benefits for the year ended December 31, 2009. The term “unrecognized tax benefits” in the
accounting standards for income taxes (ASC 740-10-20) refers to the differences between a tax
position taken or expected to be taken in a tax return and the benefit measured and recognized in
the financial statements. Interest and penalties are not included.
2009
2008
2007
Balance at January 1
$
2,696
$
2,199
$
2,296
Foreign currency effects
(1
)
(1
)
19
Additions based on tax positions
taken in current year
459
522
418
Reductions based on tax positions
taken in current year
–
(17
)
–
Additions/reductions resulting from
current-year asset acquisitions/sales
–
175
–
Additions for tax positions taken
in prior years
533
337
120
Reductions for tax positions taken
in prior years
(182
)
(246
)
(225
)
Settlements with taxing authorities
in current year
(300
)
(215
)
(255
)
Reductions as a result of a lapse
of the applicable statute of limitations
(10
)
(58
)
–
Reductions due to tax positions previously
expected to be taken but subsequently
not taken on prior-year tax returns
–
–
(174
)
Balance at December 31
$
3,195
$
2,696
$
2,199
Although unrecognized tax benefits for individual tax positions may increase or decrease
during 2010, the company believes that no change will be individually significant during 2010.
Approximately 90 percent of the $3,195 of unrecognized tax benefits at December 31, 2009, would
have an impact on the effective tax rate if subsequently recognized.
Tax positions for Chevron and its subsidiaries and affiliates are subject to income tax audits
by many tax jurisdictions throughout the world. For the company’s major tax jurisdictions,
examinations of tax returns for certain prior tax years had not been completed as of December 31,2009. For these jurisdictions, the latest years for which income tax examinations had been
finalized were as follows: United States – 2005, Nigeria – 1994, Angola – 2001 and Saudi Arabia – 2003.
On the Consolidated Statement of Income, the company reports interest and penalties related to
liabilities for uncertain tax positions as “Income tax expense.” As of December 31, 2009, accruals
of $232 for anticipated interest and penalty obligations were included on the Consolidated Balance
Sheet,
compared with accruals of $276 as of year-end 2008. Income tax (benefit) expense associated with
interest and penalties was $(20), $79 and $70 in 2009, 2008 and 2007, respectively.
Taxes Other Than on Income
Year ended December 31
2009
2008
2007
United States
Excise and similar taxes on
products and merchandise
$
4,573
$
4,748
$
4,992
Import duties and other levies
(4
)
1
12
Property and other
miscellaneous taxes
584
588
491
Payroll taxes
223
204
185
Taxes on production
135
431
288
Total United States
5,511
5,972
5,968
International
Excise and similar taxes on
products and merchandise
3,536
5,098
5,129
Import duties and other levies
6,550
8,368
10,404
Property and other
miscellaneous taxes
1,740
1,557
528
Payroll taxes
134
106
89
Taxes on production
120
202
148
Total International
12,080
15,331
16,298
Total taxes other than on income
$
17,591
$
21,303
$
22,266
Note 16
Short-Term Debt
At December 31
2009
2008
Commercial paper*
$
2,499
$
5,742
Notes payable to banks and others with
originating terms of one year or less
213
149
Current maturities of long-term debt
66
429
Current maturities of long-term
capital leases
76
78
Redeemable long-term obligations
Long-term debt
1,702
1,351
Capital leases
18
19
Subtotal
4,574
7,768
Reclassified to long-term debt
(4,190
)
(4,950
)
Total short-term debt
$
384
$
2,818
*
Weighted-average interest rates at December 31, 2009 and 2008, were 0.08 percent and 0.67 percent, respectively.
Redeemable long-term obligations consist primarily of tax-exempt variable-rate put bonds
that are included as current liabilities because they become redeemable at the option of the
bondholders within one year following
the balance sheet date. In 2009, $350 of tax-exempt Gulf Opportunity Zone bonds related to
projects at the Pascagoula Refinery were issued.
The company periodically enters into interest rate swaps on a portion of its short-term debt.
At December 31, 2009, the company had no interest rate swaps on short-term debt. See Note 10,
beginning on page FS-39, for information concerning the company’s debt-related derivative
activities.
At December 31, 2009, the company had $5,100 of committed credit facilities with banks
worldwide, which permit the company to refinance short-term obligations on a long-term basis. The
facilities support the company’s commercial paper borrowings. Interest on borrowings under the
terms of specific agreements may be based on the London Interbank Offered Rate or bank prime rate.
No amounts were outstanding under these credit agreements during 2009 or at year-end.
At December 31, 2009 and 2008, the company classified $4,190 and $4,950, respectively, of
short-term debt as long-term. Settlement of these obligations is not expected to require the use of
working capital in 2010, as the company has both the intent and the ability to refinance this debt
on a long-term basis.
Note 17
Long-Term Debt
Total long-term debt, excluding capital leases, at December 31, 2009, was $9,829. The
company’s long-term debt outstanding at year-end 2009 and 2008 was as follows:
Long-term debt of $5,705 matures as follows: 2010 – $66; 2011 – $33; 2012 – $1,520;
2013 – $21; 2014 – $2,020; and after 2014 – $2,045.
In 2009, $5,000 of public bonds was issued, and $400 of Texaco Capital Inc. bonds matured. In
2008, debt totaling $822 matured, including $749 of Chevron Canada Funding Company notes.
Note 18
New Accounting Standards
The FASB Accounting Standards
Codification and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB
Statement No. 162 (FAS 168) In June 2009, the FASB issued FAS 168, which became effective for the
company in the quarter ending September 30, 2009. This standard established the FASB Accounting
Standards Codification (ASC) system as the single authoritative source of U.S. generally accepted
accounting principles (GAAP) and superseded existing literature of the FASB, Emerging Issues Task
Force, American Institute of CPAs and other sources. The ASC did not change GAAP, but organized the
literature into about 90 accounting Topics. Adoption of the ASC did not affect the company’s
accounting.
Employer’s Disclosures About Postretirement Benefit Plan Assets (FSP FAS 132(R)-1) In December 2008,
the FASB issued FSP FAS 132(R)-1, which was subsequently codified into ASC 715, Compensation –
Retirement Benefits, and became effective with the company’s reporting at December 31,2009. This standard amended and expanded the disclosure
requirements for the plan assets of defined benefit pension
and other postretirement plans. Refer to information
beginning on page FS-52 in Note 21, Employee Benefits, for these
disclosures.
Transfers and Servicing (ASC 860), Accounting for Transfers of Financial Assets (ASU 2009-16) The
FASB issued ASU 2009-16 in December 2009. This standard became effective for the company on January1, 2010. ASU 2009-16 changes how companies account for transfers of financial assets and eliminates
the concept of qualifying special-purpose entities. Adoption of the guidance is not expected to
have an impact on the company’s results of operations, financial position or liquidity.
Consolidation (ASC 810), Improvements to Financial Reporting by Enterprises Involved With Variable
Interest Entities (ASU 2009-17) The FASB issued ASU 2009-17 in December 2009. This standard became
effective for the companyJanuary 1,2010. ASU 2009-17 requires the enterprise to qualitatively
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 18 New Accounting Standards - Continued
assess if it is the primary beneficiary of a variable-interest entity (VIE), and, if
so, the VIE must be consolidated. Adoption of the standard is not expected to have a material
impact on the company’s results of operations, financial position or liquidity.
Extractive Industries – Oil and Gas (ASC 932), Oil and Gas Reserve Estimation and Disclosures
(ASU 2010-03) In January 2010, the FASB issued ASU 2010-03, which became effective for the company
on December 31, 2009. The standard amends certain sections of ASC 932, Extractive Industries – Oil
and Gas, to align them with the requirements in the Securities and Exchange Commission’s final
rule, Modernization of the Oil and Gas Reporting Requirements (the final rule). The final rule was
issued on December 31, 2008. Refer to Table V – Reserve Quantity Information, beginning on page
FS-69, for additional information on the final rule and the impact of adoption.
Note 19
Accounting for Suspended Exploratory Wells
Accounting standards for the costs of exploratory
wells (ASC 932) provide that exploratory well costs continue to be capitalized after the completion
of drilling when (a) the well has found a sufficient quantity of reserves to justify completion as
a producing well and (b) the enterprise is making sufficient progress assessing the reserves and
the economic and operating viability of the project. If either condition is not met or if an
enterprise obtains information that raises substantial doubt about the economic or operational
viability of the project, the exploratory well would be assumed to be impaired, and its costs, net
of any salvage value, would be charged to expense. The accounting standards provide a number of
indicators that can assist an entity in demonstrating that sufficient progress is being made in
assessing the reserves and economic viability of the project.
The following table indicates the changes to the company’s suspended exploratory well costs
for the three years ended December 31, 2009:
2009
2008
2007
Beginning balance at January 1
$
2,118
$
1,660
$
1,239
Additions to capitalized exploratory
well costs pending the
determination of proved reserves
663
643
486
Reclassifications to wells, facilities
and equipment based on the
determination of proved reserves
(174
)
(49
)
(23
)
Capitalized exploratory well costs
charged to expense
(172
)
(136
)
(42
)
Ending balance at December 31
$
2,435
$
2,118
$
1,660
The following table provides an aging of capitalized well costs and the number of projects
for which exploratory well costs have been capitalized for a period greater than one year since the
completion of drilling.
At December 31
2009
2008
2007
Exploratory well costs capitalized
for a period of one year or less
$
564
$
559
$
449
Exploratory well costs capitalized
for
a period greater than one year
1,871
1,559
1,211
Balance at December 31
$
2,435
$
2,118
$
1,660
Number of projects with
exploratory
well costs that have been capitalized
for a period greater than one year*
46
50
54
*
Certain projects have multiple wells or fields or both.
Of the $1,871 of exploratory well costs capitalized for more than one year at December 31,2009, $1,143 (28 projects) is related to projects that had drilling activities under way or firmly
planned for the near future. The $728 balance is related to 18 projects in areas requiring a major
capital expenditure before production could begin and for which additional drilling efforts were
not under way or firmly planned for the near future. Additional drilling was not deemed necessary
because the presence of hydrocarbons had already been established, and other activities were in
process to enable a future decision on project development.
