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Chevron Corporation 10-K 2011 Documents found in this filing:
Table of Contents
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
þ ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31,
2010
OR
o TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from
to
Commission File Number
001-00368
(Exact name of registrant as specified in its charter)
Registrant’s telephone number, including area code
(925) 842-1000
Securities registered pursuant to Section 12(b) of the Act:
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):
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 — $136,438,881,628 (As of June 30, 2010)
Number of Shares of Common Stock outstanding as of
February 18, 2011 — 2,007,449,583
DOCUMENTS INCORPORATED BY REFERENCE
(To The Extent Indicated Herein)
Notice of the 2011 Annual Meeting and 2011 Proxy Statement, to
be filed pursuant to
Rule 14a-6(b)
under the Securities Exchange Act of 1934, in connection with
the company’s 2011 Annual Meeting of Stockholders (in
Part III)
Table of Contents
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 32 through
34 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.
Table of Contents
Chevron
Corporation,*
a Delaware corporation, manages its investments in subsidiaries
and affiliates and provides administrative, financial,
management and technology support to U.S. and international
subsidiaries that engage in fully integrated petroleum
operations, chemicals operations, mining operations, power
generation and energy services. Upstream operations consist
primarily of exploring for, developing and producing crude oil
and natural gas; processing, liquefaction, transportation and
regasification associated with liquefied natural gas;
transporting crude oil by major international oil export
pipelines; transporting, storage and marketing of natural gas;
and a
gas-to-liquids
project. Downstream operations consist primarily of refining of
crude oil into petroleum products; marketing of crude oil
and refined products; transporting of crude oil and refined
products by pipeline, marine vessel, motor equipment and
rail car; and manufacturing and marketing of commodity
petrochemicals, plastics for industrial uses and fuel and
lubricant additives.
A list of the company’s major subsidiaries is presented on
pages E-4
and E-5. As
of December 31, 2010, Chevron had approximately
62,000 employees (including about 3,900 service station
employees). Approximately 30,000 employees (including about
3,600 service station employees), or 48 percent, were
employed in U.S. operations.
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, transportation and chemicals entities and
national petroleum companies in the sale or acquisition of
various goods or services in many national and international
markets.
Refer to pages FS-2 through FS-10 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.
Table of Contents
Chevron’s primary objective is to create shareholder value
and achieve sustained financial returns from its operations that
will enable it to outperform its competitors. In the upstream,
the company’s strategies are to grow profitably in core
areas, 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 grow earnings across the
value chain. The company also continues to utilize technology
across all its businesses to differentiate performance, and to
invest in profitable renewable energy and energy efficiency
solutions.
The upstream and downstream activities of the company and its
equity affiliates are widely dispersed geographically, with
operations in North America, South America, Europe, Africa, Asia
and Australia. Tabulations of segment sales and other operating
revenues, earnings and income taxes for the three years ending
December 31, 2010, and assets as of the end of 2010 and
2009 — for the United States and the company’s
international geographic areas — are in Note 11
to the Consolidated Financial Statements beginning on
page FS-41.
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 2010 were $21.8 billion, including
$1.4 billion for the company’s share of
equity-affiliate expenditures. In 2009 and 2008, expenditures
were $22.2 billion and $22.8 billion, respectively,
including the company’s share of affiliates’
expenditures of $1.6 billion in 2009 and $2.3 billion
in 2008.
Of the $21.8 billion in expenditures for 2010,
87 percent, or $18.9 billion, was related to upstream
activities. Approximately 80 percent was expended for
upstream operations in 2009 and 2008. International upstream
accounted for about 82 percent of the worldwide upstream
investment in 2010, more than 