Note 19 Accounting for Suspended Exploratory Wells - Continued
The projects for the $728 referenced above had the following activities
associated with assessing the reserves and the projects’
economic viability: (a) $330 (one project) – negotiation of crude-oil and natural-gas transportation contracts and construction agreements;
(b) $107 (two projects) – discussion with possible natural-gas purchasers ongoing; (c) $73 (two
projects) – continued unitization efforts on adjacent discoveries that span international
boundaries while planning on an LNG facility has commenced; (d) $49
(one project) – progression of
development concept selection; (e) $47 (one project) – subsurface and facilities engineering
studies concluding with front-end engineering and design expected to begin in early 2010; (f) $34 (one project) – reviewing development alternatives; $88 – miscellaneous activities for 10
projects with smaller amounts suspended. While progress was being made on all 46 projects, the
decision on the recognition of proved reserves under SEC rules in some cases may not occur for
several years because of the complexity, scale and negotiations connected with the projects. The
majority of these decisions are expected to occur in the next three years.
The $1,871 of suspended well costs capitalized for a period greater than one year as of
December 31, 2009, represents 149 exploratory wells in 46 projects. The tables below contain the
aging of these costs on a well and project basis:
Number
Aging based on drilling completion date of individual wells:
Amount
of wells
1992
$
8
3
1997–1998
15
3
1999–2003
271
42
2004–2008
1,577
101
Total
$
1,871
149
Aging based on drilling completion date of last
Number
suspended well in project:
Amount
of projects
1992
$
8
1
1999
8
1
2003–2004
242
5
2005–2009
1,613
39
Total
$
1,871
46
Note 20
Stock Options and Other Share-Based Compensation
Compensation expense for stock options for
2009, 2008 and 2007 was $182 ($119 after tax), $168 ($109 after tax) and $146 ($95 after tax),
respectively. In addition, compensation expense for stock appreciation rights, restricted stock,
performance units and restricted stock units was $170 ($110
after tax), $132 ($86 after tax) and $205 ($133 after tax) for 2009, 2008 and 2007, respectively.
No significant stock-based compensation cost was capitalized at December 31, 2009 and 2008.
Cash received in payment for option exercises under all share-based payment arrangements for
2009, 2008 and 2007 was $147, $404 and $445, respectively. Actual tax benefits realized for the tax
deductions from option exercises were $25, $103 and $94 for 2009, 2008 and 2007, respectively.
Cash paid to settle performance units and stock appreciation rights was $89, $136 and $88 for
2009, 2008 and 2007, respectively.
Chevron Long-Term Incentive Plan (LTIP) Awards under the LTIP may take the form of, but are not
limited to, stock options, restricted stock, restricted stock units, stock appreciation rights,
performance units and nonstock grants. From April 2004 through January 2014, no more than 160
million shares may be issued under the LTIP, and no more than 64 million of those shares may be in
a form other than a stock option, stock appreciation right or award requiring full payment for
shares by the award recipient.
Texaco Stock Incentive Plan (Texaco SIP) On the closing of the acquisition of Texaco in October
2001, outstanding options granted under the Texaco SIP were converted to Chevron options. These
options, which have 10-year contractual lives extending into 2011, retained a provision for being
restored. This provision enables a participant who exercises a stock option to receive new options
equal to the number of shares exchanged or who has shares withheld to satisfy tax withholding
obligations to receive new options equal to the number of shares exchanged or withheld. The
restored options are fully exercisable six months after the date of grant, and the exercise price
is the market value of the common stock on the day the restored option is granted. Beginning in
2007, restored options were issued under the LTIP. No further awards may be granted under the
former Texaco plans.
Unocal Share-Based Plans (Unocal Plans) When Chevron acquired Unocal in August 2005, outstanding
stock options and stock appreciation rights granted under various Unocal Plans were exchanged for
fully vested Chevron options and appreciation rights. These awards retained the same provisions as
the original Unocal Plans. If not exercised, these awards will expire between early 2010 and early
2015.
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note
20 Stock Options and Other Share-Based
Compensation - Continued
The fair market values of stock options and stock appreciation rights granted in
2009, 2008 and 2007 were measured on the date of grant using the Black-Scholes option-pricing
model, with the following weighted-average assumptions:
Year ended December 31
2009
2008
2007
Stock Options
Expected term in years1
6.0
6.1
6.3
Volatility2
30.2
%
22.0
%
22.0
%
Risk-free
interest rate based on
zero coupon U.S. treasury note
2.1
%
3.0
%
4.5
%
Dividend yield
3.2
%
2.7
%
3.2
%
Weighted-average
fair value per
option granted
$
15.36
$
15.97
$
15.27
Restored Options
Expected term in years1
1.2
1.2
1.6
Volatility2
45.0
%
23.1
%
21.2
%
Risk-free
interest rate based on
zero coupon U.S. treasury note
1.1
%
1.9
%
4.5
%
Dividend yield
3.5
%
2.7
%
3.2
%
Weighted-average
fair value per
option granted
$
12.38
$
10.01
$
8.61
1
Expected term is based on historical exercise and postvesting cancellation data.
2
Volatility rate is based on historical stock prices over an appropriate period,
generally equal to the expected term.
A summary of option activity during 2009 is presented below:
The total intrinsic value (i.e., the difference between the exercise price and the
market price) of options exercised during 2009, 2008 and 2007 was $91, $433 and $423, respectively.
During this period, the company continued its practice of issuing treasury shares upon exercise of
these awards.
As of December 31, 2009, there was $233 of total unrecognized before-tax compensation cost
related to nonvested share-based compensation arrangements granted or restored under the plans.
That cost is expected to be recognized over a weighted-average period of 1.8 years.
At January 1, 2009, the number of LTIP performance units outstanding was equivalent to
2,400,555 shares. During 2009, 992,800 units were granted, 668,953 units vested with cash proceeds
distributed to recipients and 45,294 units were forfeited. At December 31, 2009, units outstanding
were 2,679,108, and the fair value of the liability recorded for these instruments was $233. In
addition, outstanding stock appreciation rights and other awards that were granted under various
LTIP and former Texaco and Unocal programs totaled approximately 1.5 million equivalent shares as
of December 31, 2009. A liability of $45 was recorded for these awards.
In March 2009, Chevron granted all eligible LTIP employees restricted stock units in lieu of
annual cash bonus. The expense associated with these special restricted stock units was recognized
at the time of the grants. A total of 453,965 units were granted at $69.70 per unit at the time of
the grant. Total fair value of the special restricted stock units was $32 as of December 31, 2009.
All of the special restricted stock units will be payable in November 2010.
Note 21
Employee Benefit Plans
The company has defined benefit pension plans for many employees. The company typically
prefunds defined benefit plans as required by local regulations or in certain situations where
prefunding provides economic advantages. In the United States, all qualified plans are subject to
the Employee Retirement Income Security Act (ERISA) minimum funding standard. The company does not
typically fund U.S. nonqualified pension plans that are not subject to funding requirements under
laws and regulations because contributions to these pension plans may be less economic and
investment returns may be less attractive than the company’s other investment alternatives.
The company also sponsors other postretirement (OPEB) plans that provide medical and dental
benefits, as well as life insurance for some active and qualifying retired employees. The plans are
unfunded, and the company and retirees share the costs. Medical coverage for Medicare-eligible
retirees in the company’s main U.S. medical plan is secondary to Medicare (including Part D), and
the increase to the company contribution for retiree medical coverage is limited to no more than 4
percent per year. Certain life insurance benefits are paid by the company.
Under accounting standards for postretirement benefits (ASC 715), the company recognizes the
overfunded or underfunded status of each of its defined benefit pension and OPEB as an asset or
liability on the Consolidated Balance Sheet.
The funded status of the company’s pension and other postretirement benefit plans for 2009 and
2008 is on the following page:
Amounts recognized on the Consolidated Balance Sheet for the company’s pension and other
postretirement benefit plans at December 31, 2009 and 2008, include:
Pension Benefits
2009
2008
Other Benefits
U.S.
Int’l.
U.S.
Int’l.
2009
2008
Deferred charges and other assets
$
6
$
37
$
6
$
31
$
–
$
–
Accrued liabilities
(66
)
(67
)
(72
)
(61
)
(208
)
(209
)
Reserves for employee benefit plans
(2,300
)
(1,450
)
(2,613
)
(1,261
)
(2,857
)
(2,722
)
Net amount recognized at December 31
$
(2,360
)
$
(1,480
)
$
(2,679
)
$
(1,291
)
$
(3,065
)
$
(2,931
)
Amounts recognized on a before-tax basis in “Accumulated other comprehensive loss” for the
company’s pension and OPEB plans were $6,454 and $5,831 at the end of 2009 and 2008, respectively.
These amounts consisted of:
Pension Benefits
2009
2008
Other Benefits
U.S.
Int’l.
U.S.
Int’l.
2009
2008
Net actuarial loss
$
4,181
$
1,889
$
3,797
$
1,804
$
465
$
410
Prior-service (credit) costs
(60
)
201
(68
)
211
(222
)
(323
)
Total recognized at December 31
$
4,121
$
2,090
$
3,729
$
2,015
$
243
$
87
The accumulated benefit obligations for all U.S. and international pension plans were
$8,707 and $4,029, respectively, at December 31, 2009, and $7,376 and $3,273, respectively, at
December 31, 2008.
Information for U.S. and international pension plans with an accumulated benefit
obligation in excess of plan assets at December 31, 2009 and 2008, was:
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 21 Employee Benefit Plans - Continued
The components of net periodic benefit cost and amounts recognized in other comprehensive
income for 2009, 2008 and 2007 are shown in the table below:
Pension Benefits
2009
2008
2007
Other Benefits
U.S.
Int’l.
U.S.
Int’l.
U.S.
Int’l.
2009
2008
2007
Net Periodic Benefit Cost
Service cost
$
266
$
128
$
250
$
132
$
260
$
125
$
43
$
44
$
49
Interest cost
481
292
499
292
483
255
180
178
184
Expected return on plan assets
(395
)
(203
)
(593
)
(273
)
(578
)
(266
)
–
–
–
Amortization of prior-service
(credits) costs
(7
)
23
(7
)
24
46
17
(81
)
(81
)
(81
)
Recognized actuarial losses
298
108
60
77
128
82
27
38
81
Settlement losses
141
1
306
2
65
–
–
–
–
Curtailment losses
–
–
–
–
–
3
(5
)
–
–
Special termination benefit recognition
–
–
–
1
–
–
–
–
–
Total net periodic benefit cost
784
349
515
255
404
216
164
179
233
Changes Recognized in Other
Comprehensive Income
Net actuarial loss (gain) during period
823
194
2,624
646
(160
)
31
82
(42
)
(401
)
Amortization of actuarial loss
(439
)
(109
)
(366
)
(79
)
(193
)
(82
)
(27
)
(38
)
(81
)
Prior service cost (credit) during period
1
13
–
32
(301
)
97
20
–
–
Amortization of prior-service
credits (costs)
7
(23
)
7
(24
)
(46
)
(20
)
81
81
81
Total changes recognized in
other comprehensive income
392
75
2,265
575
(700
)
26
156
1
(401
)
Recognized in Net Periodic
Benefit Cost and Other
Comprehensive Income
$
1,176
$
424
$
2,780
$
830
$
(296
)
$
242
$
320
$
180
$
(168
)
Net actuarial losses recorded in “Accumulated other comprehensive loss” at December31, 2009, for the company’s U.S. pension, international pension and OPEB plans are being amortized
on a straight-line basis over approximately 11, 13 and 10 years, respectively. These amortization
periods represent the estimated average remaining service of employees expected to receive benefits
under the plans. These losses are amortized to the extent they exceed 10 percent of the higher of
the projected benefit obligation or market-related value of plan assets. The amount subject to
amortization is determined on a plan-by-plan basis. During 2010, the company estimates actuarial
losses of $318, $102 and $26 will be amortized from “Accumulated other comprehensive loss” for U.S.
pension, international pension and OPEB plans, respec-
tively. In addition, the company estimates an
additional $220 will be recognized from “Accumulated
other comprehensive loss” during 2010 related to lump-sum settlement costs from U.S. pension plans.
The weighted average amortization period for recognizing prior service costs (credits)
recorded in “Accumulated other comprehensive loss” at December 31, 2009, was approximately eight
and 12 years for U.S. and international pension plans, respectively, and eight years for other
postretirement benefit plans. During 2010, the company estimates prior service (credits) costs of
$(7), $27 and $(74) will be amortized from “Accumulated other comprehensive loss” for U.S. pension,
international pension and OPEB plans, respectively.
Assumptions The following weighted-average assumptions were used to determine benefit
obligations and net periodic benefit costs for years ended December 31:
Pension Benefits
2009
2008
2007
Other Benefits
U.S.
Int’l.
U.S.
Int’l.
U.S.
Int’l.
2009
2008
2007
Assumptions used to determine
benefit obligations
Discount rate
5.3
%
6.8
%
6.3
%
7.5
%
6.3
%
6.7
%
5.9
%
6.3
%
6.3
%
Rate of compensation increase
4.5
%
6.3
%
4.5
%
6.8
%
4.5
%
6.4
%
N/A
4.0
%
4.5
%
Assumptions used to determine
net periodic benefit cost
Discount rate
6.3
%
7.5
%
6.3
%
6.7
%
5.8
%
6.0
%
6.3
%
6.3
%
5.8
%
Expected return on plan assets
7.8
%
7.5
%
7.8
%
7.4
%
7.8
%
7.5
%
N/A
N/A
N/A
Rate of compensation increase
4.5
%
6.8
%
4.5
%
6.4
%
4.5
%
6.1
%
N/A
4.5
%
4.5
%
Expected Return on Plan AssetsThe company’s estimated long-term rates of return on
pension assets are driven primarily by actual historical asset-class returns, an assessment of
expected future performance, advice from external actuarial firms and the incorporation of specific
asset-class risk factors. Asset allocations are periodically updated using pension plan
asset/liability studies, and the company’s estimated long-term rates of return are consistent with
these studies.
There have been no changes in the expected long-term rate of return on plan assets since 2002
for U.S. plans, which account for 69 percent of the company’s pension plan assets. At December 31,2009, the estimated long-term rate of return on U.S. pension plan assets was 7.8 percent.
The market-related value of assets of the major U.S. pension plan used in the determination of
pension expense was based on the market values in the three months preceding the year-end
measurement date, as opposed to the maximum allowable period of five years under U.S. accounting
rules. Management considers the three-month time 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.
Discount Rate The discount rate assumptions used to determine U.S. and international pension and
postretirement benefit plan obligations and expense reflect the prevailing rates available on
high-quality, fixed-income debt instruments. At December 31, 2009, the company selected a 5.3
percent discount rate for the U.S. pension plan and 5.8 percent for the U.S. postretirement benefit
plan. This rate was based on a cash flow analysis that matched estimated future benefit payments to
the Citigroup Pension Discount Yield Curve as of year-end 2009. The discount rates at the end of
2008 and 2007 were 6.3 percent for the U.S. pension plan and the OPEB plan.
Other Benefit Assumptions For the measurement of accumulated postretirement benefit obligation at
December 31, 2009, for the main U.S. postretirement medical plan, the assumed health care
cost-trend rates start with 7 percent in 2010 and gradually decline to 5 percent for 2018 and
beyond. For this measurement at December 31, 2008, the assumed health care cost-trend rates started
with 7 percent in 2009 and gradually declined to 5 percent for 2017 and beyond. In both
measurements, the annual increase to company contributions was capped at 4 percent.
Assumed health care cost-trend rates can have a significant effect on the amounts reported for
retiree health care costs. The impact is mitigated by the 4 percent cap on the company’s medical
contributions for the primary U.S. plan. A one-percentage-point change in the assumed health care
cost-trend rates would have the following effects:
1 Percent
1 Percent
Increase
Decrease
Effect on total service and interest cost components
$
10
$
(9
)
Effect on postretirement benefit obligation
$
102
$
(87
)
Plan Assets and Investment Strategy Effective December 31, 2009, the company implemented the
expanded disclosure requirements for the plan assets of defined benefit pension and OPEB plans (ASC
715) 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 unobservable
inputs on changes in plan assets for the period; and significant concentrations of risk within plan
assets.
The fair-value hierarchy of inputs the company uses to value the pension assets is divided
into three levels:
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 21 Employee Benefit Plans - Continued
Level 1: Fair values of these assets are measured using unadjusted quoted prices
for the assets or the prices of identical assets in active markets that the plans have the ability
to access.
Level 2: Fair values of these assets are measured based on quoted prices for similar assets in
active markets; quoted prices for identical or similar assets in inactive markets; inputs other
than quoted prices that are observable for the asset; and inputs that are derived principally from
or corroborated by observable market data by correlation or other means. If the
asset has a contractual term, the Level 2 input is observable for substantially the full term of
the asset. The fair values for Level 2 assets are generally obtained from third-party broker
quotes, independent pricing services and exchanges.
Level 3: Inputs to the fair value measurement are unobservable for these assets. Valuation may
be performed using a financial model with estimated inputs entered into the model.
The fair value measurements of the company’s pension plans for 2009 are below:
Collective Trusts/Mutual Funds for U.S. plans are entirely index funds; for
International plans, they are mostly index funds. For these index funds, the Level 2
designation is based
on the restriction that advance notification of redemptions, typically two business days, is
required.
3
Mixed funds are composed of funds that invest in both equity and fixed income
instruments in order to diversify and lower risk.
4
The year-end valuations of the U.S. real estate assets are based on internal
appraisals by the real estate managers, which are updates of third-party appraisals that occur
at least once
a year for each property in the portfolio.
5
The “Other” asset category includes net payables for securities purchased but not yet
settled (Level 1); dividends, interest- and tax-related receivables (Level 2); insurance
contracts
and investments in private-equity limited partnerships (Level 3).
The effect of fair-value measurements using significant unobservable inputs on changes
in Level 3 plan assets for the period are outlined below:
The primary investment objectives of the pension plans are to achieve the highest
rate of total return within prudent levels of risk and liquidity, to diversify and mitigate
potential downside risk associated with the investments, and to provide adequate liquidity for
benefit payments and portfolio management.
The company’s U.S. and U.K. pension plans comprise 84 percent of the total pension assets.
Both the U.S. and U.K. plans have an Investment Committee that regularly meets during the year to
review the asset holdings and their returns. To assess the plan’s investment performance, long-term
asset allocation policy benchmarks have been established.
For the primary U.S. pension plan, the Chevron Board of Directors has established the
following approved asset allocation ranges: Equities 40-70 percent, Fixed Income and Cash 20-60
percent, Real Estate 0-15 percent, and Other 0-5 percent. For the U.K. pension plan, the U.K. Board
of Trustees has established the following asset allocation guidelines, which are reviewed
regularly: Equities 60-80 percent and Fixed Income and Cash 20–40 percent. The other significant
international pension plans also have established maximum and minimum asset allocation ranges that
vary by plan. Actual asset allocation within approved ranges is based on a variety of current
economic and market conditions and consideration of specific asset category risk. There are no
significant concentrations of risk in plan assets due to the diversification of investment
categories.
The company does not prefund its OPEB obligations.
Cash Contributions and Benefit Payments In 2009, the company contributed $1,494 and $245 to its
U.S. and international pension plans, respectively. In 2010, the company expects contributions to
be approximately $600 and $300 to its U.S. and international pension plans, respectively. Actual
contribution amounts are dependent upon plan-investment returns, changes in pension obligations,
regulatory environments and other economic factors. Additional funding may ultimately be required
if investment returns are insufficient to offset increases in plan obligations.
The company anticipates paying other postretirement benefits of approximately $208 in 2010,
as compared with $187 paid in 2009.
The following benefit payments, which include estimated future service, are expected to be
paid by the company in the next 10 years:
Pension Benefits
Other
U.S.
Int’l.
Benefits
2010
$
855
$
242
$
208
2011
$
851
$
271
$
213
2012
$
861
$
284
$
217
2013
$
884
$
296
$
222
2014
$
913
$
317
$
229
2015–2019
$
4,707
$
1,969
$
1,197
Employee Savings Investment Plan Eligible employees of Chevron and certain of its
subsidiaries participate in the Chevron Employee Savings Investment Plan (ESIP).
Charges to expense for the ESIP represent the company’s contributions to the plan, which are
funded either through the purchase of shares of common stock on the open market or through the
release of common stock held in the leveraged employee stock ownership plan (LESOP), which is
described in the section that follows. Total company matching contributions to employee accounts
within the ESIP were $257, $231 and $206 in 2009, 2008 and 2007, respectively. This cost was
reduced by the value of shares released from the LESOP totaling $184, $40 and $33 in 2009, 2008 and
2007, respectively. The remaining amounts, totaling $73, $191 and $173 in 2009, 2008 and 2007,
respectively, represent open market purchases.
Employee Stock Ownership Plan Within the Chevron ESIP is an employee stock ownership plan (ESOP).
In 1989, Chevron established a LESOP as a constituent part of the ESOP. The LESOP provides partial
prefunding of the company’s future commitments to the ESIP.
As permitted by accounting standards for share-based compensation (ASC 718), the debt of the
LESOP is recorded as debt, and shares pledged as collateral are reported as “Deferred compensation
and benefit plan trust” on the Consolidated Balance Sheet and the Consolidated Statement of Equity.
The company reports compensation expense equal to LESOP debt principal repayments less
dividends received and used by the LESOP for debt service. Interest accrued on LESOP debt is
recorded as interest expense. Dividends paid on LESOP shares are reflected as a reduction of
retained earnings. All LESOP shares are considered outstanding for earnings-per-share computations.
Total credits to expense for the LESOP were $3, $1 and $1 in 2009, 2008 and 2007,
respectively. The net credit for the respective years was composed of credits to compensation
expense of $15, $15 and $17 and charges to interest expense for LESOP debt of $12, $14 and $16.
Of the dividends paid on the LESOP shares, $110, $35 and $8 were used in 2009, 2008 and 2007,
respectively, to service LESOP debt. No contributions were required in 2009, 2008 or 2007 as
dividends received by the LESOP were sufficient to satisfy LESOP debt service.
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 21 Employee Benefit Plans - Continued
Shares held in the LESOP are released and allocated to the accounts of plan
participants based on debt service deemed to be paid in the year in proportion to the total of
current-year and remaining debt service. LESOP shares as of December 31, 2009 and 2008, were as
follows:
Thousands
2009
2008
Allocated shares
21,211
19,651
Unallocated shares
3,636
6,366
Total LESOP shares
24,847
26,017
Benefit Plan Trusts Prior to its acquisition by Chevron, Texaco established a benefit plan
trust for funding obligations under some of its benefit plans. At year-end 2009, the trust
contained 14.2 million shares of Chevron treasury stock. The trust will sell the shares or use the
dividends from the shares to pay benefits only to the extent that the company does not pay such
benefits. The company intends to continue to pay its obligations under the benefit plans. The
trustee will vote the shares held in the trust as instructed by the trust’s beneficiaries. The
shares held in the trust are not considered outstanding for earnings-per-share purposes until
distributed or sold by the trust in payment of benefit obligations.
Prior to its acquisition by Chevron, Unocal established various grantor trusts to fund
obligations under some of its benefit plans, including the deferred compensation and supplemental
retirement plans. At December 31, 2009 and 2008, trust assets of $57 and $60, respectively, were
invested primarily in interest-earning accounts.
Employee Incentive Plans Effective January 2008, the company established the Chevron Incentive Plan
(CIP), a single annual cash bonus plan for eligible employees that links awards to corporate, unit
and individual performance in the prior year. This plan replaced other cash bonus programs, which
primarily included the Management Incentive Plan (MIP) and the Chevron Success Sharing program. In
2009 and 2008, charges to expense for cash bonuses were $561 and $757, respectively. In 2007,
charges to expense for MIP were $184 and charges for other cash bonus programs were $431. Chevron
also has the LTIP for officers and other regular salaried employees of the company and its
subsidiaries who hold positions of significant responsibility. Awards under the LTIP consist of
stock options and other share-based compensation that are described in Note 20, on page FS-51.
Note 22
Other Contingencies and Commitments
Income TaxesThe 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 15 beginning on page FS-46 for a
discussion of the periods for which tax returns have been audited for the company’s 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 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.
GuaranteesThe company’s guarantee of approximately $600 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 over time as certain fees are paid by the affiliate. There are numerous
cross-indemnity agreements with the affiliate and the other partners to permit recovery of any
amounts paid under the guarantee. Chevron has recorded no liability for its obligation under this
guarantee.
IndemnificationsThe 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
company’s interests in those investments. The company would be required to perform if the
indemnified liabilities become actual losses. Were that to occur, the company could be required to
make future payments up to $300. Through the end of 2009, the company paid $48 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 Texaco’s 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 had to be asserted by February 2009 for Equilon indemnities and must be
asserted 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. Management does
not believe this letter or any other information provides a basis to estimate the amount, if any,
of a range of loss or potential range of loss with respect to either
the Equilon or the Motiva indemnities. The company posts no assets as collateral and has made no
payments under the indemnities.
Note 22 Other Contingencies and Commitments - Continued
The amounts payable for the indemnities described in the preceding paragraph 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. The acquirer of those
assets shared in certain environmental remediation costs up to a maximum obligation of $200, which
had been reached at December 31, 2009. Under the indemnification agreement, after reaching the $200
obligation, Chevron is solely responsible until April 2022, when the indemnification expires. The
environmental conditions or events that are subject to these indemnities must have arisen prior to
the sale of the assets in 1997.
Although the company has provided for known obligations under this indemnity 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.
Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay
AgreementsThe 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 company’s business. The
aggregate approximate amounts of required payments under these various commitments are: 2010 –
$7,500; 2011 – $4,300; 2012 – $1,400; 2013 – $1,400; 2014 – $1,000; 2015 and after – $4,100. A
portion of these commitments may ultimately be shared with project partners. Total payments under
the agreements were approximately $8,100 in 2009, $5,100 in 2008 and $3,700 in 2007.
EnvironmentalThe company is subject to loss contingencies pursuant to laws, regulations, private
claims and legal proceedings related to environmental matters that are subject to legal settlements
or that in the future may require the company to take action to correct or ameliorate the effects
on the environment of prior release of chemicals or petroleum substances, including MTBE, by the
company or other parties. Such contingencies may exist for various sites, including, but not
limited to, federal Superfund sites and analogous sites under state laws, refineries, crude-oil fields, service stations, terminals, land development
areas, and mining operations,
whether operating, closed or divested. These future costs are not
fully determinable due to such factors as the unknown magnitude of possible contamination, the
unknown timing and extent of the corrective actions that may be required, the determination of the
company’s 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 company’s competitive position relative to other U.S. or international petroleum or
chemical companies.
Chevron’s environmental reserve as of December 31, 2009, was $1,700. Included in this balance
were remediation activities at approximately 250 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 company’s remediation reserve for these sites at year-end 2009 was $185.
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 company’s results of operations, consolidated financial
position or liquidity.
Of the remaining year-end 2009 environmental reserves balance of $1,515, $820 related to the
company’s U.S. downstream operations, including refineries and other plants, marketing locations
(i.e., service stations and terminals), and pipelines. The remaining $695 was associated with
various sites in international downstream ($107), upstream ($369), chemicals ($149) and other
businesses ($70). Liabilities at all sites, whether operating, closed or divested, were primarily
associated with the company’s 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
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts
Note 22 Other Contingencies and Commitments - Continued
States include the Resource Conservation and Recovery Act and various state or local regulations. No single remediation site at year-end 2009
had a recorded liability that was material to the company’s results of operations, consolidated
financial position or liquidity.
It is likely that the company will continue to incur additional liabilities, beyond those
recorded, for environmental remediation relating to past operations. These future costs are not
fully determinable due to such factors as the unknown magnitude of possible contamination, the
unknown timing and extent of the corrective actions that may be required, the determination of the
company’s liability in proportion to other responsible parties, and the extent to which such costs
are recoverable from third parties.
Refer to Note 23 for a discussion of the company’s asset retirement obligations.
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 Chevron’s interests in four producing zones at the Naval Petroleum Reserve at Elk Hills,
California, for the time when the remaining interests in these zones were owned by the U.S.
Department of Energy. A wide range remains for a possible net settlement amount for the four zones.
For this range of settlement, Chevron estimates its maximum possible net before-tax liability at
approximately $200, and the possible maximum net amount that could be owed to Chevron is estimated
at about $150. The timing of the settlement and the exact amount within this range of estimates are
uncertain.
Other Contingencies Chevron receives claims from and submits claims to customers; trading partners;
U.S. federal, state and local regulatory bodies; governments; contractors; insurers; and suppliers.
The amounts of these claims, individually and in the aggregate, may be significant and take lengthy
periods to resolve.
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.
Note 23
Asset Retirement Obligations
In accordance with accounting standards for asset retirement obligations (ASC 410), the
company records the fair value of a liability for an asset retirement obligation (ARO) when there
is a legal obligation associated with the retirement of a tangible long-lived asset and the
liability can be reasonably estimated. The legal obligation to perform the asset retirement
activity is unconditional even though uncertainty may exist about the timing and/or method of
settlement that may be beyond the company’s control. This uncertainty about the timing and/or
method of settlement is factored into the measurement of the liability when sufficient information
exists to reasonably estimate fair value. The legal obligations associated with the retirement of
the tangible long-lived assets require recognition in certain circumstances including: (1) the
present value of a liability and offsetting asset for an ARO, (2) the subsequent accretion of that
liability and depreciation of the asset, and (3) the periodic review of the ARO liability estimates
and discount rates.
Accounting standards for asset retirement obligations primarily affect the company’s
accounting for crude-oil and natural-gas producing assets. No significant AROs associated with any
legal obligations to retire refining, marketing and transportation (downstream) and chemical
long-lived assets have been recognized, as indeterminate settlement dates for the asset retirements
prevent estimation of the fair value of the associated ARO. The company performs periodic reviews
of its downstream and chemical long-lived assets for any changes in facts and circumstances that
might require recognition of a retirement obligation.
The following table indicates the changes to the company’s before-tax asset retirement
obligations in 2009, 2008 and 2007:
2009
2008
2007
Balance at January 1
$
9,395
$
8,253
$
5,773
Liabilities incurred
144
308
178
Liabilities settled
(757
)
(973
)
(818
)
Accretion expense
463
430
399
*
Revisions in estimated cash flows
930
1,377
2,721
Balance at December 31
$
10,175
$
9,395
$
8,253
*
Includes $175 for revision to the ARO liability retained on properties that had been
sold.
In the table above, the amounts associated with “Revisions in estimated cash flows”
reflect increasing costs to abandon onshore and offshore wells, equipment and facilities. The
long-term portion of the $10,175 balance at the end of 2009 was $9,289.
Earnings in 2009 included gains of approximately $1,000 relating to the sale of nonstrategic
properties. Of this amount, approximately $600 and $400 related to downstream and upstream assets,
respectively. Earnings in 2008 included gains of approximately $1,200 relating to the sale of
nonstrategic properties. Of this amount, approximately $1,000 related to upstream assets. Earnings
in 2007 included gains of approximately $2,000 relating to the sale of nonstrategic properties. Of
this amount, approximately $1,100 related to downstream assets and $680 related to the sale of the
company’s investment in Dynegy, Inc.
Other financial information is as follows:
Year ended December 31
2009
2008
2007
Total financing interest and debt costs
$
301
$
256
$
468
Less: Capitalized interest
273
256
302
Interest and debt expense
$
28
$
–
$
166
Research and development expenses
$
603
$
702
$
510
Foreign currency effects*
$
(744
)
$
862
$
(352
)
*
Includes $(194), $420 and $18 in 2009, 2008 and 2007, respectively, for the company’s share of
equity affiliates’ foreign currency effects.
The excess of replacement cost over the carrying value of inventories for which the Last-In,
First-Out (LIFO) method is used was $5,491 and $9,368 at December 31, 2009 and 2008, respectively.
Replacement cost is generally based on average acquisition costs for the year. LIFO (charges)
profits of $(168), $210 and $113 were included in earnings for the years 2009, 2008 and 2007,
respectively.
The company has $4,618 in goodwill on the Consolidated Balance Sheet related to its 2005
acquisition of Unocal. Under the accounting standard for goodwill
(ASC 350), the
company tested this goodwill for impairment during 2009 and concluded no impairment was necessary.
Events subsequent to December 31, 2009, were evaluated until the time of the Form 10-K filing with
the Securities and Exchange Commission on February 25, 2010.
Note 25
Assets Held for Sale
At December 31, 2009, the company reported no assets as “Assets held for sale” (AHS) on the
Consolidated Balance Sheet. At December 31, 2008, $252 of net properties, plant and equipment were
reported as AHS. Assets in this category are related to groups of service stations, aviation
facilities, lubricants blending plants, and commercial and industrial fuels business. These assets
were sold in 2009.
Note 26
Earnings Per Share
Basic earnings per share (EPS) is based upon Net Income Attributable to Chevron Corporation
(“earnings”) less preferred stock dividend requirements and includes the effects of deferrals of
salary and other compensation awards that are invested in Chevron stock units by certain officers
and employees of the company and the company’s share of stock transactions of affiliates, which,
under the applicable accounting rules, may be recorded directly to the company’s retained earnings
instead of net income. Diluted EPS includes the effects of these items as well as the
dilutive effects of outstanding stock options awarded under the company’s stock option programs
(refer to Note 20, “Stock Options and Other
Share-Based Compensation,” beginning on page FS-51).
The table below sets forth the computation of basic and diluted EPS:
Year ended December 31
2009
2008
2007
Basic EPS Calculation
Earnings available to common stockholders – Basic1
$
10,483
$
23,931
$
18,688
Weighted-average number of common shares outstanding
1,991
2,037
2,117
Add: Deferred awards held as stock units
1
1
1
Total weighted-average number of common shares outstanding
1,992
2,038
2,118
Per share of common stock
Earnings – Basic
$
5.26
$
11.74
$
8.83
Diluted EPS Calculation
Earnings available to common stockholders – Diluted1
$
10,483
$
23,931
$
18,688
Weighted-average number of common shares outstanding
1,991
2,037
2,117
Add: Deferred awards held as stock units
1
1
1
Add: Dilutive effect of employee stock-based awards
9
12
14
Total weighted-average number of common shares outstanding
2,001
2,050
2,132
Per share of common stock
Earnings – Diluted
$
5.24
$
11.67
$
8.77
1
There was no effect of dividend equivalents paid on stock units or dilutive impact
of employee stock-based awards on earnings.
Supplemental Information on Oil and Gas Producing Activities
Unaudited
In accordance with FASB and SEC disclosure and reporting requirements for oil and gas
producing activities, this section provides supplemental information on oil and gas exploration and
producing activities of the company in seven separate tables. Tables I through IV provide
historical cost information pertaining to costs incurred in exploration, property acquisitions and
development; capitalized costs; and results
of operations. Tables V through VII present information on the company’s estimated net
proved-reserve quantities, standardized measure of estimated discounted future net cash flows
related to proved reserves, and changes in estimated discounted future net cash flows. The Africa
geographic area includes activities principally in Angola, Chad, Nigeria, Republic of the Congo and
Democratic Republic
Table
I - Costs Incurred in Exploration, Property Acquisitions and Development1
Includes costs incurred whether capitalized or expensed. Excludes general
support equipment expenditures. Includes capitalized amounts related to asset retirement
obligations. See Note 23, “Asset Retirement Obligations,” on page FS-60.
2
Includes wells, equipment and facilities associated with proved reserves. Does not
include properties acquired in nonmonetary transactions.
3
Includes $121, $224 and $99 costs incurred prior to assignment of proved reserves in
2009, 2008 and 2007, respectively. Also includes $104 and $12 in 2009 for consolidated Other and
affiliated Other, respectively.
4
Includes cost incurred for oil sands in consolidated Other
and heavy oil in affiliated Other as a result of the update to
Extractive Industries – Oil and Gas (Topic 932).
5
Geographic presentation conformed to 2009 consistent with the presentation of the oil
and gas reserve tables.
Supplemental Information on Oil and Gas Producing Activities
Table II
Capitalized Costs Related to Oil and Gas Producing Activities
of the Congo. The Asia geographic area includes activities principally in Azerbaijan,
Bangladesh, China, Indonesia, Kazakhstan, Myanmar, the Partitioned Zone between Kuwait and Saudi
Arabia, the Philippines, and Thailand. The Other geographic regions include activities in
Argentina, Australia, Brazil, Canada, Colombia, Denmark, the Netherlands, Norway, Trinidad and
Tobago, Venezuela, the United
Kingdom and other countries. Amounts for TCO represent Chevron’s 50 percent equity share of
Tengizchevroil, an exploration and production partnership in the Republic of Kazakhstan. The
affiliated companies Other amounts are composed of the company’s equity interests in Venezuela and
Angola. Refer to Note 12, beginning on page FS-43, for a discussion of the company’s major equity
affiliates.
Table
II - Capitalized Costs Related to Oil and Gas Producing Activities
Includes net capitalized cost for oil sands in consolidated Other
and heavy oil in affiliated Other as a result of the update to
Extractive Industries – Oil and Gas (Topic 932).
2
Geographic presentation conformed to 2009 consistent with the presentation of the oil
and gas reserve tables.
3
Amounts for Affiliated Companies — Other conformed to agreements entered in 2007 and 2008 for Venezuelan affiliates.
Supplemental Information on Oil and Gas Producing Activities
Table III
Results of Operations for Oil and Gas Producing Activities1
The company’s results of operations from oil and gas producing activities for the years 2009,
2008 and 2007 are shown in the following table. Net income from exploration and production
activities as reported on page FS-41 reflects income taxes computed on an effective rate basis.
Income taxes in Table III are based on statutory tax rates, reflecting allowable deductions and tax
credits. Interest income and expense are excluded from the results reported in Table III and from
the net income amounts on page FS-41.
The value of owned production consumed in operations as fuel has been eliminated
from revenues and production expenses, and the related volumes have been deducted from net
production in calculating the unit average sales price and production cost. This has no effect on
the results of producing operations.
2
Includes results of producing operations for oil sands in consolidated Other
and heavy oil in affiliated Other as a result of the update to
Extractive Industries – Oil and Gas (Topic 932).
3
Represents accretion of ARO liability. Refer to Note 23, “Asset Retirement
Obligations,” on page FS-60.
4
Includes foreign currency gains and losses, gains and losses on property dispositions,
and income from operating and technical service agreements.
5
Geographic presentation conformed to 2009 consistent with the presentation of
the oil and gas reserve tables.
The value of owned production consumed in operations as fuel has been eliminated
from revenues and production expenses, and the related volumes have been deducted from net
production in calculating the unit average sales price and production cost. This has no effect on
the results of producing operations.
2
Geographic presentation conformed to 2009 consistent with the presentation of the oil and gas reserve tables.
3
Includes $10 costs incurred prior to assignment of proved reserves in 2007.
4
Represents accretion of ARO liability. Refer to Note 23, “Asset Retirement Obligations,” on page FS-60.
5
Includes foreign currency gains and losses, gains and losses on property dispositions,
and income from operating and technical service agreements.
The value of owned production consumed in operations as fuel has been eliminated
from revenues and production expenses, and the related volumes have been deducted from net
production in calculating the unit average sales price and production cost. This has no effect on
the results of producing operations.
2
Natural gas converted to oil-equivalent gas (OEG) barrels at a rate of 6 MCF = 1 OEG barrel.
3
Includes oil sands in consolidated Other
and heavy oil in affiliated Other as a result of the update to
Extractive Industries – Oil and Gas (Topic 932).
4
Geographic presentation conformed to 2009 consistent with the presentation of the oil and gas reserve tables.
Table V Reserve Quantity Information
Reserves GovernanceThe company has adopted a comprehensive reserves and resource
classification system modeled after a system developed and approved by the Society of Petroleum
Engineers, the World Petroleum Congress and the American Association of Petroleum Geologists. The
system classifies recoverable hydrocarbons into six categories based on their status at the time of
reporting – three deemed commercial and three noncommercial. Within the commercial classification
are proved reserves and two categories of unproved: probable and possible. The noncommercial
categories are also referred to as contingent resources. For reserves estimates to be classified as
proved, they must meet all SEC and company standards.
Proved oil and gas reserves are the estimated quantities that geoscience and engineering data
demonstrate with reasonable certainty to be economically producible in the future from known
reservoirs under existing economic conditions, operating methods, and government regulations. Net
proved reserves exclude royalties and interests owned by others and reflect contractual
arrangements and royalty obligations in effect at the time of the estimate.
Proved reserves are classified as either developed or undeveloped. Proved developed reserves are
the quantities expected to be recovered through existing wells with existing equipment and
operating methods.
Due to the inherent uncertainties and the limited nature of reservoir data, estimates of reserves
are subject to change as additional information becomes available.
Proved reserves are estimated by company asset teams composed of earth scientists and engineers. As
part of the internal control process related to reserves estimation, the com-
pany maintains a Reserves Advisory Committee (RAC) that is chaired by the corporate reserves
manager, who is a member of a corporate department that reports directly to the vice chairman
responsible for the company’s worldwide exploration and production activities. The corporate
reserves manager has more than 30 years experience working in the oil and gas industry and a
Master’s of Science in Petroleum Engineering. All RAC members are knowledgeable in SEC guidelines
for proved reserves classification. The RAC manages its activities through two operating
company-level reserves managers. These two reserves managers are not members of the RAC so as to
preserve the corporate-level independence.
The RAC has the following primary responsibilities: provide independent reviews of the business
units’ recommended reserve changes; confirm that proved reserves are recognized in accordance with
SEC guidelines; determine that reserve volumes are calculated using consistent and appropriate
standards, procedures and technology; and maintain the Corporate Reserves Manual, which provides
standardized procedures used corporatewide for classifying and reporting hydrocarbon reserves.
During the year, the RAC is represented in meetings with each of the company’s upstream business
units to review and discuss reserve changes recommended by the various asset teams. Major changes
are also reviewed with the company’s Strategy and Planning Committee and the Executive Committee,
whose members include the Chief Executive Officer and the Chief Financial Officer. The company’s
annual reserve activity is also reviewed with the Board of Directors. If major changes to reserves
were to occur between the annual reviews, those matters would also be discussed with the Board.
RAC subteams also conduct in-depth reviews during the year of many of the fields that have the
largest proved reserves quantities. These reviews include an examination of the proved-reserve
records and documentation of their alignment with the Corporate Reserves Manual.
Summary of Net Oil and Gas Reserves
20091
20082
20072
Crude Oil
Crude Oil
Crude Oil
Liquids and Synthetic Oil in Millions of Barrels
Condensate
Synthetic
Natural
Condensate
Natural
Condensate
Natural
Natural Gas in Billions of Cubic Feet
NGLs
Oil
Gas
NGLs
Gas
NGLs
Gas
Proved Developed
Consolidated Companies
U.S.
1,122
–
2,314
1,158
2,709
1,238
3,226
Africa
820
–
978
789
1,209
758
1,151
Asia
926
–
5,062
1,094
4,758
722
4,344
Other
267
190
3,051
295
3,163
368
2,978
Total Consolidated
3,135
190
11,405
3,336
11,839
3,086
11,699
Affiliated Companies
TCO
1,256
–
1,830
1,369
1,999
1,273
1,762
Other
97
56
73
263
124
263
117
Total Consolidated and Affiliated Companies
4,488
246
13,308
4,968
13,962
4,622
13,578
Proved Undeveloped
Consolidated Companies
U.S.
239
–
384
312
441
386
451
Africa
426
–
2,043
596
1,847
742
1,898
Asia
245
–
2,798
362
3,238
301
2,863
Other
105
270
5,523
129
1,657
150
2,226
Total Consolidated
1,015
270
10,748
1,399
7,183
1,579
7,438
Affiliated Companies
TCO
690
–
1,003
807
1,176
716
986
Other
54
210
990
176
754
170
138
Total Consolidated and Affiliated Companies
1,759
480
12,741
2,382
9,113
2,465
8,562
Total Proved Reserves
6,247
726
26,049
7,350
23,075
7,087
22,140
1
Based on 12-month average price.
2
Based on year-end prices.
Revised Oil and Gas Reporting In December 2008, the SEC issued its final rule, Modernization
of Oil and Gas Reporting (Release Nos. 33-8995; 34-59192; FR-78). The disclosure requirements under
the final rule became effective for the company with its Form 10-K filing for the year ending
December 31, 2009. The final rule changes a number of oil and gas reserve estimation and disclosure
requirements under SEC Regulations S-K and S-X. Subsequently, the FASB updated Extractive
Industries — Oil and Gas (Topic 932) to align the oil and gas reserves estimation and disclosure
requirements with the SEC’s final rule.
Among the principal changes in the final rule are requirements to use a price based on a 12-month
average for reserve estimation and disclosure instead of a single end-of-year price; expanding the
definition of oil and gas producing activities to include nontraditional sources such as bitumen
extracted from oil sands; permitting the use of new reliable technologies to establish reasonable
certainty of proved reserves; allowing optional disclosure of probable and possible reserves;
modifying the definition of geographic area for disclosure of reserve estimates and production;
amending
disclosures of proved reserve quantities to include separate disclosures of synthetic oil and gas;
expanding proved undeveloped reserves disclosures, including discussion of proved undeveloped
reserves that have remained undeveloped for five years or more; and disclosure of the
qualifications of the chief technical person who oversees the company’s overall reserves estimation
process.
Effect of New Rules The most significant effect of the company’s adopting the new guidance was the
inclusion of Canadian oil sands as synthetic oil in the consolidated companies reserves. As
indicated in Table V, on page FS-72, an additional 460 million BOE were included at year-end 2009.
The synthetic oil reported for affiliated companies represents volumes reclassified from
heavy crude oil to synthetic oil, and does not represent additional reserves. It was
impracticable to estimate the remaining impact of the new rules because of the cost and resources
required to prepare detailed field-level calculations. However, the use of the 12-month average
price had an upward effect on reserves related to production-sharing and variable-royalty contracts
as the 12-month average price for crude oil and
Supplemental Information on Oil and Gas Producing Activities
Table V
Reserve Quantity Information - Continued
natural gas for 2009 was lower than the 2009 year-end spot prices applicable under the old
rules. The ability to use new technologies in reserves determination did not impact reserves
significantly, as most reserve additions and revisions were based on conventional technologies.
Proved Undeveloped Reserve Quantities At the end of 2009, proved undeveloped oil-equivalent
reserves for consolidated companies totaled 3.1 billion barrels. Approximately 58 percent of the
reserves are attributed to natural gas, of which about half were located in Australia in the Other
regions. Crude oil, condensate and NGLs accounted for about 33 percent of the total, with the
largest concentration of these reserves in Africa, Asia and the United States. Synthetic oil
accounted for the balance of the reserves and were located in Canada in the Other regions.
Proved undeveloped reserves of equity affiliates amounted to 1.3 billion oil-equivalent barrels. At
year-end, crude oil, condensate and NGLs represented 58 percent of the total reserves, with the TCO
affiliate accounting for the majority of the amount. Natural gas represented 26 percent of the
total, with over half of these reserves at TCO. The balance is attributed to synthetic oil in
Venezuela in the Other regions.
In 2009, worldwide proved undeveloped oil-equivalent reserves increased by 480 million barrels for
consolidated companies and decreased 19 million barrels for equity affiliates. The largest
increase for consolidated companies was in the Other regions, resulting primarily from initial
recognition of reserves for the Gorgon Project in Australia and addition of synthetic oil
reserves related to Canadian oil sands with adoption of the new definition of oil and gas activity.
Proved undeveloped reserves decreased in Asia, Africa, and the United States, as a result of
development drilling and other activities, which reclassified reserves to proved developed.
Proved undeveloped reserves decreased for affiliated companies. This was primarily associated with
a 146 million barrel reclassification to proved developed as a result of the TCO production
capacity added with the completion of the Sour Gas Injection/Second Generation Plant Projects
(SGI/SGP). The decrease at TCO was partially offset by increased proved undeveloped reserves in
Venezuela and for Angola LNG due to reservoir performance and additional drilling opportunities.
There were no material downward revisions of proved undeveloped reserves for consolidated or
affiliated companies.
Investment to Convert Proved Undeveloped to Proved Developed Reserves During 2009, investments
totaling about $6.9 billion were made by consolidated companies and equity affiliates to advance
the development of proved undeveloped reserves. In the Africa region, $2.5 billion was expended on
various projects, including offshore development projects in Nigeria and Angola, which advanced
development drilling, and the completion of a Nigerian natural gas processing project. In the Asia
region, expenditures during the year totaled $1.5 billion, which included construction on a gas
processing
facility in Thailand and development drilling at a steam-flood project in Indonesia. In the United
States, expenditures totaled $1.7 billion for three offshore development projects in the Gulf of
Mexico and various smaller development projects. In the Other regions, development expenditures
totaled $1.2 billion for a variety of projects including development activities in Australia and
the United Kingdom.
During
the year, eight major development projects that were placed into service resulted in the
recognition of proved developed reserves.
Proved Undeveloped Reserves for 5 Years or More Reserves that remain proved undeveloped for five or
more years are a result of several physical factors that affect optimal project development and
execution, such as the complex nature of the development project in adverse and remote locations,
physical limitations of infrastructure or plant capacities that dictate project timing, compression
projects that are pending reservoir pressure declines, and contractual limitations that dictate
production levels.
Proved undeveloped oil-equivalent reserves for consolidated and affiliated companies totaled 4.4
billion barrels at year-end 2009. Of this total, 1.7 billion barrels corresponds to proved
undeveloped
oil-equivalent reserves that have remained undeveloped for five years or more.
Consolidated companies held approximately 700 million barrels of the proved undeveloped reserves
over five years. In Africa, approximately 400 million barrels were related to deepwater projects
under development. The Asia region held approximately 100 million barrels related to compression
and contract restrictions. The Other regions held about 100 million barrels related to compression
projects in Australia. The balance relates to capacity constraints and various projects in
the United States.
At year end, affiliated companies held about 1.0 billion barrels of proved undeveloped reserves
over five years. TCO accounted for 800 million oil-equivalent barrels of reserves, which was
primarily related to plant capacity limitations. The balance related to capacity limitations at a
synthetic oil project in Venezuela.
Annually,
the company assesses whether any changes have occurred in facts or circumstances, such as changes to
development plans, regulations or government policies, which would warrant a revision to reserve
estimates. For 2009, this assessment did not result in any material changes in reserves classified
as proved undeveloped. Over the past three years, the ratio of proved undeveloped reserves to total
proved reserves has ranged between 35 and 39 percent. The consistent completion of major capital
projects has kept the ratio in a narrow range over this time period.
Proved Reserve Quantities At December 31, 2009, oil-equivalent reserves for the company’s
consolidated operations were 8.3 billion barrels. (Refer to the term “Reserves” on page E-42 for
the definition of oil-equivalent reserves.) Approximately 22 percent of the total reserves were
located
in the United States. For the company’s interests in equity affiliates, oil-equivalent reserves
were 3.0 billion barrels, 80 percent of which were associated with the company’s 50 percent
ownership in TCO.
Aside from the Tengiz Field in the TCO affiliate, no single property accounted for more than 5
percent of the company’s total oil-equivalent proved reserves. About 25 other individual properties
in the company’s portfolio of assets each contained between 1 percent and 5 percent of the
company’s oil-equivalent proved reserves, which in the aggregate accounted for approximately
48
percent of the company’s total proved reserves. These properties were geographically dispersed,
located in the United States, Canada, South America, West Africa, the Middle East, Southeast Asia,
and Australia.
In the United States, total oil-equivalent reserves at year-end 2009 were 1.8 billion barrels.
California properties accounted for approximately 44 percent of the U.S. reserves, with most
classified as heavy oil. Because of heavy oil’s high viscosity and the need to employ enhanced
recovery methods, the producing operations are capital intensive in nature. Most of the company’s
heavy-oil fields in California employ
a continuous steamflooding process. The Gulf of Mexico region contains about 22 percent of the U.S. reserves,
with liquids representing about 15 percent of reserves. Production operations are mostly offshore
and, as a result, are also capital intensive. Other U.S. areas represent the remaining 34 percent
of U.S. reserves, which are about evenly split between liquids and natural gas. For production of
crude oil, some fields utilize enhanced recovery methods, including water-flood and CO2
injection.
For the three years ending December 31, 2009, the pattern of net reserve changes shown in the
following tables are not necessarily indicative of future trends. Apart from acquisitions, the
company’s ability to add proved reserves is affected by, among other things, events and
circumstances that are outside the company’s control, such as delays in government permitting,
partner approvals of development plans, declines in oil and gas prices, OPEC constraints,
geopolitical uncertainties and civil unrest.
The company’s estimated net proved oil and natural gas reserves and changes thereto for the
years 2007, 2008 and 2009 are shown in the following table and on page FS-74.
Net
Proved Reserves of Crude Oil, Condensate, Natural Gas Li qui ds and Synthetic Oil
3
Reserves associated with Venezuela that were reported in other as heavy oil in 2008 and 2007.
4 Included are year-end reserve quantities related to production-sharing contracts (PSC)
(refer to page E-42 for the definition of a PSC). PSC-related reserve quantities are 26
percent, 32 percent and 26 percent for consolidated companies for 2009, 2008 and 2007,
respectively.
5 Includes reserves acquired through nonmonetary transactions.
6 Includes reserves disposed of through nonmonetary transactions.
Supplemental Information on Oil and Gas Producing Activities
Table V Reserve Quantity Information - Continued
Noteworthy amounts in the categories of liquids proved-reserve changes for 2007 through 2009
are discussed below:
Revisions In 2007, net revisions decreased reserves by 146 million barrels for worldwide
consolidated companies and increased reserves by 103 million barrels for equity affiliates. For
consolidated companies, the largest downward net revisions were 89 million barrels in Africa and 54
million barrels in Asia.
In 2008, net revisions increased reserves by 536 million barrels for worldwide consolidated
companies and increased reserves by 267 million barrels for equity affiliates. For consolidated
companies, the largest increase was in the Asia region, which added 574 million barrels. The
majority of the increase was in the Partitioned Zone, as a result of a concession extension, and
Indonesia, due to lower year-end prices. Upward
revisions were also recorded in Kazakhstan and Azerbaijan and were mainly associated with the
effect of lower year-end prices on the calculation of reserves associated with production-sharing
and variable-royalty contracts. In Indonesia, reserves increased due mainly to the impact of lower
year-end prices on the reserve calculations for
production-sharing contracts, as well as a result
of development drilling and improved waterflood and steam-flood performance. These increases were
offset by downward revisions in the United States and Other regions. For affiliated companies, the
249 million-barrel increase for TCO was due to the effect of lower year-end prices on the royalty
determination and facility optimization at the Tengiz and Korolev fields.
In 2009, net revisions increased reserves by 355 million barrels for worldwide consolidated
companies and decreased reserves by 187 million barrels for equity affiliates. For consolidated
companies, the largest increase was 460 million barrels in the Other regions due to the inclusion
of synthetic oil related to Canadian oil sands. In the United States, reserves increased 63
million barrels as a result of development drilling and performance revisions. The increases were
partially offset by decreases of 121 million barrels in Asia and 46 million barrels in Africa. In
Asia, decreases in Indonesia and Azerbaijan were driven by the effect of higher 12-month average
prices on the calculation of reserves associated with
production-sharing contracts and the effect
of reservoir performance revisions. In Africa, reserves in Nigeria declined as a result of higher
prices on production-sharing contracts and reservoir performance.
For affiliated companies, TCO declined by 184 million-barrels primarily due to the effect of
higher 12-month average prices on royalty determination. For Other affiliated companies, 266
million barrels of heavy crude oil were reclassified to synthetic oil for the activities in
Venezuela.
Improved Recovery In 2007, improved recovery increased liquids volumes by 20 million barrels
worldwide. No addition was individually significant.
In 2008, improved recovery increased worldwide liquids volumes by 37 million barrels. For
consolidated companies, the largest addition was in the Asia region related to gas reinjection in
Kazakhstan. Affiliated companies increased reserves 10 million barrels due to improved secondary
recovery at Boscan.
In 2009, improved recovery increased liquids volumes by 86 million barrels worldwide.
Consolidated companies accounted for 50 million barrels. The largest addition was related to
improved secondary recovery in Nigeria. Affiliated companies increased reserves 36 million barrels
due to improvements related to the TCO SGI/SGP facilities.
Extensions and Discoveries In 2007, extensions and discoveries increased liquids volumes by 60
million barrels worldwide. The largest additions were 36 million barrels in the United States,
mainly for the deepwater Tahiti and Mad Dog fields in the Gulf of Mexico.
In 2008, extensions and discoveries increased consolidated company reserves 33 million barrels
worldwide. The United States increased reserves 17 million barrels, primarily in the Gulf of
Mexico. The Africa, Asia, and Other regions increased reserves 16 million barrels with no one
country resulting in additions greater than 5 million barrels.
In 2009, extensions and discoveries increased liquids volumes by 52 million barrels worldwide.
The largest additions were 33 million barrels in Other regions related to the Gorgon Project in
Australia and delineation drilling in Argentina. Africa and the United States accounted for 10
million barrels and 6 million barrels, respectively.
Purchases In 2007, acquisitions of 316 million barrels for equity affiliates related to the
formation of a new Hamaca equity affiliate in Venezuela.
Sales In 2007, affiliated company sales of 432 million barrels related to the dissolution of a
Hamaca equity affiliate in Venezuela.
1 Includes reserves acquired through nonmonetary transactions.
2 Includes year-end reserve quantities related to production-sharing contracts (PSC)
(refer to page E-42 for the definition of a PSC). PSC-related reserve quantities are 31
percent, 40 percent and 37 percent for consolidated companies for 2009, 2008 and 2007,
respectively.
3 Includes reserves disposed of through nonmonetary transactions.
Noteworthy amounts in the categories of natural gas
proved-reserve changes for 2007 through
2009 are discussed below:
Revisions In 2007, net revisions increased reserves for consolidated companies by 395 BCF and
increased reserves for affiliated companies by 73 BCF. For consolidated companies, net increases of
346 BCF in Asia and 209 BCF in the United States were partially offset by downward revisions of 160
BCF in Africa and Other regions. In the Asia region, drilling activities in Thailand added 360 BCF,
which were partially offset by downward revisions in Azerbaijan and Kazakhstan due to the impact of
higher prices. In the United States, improved reservoir performance for many fields contributed to
the increase with the largest portion in the
mid-continent areas. Decreases in Africa were
primarily due to a 136 BCF downward revision in Nigeria resulting from field performance. The Other
regions had net downward revisions of 19 BCF. A 185 BCF downward revision in Australia due to
drilling results and other smaller declines
were mostly offset by improved reservoir performance in Trinidad and Tobago which added 188 BCF.
TCO had an upward revision of 75 BCF associated with improved reservoir performance and
development activities. This upward revision was net of a negative impact due to higher year-end
prices on royalty determination.
In 2008, net revisions increased reserves for consolidated companies by 1,166 BCF and
increased reserves for affiliated companies by 1,130 BCF. In the Asia region, positive revisions
totaled 1,073 BCF for consolidated companies. Almost half of the increase was attributed to the
Karachaganak Field in Kazakhstan, due mainly to the effects of low year-end prices on the
production-sharing contract and the results of development drilling and improved recovery. Other
large upward revisions were recorded for the Pattani Field in Thailand due to a successful drilling
campaign.
For the TCO affiliate in Kazakhstan, an increase of 498 BCF reflected the impacts of lower
year-end prices on royalty determination and facility optimization. Reserves associated
Supplemental Information on Oil and Gas Producing Activities
with the Angola LNG project accounted for a majority of the 632 BCF increase in Other affiliated companies.
In 2009, net revisions increased reserves by 569 BCF for consolidated companies and decreased
reserves by 44 BCF for affiliated companies. For consolidated companies, net increases were 493 BCF
in Asia primarily as a result of reservoir studies in Bangladesh and development drilling in
Thailand. These results were partially offset by a downward revision due to the impact of higher
prices on production-sharing contracts in Myanmar. The United States and Other regions increased
reserves 39 BCF and 33 BCF, respectively. In the United States, development drilling in the Gulf of
Mexico was partially offset by performance revisions in the California and mid-continent areas. In
Other regions, improved reservoir performance and compression in Australia was partially offset by
the effect of higher prices on production-sharing contracts in Trinidad.
For equity affiliates, a downward revision of 237 BCF at TCO was due to the effect of higher
prices on royalty determination and an increase in gas injection for SGI/SGP facilities. This
decline was partially offset by performance and drilling opportunities related to the Angola LNG
project.
Extensions and Discoveries In 2007, extensions and discoveries accounted for an increase of
518 BCF worldwide. The largest addition was 330 BCF in Bangladesh, the result of drilling
activities. Other additions were not individually significant.
In 2009, worldwide extensions and discoveries of 4,387 BCF were attributed to consolidated
companies. The Gorgon Project in Australia accounted for essentially all of the 4,277 BCF additions
in the Other regions. In Asia, development drilling in Thailand accounted for the majority of the
increase. In the United States, delineation drilling in California accounted for the majority of
the increase.
Purchases In 2007, purchases of natural gas reserves were 141 BCF for consolidated companies,
which include the acquisition of an additional interest in the Bibiyana Field in Bangladesh.
Affiliated company purchases of 211 BCF related to the formation of a new Hamaca equity affiliate
in Venezuela and an initial booking related to the Angola LNG project.
Sales In 2007, sales were 76 BCF and 175 BCF for consolidated companies and equity affiliates,
respectively. The affiliated company sales related to the dissolution of a Hamaca equity affiliate
in Venezuela.
In 2009, worldwide sales of 117 BCF were related to consolidated companies. For the Other
regions, the sale of properties in Argentina accounted for 84 BCF. The sale of properties in the
Gulf of Mexico accounted for the majority of the 33 BCF decrease in the United States.
Table VI
Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves
The standardized measure of discounted future net cash flows, related to the preceding proved
oil and gas reserves, is calculated in accordance with the requirements of the FASB. Estimated
future cash inflows from production are computed by applying
12 month-average prices for oil and
gas to year-end quantities of estimated net proved reserves. Future price changes are limited to
those provided by contractual arrangements in existence at the end of each reporting year. Future
development and production costs are those estimated future expenditures necessary to develop and
produce year-end estimated proved reserves based on year-end cost indices, assuming continuation of
year-end economic conditions, and include estimated costs for asset retirement obligations.
Estimated future income taxes are calculated by applying appropriate year-end statutory tax rates.
These rates reflect allowable deductions and tax credits and are applied to estimated future pretax
net cash flows, less the tax basis of related assets. Discounted future net cash flows are
calculated using 10 percent midperiod discount factors. Discounting requires a year-by-year
estimate of when future expenditures will be incurred and when reserves will be produced.
The information provided does not represent management’s estimate of the company’s expected
future cash flows or value of proved oil and gas reserves. Estimates of proved-reserve quantities
are imprecise and change over time as new information becomes available. Moreover, probable and
possible reserves, which may become proved in the future, are excluded from the calculations. The
arbitrary valuation prescribed by the FASB requires assumptions as to the timing and amount of
future development and production costs. The calculations are made as of December 31 each year and
should not be relied upon as an indication of the company’s future cash flows or value of its oil
and gas reserves. In the following table, “Standardized Measure Net Cash Flows” refers to the
standardized measure of discounted future net cash flows.
Supplemental Information on Oil and Gas Producing Activities
Table VII
Changes in the Standardized Measure of Discounted
Future Net Cash Flows From Proved Reserves
The changes in present values between years, which can be significant, reflect changes
in estimated proved-reserve quantities and prices and assumptions used in forecasting
production volumes and costs. Changes in the timing of production are included with “Revisions of
previous quantity estimates.”
By-Laws of Chevron Corporation, as amended January 30,2008, filed as Exhibit 3.1 to Chevron Corporation’s
Current Report on
Form 8-K
dated February 1, 2008, and incorporated herein by
reference.
4
.1
Pursuant to the Instructions to Exhibits, certain instruments
defining the rights of holders of long-term debt securities of
the company and its consolidated subsidiaries are not filed
because the total amount of securities authorized under any such
instrument does not exceed 10 percent of the total assets
of the corporation and its subsidiaries on a consolidated basis.
A copy of such instrument will be furnished to the Commission
upon request.
4
.2
Confidential Stockholder Voting Policy of Chevron Corporation,
filed as Exhibit 4.2 to Chevron Corporation’s Annual
Report on
Form 10-K
for the year ended December 31, 2008, and incorporated
herein by reference.
10
.1
Chevron Corporation Non-Employee Directors’ Equity
Compensation and Deferral Plan, filed as Exhibit 10.1 to
Chevron Corporation’s Annual Report on
Form 10-K
for the year ended December 31, 2008, and incorporated
herein by reference.
10
.2
Chevron Incentive Plan, filed as Exhibit 10.2 to Chevron
Corporation’s Annual Report on
Form 10-K
for the year ended December 31, 2008, and incorporated
herein by reference.
10
.3
Long-Term Incentive Plan of Chevron Corporation, filed as
Exhibit 10.3 to Chevron Corporation’s Annual Report on
Form 10-K
for the year ended December 31, 2008, and incorporated
herein by reference.
10
.4
Chevron Corporation Deferred Compensation Plan for Management
Employees, as amended and restated on December 7, 2005,
filed as Exhibit 10.5 to Chevron Corporation’s Current
Report on
Form 8-K
dated December 7, 2005, and incorporated herein by
reference.
10
.5
Chevron Corporation Deferred Compensation Plan for Management
Employees II, filed as Exhibit 10.5 to Chevron
Corporation’s Annual Report on
Form 10-K
for the year ended December 31, 2008, and incorporated
herein by reference.
10
.6
Chevron Corporation Retirement Restoration Plan, filed as
Exhibit 10.6 to Chevron Corporation’s Annual Report on
Form 10-K
for the year ended December 31, 2008, and incorporated
herein by reference.
10
.7
Chevron Corporation ESIP Restoration Plan, filed as
Exhibit 10.7 to Chevron Corporation’s Annual Report on
Form 10-K
for the year ended December 31, 2008, and incorporated
herein by reference.
10
.8
Texaco Inc. Stock Incentive Plan, adopted May 9, 1989, as
amended May 13, 1993, and May 13, 1997, filed as
Exhibit 10.13 to Chevron Corporation’s Annual Report
on
Form 10-K
for the year ended December 31, 2001, and incorporated
herein by reference.
10
.9
Supplemental Pension Plan of Texaco Inc., dated June 26,
1975, filed as Exhibit 10.14 to Chevron Corporation’s
Annual Report on
Form 10-K
for the year ended December 31, 2001, and incorporated
herein by reference.
10
.10
Supplemental Bonus Retirement Plan of Texaco Inc., dated
May 1, 1981, filed as Exhibit 10.15 to Chevron
Corporation’s Annual Report on
Form 10-K
for the year ended December 31, 2001, and incorporated
herein by reference.
10
.11
Texaco Inc. Director and Employee Deferral Plan approved
March 28, 1997, filed as Exhibit 10.16 to Chevron
Corporation’s Annual Report on
Form 10-K
for the year ended December 31, 2001, and incorporated
herein by reference.
10
.12
Summary of Chevron Incentive Plan Award Criteria, filed as
Exhibit 10.13 to Chevron Corporation’s Annual Report
on
Form 10-K
for the year ended December 31, 2008, and incorporated
herein by reference.
10
.13
Chevron Corporation Change in Control Surplus Employee Severance
Program for Salary Grades 41 through 43, filed as
Exhibit 10.1 to Chevron Corporation’s Current Report
on
Form 8-K
dated December 6, 2006, and incorporated herein by
reference.
10
.14
Chevron Corporation Benefit Protection Program, filed as
Exhibit 10.2 to Chevron Corporation’s Current Report
on
Form 8-K
dated December 6, 2006, and incorporated herein by
reference.
10
.15*
Form of Grant Agreement under the Long-Term Incentive Plan of
Chevron Corporation.
10
.16*
Form of Restricted Stock Unit Grant Agreement under the
Long-Term Incentive Plan of Chevron Corporation.
Form of Retainer Stock Option Agreement under the Chevron
Corporation Non-Employee Directors’ Equity Compensation and
Deferral Plan.
10
.18
Form of Stock Units Agreement under the Chevron Corporation
Non-Employee Directors’ Equity Compensation and Deferral
Plan, filed as Exhibit 10.19 to Chevron Corporation’s
Annual Report on
Form 10-K
for the year ended December 31, 2008, and incorporated
herein by reference.
10
.19*
Employment Agreement, dated October 3, 2002, between
Chevron Corporation and Charles A. James.
10
.20*
Termination Agreement, dated January 5, 2010, between
Chevron Corporation and Charles A. James.
12
.1*
Computation of Ratio of Earnings to Fixed Charges
(page E-22).
21
.1*
Subsidiaries of Chevron Corporation (pages
E-23 through
E-24).
Powers of Attorney for directors and certain officers of Chevron
Corporation, authorizing the signing of the Annual Report on
Form 10-K
on their behalf.
31
.1*
Rule 13a-14(a)/15d-14(a)
Certification of the company’s Chief Executive Officer
(page E-38).
31
.2*
Rule 13a-14(a)/15d-14(a)
Certification of the company’s Chief Financial Officer
(page E-39).
32
.1*
Section 1350 Certification of the company’s Chief
Executive Officer
(page E-
40).
32
.2*
Section 1350 Certification of the company’s Chief
Financial Officer
(page E-
41).
99
.1*
Definitions of Selected Energy and Financial Terms (pages E- 42
through
E-44).
101
.INS*
XBRL Instance Document
101
.SCH*
XBRL Schema Document
101
.CAL*
XBRL Calculation Linkbase Document
101
.LAB*
XBRL Label Linkbase Document
101
.PRE*
XBRL Presentation Linkbase Document
101
.DEF*
XBRL Definition Linkbase Document
Attached as Exhibit 101 to this report are documents
formatted in XBRL (Extensible Business Reporting Language).
Users of this data are advised pursuant to Rule 406T of
Regulation S-T
that the interactive data file is deemed not filed or part of a
registration statement or prospectus for purposes of
section 11 or 12 of the Securities Act of 1933, is deemed
not filed for purposes of section 18 of the Securities
Exchange Act of 1934, and is otherwise not subject to liability
under these sections. The financial information contained in the
XBRL-related documents is “unaudited” or
“unreviewed.”
Copies of above exhibits not contained herein are available to
any security holder upon written request to the Corporate
Governance Department, Chevron Corporation, 6001 Bollinger
Canyon Road, San Ramon, California94583-2324.
E-2
Dates Referenced Herein and Documents Incorporated by Reference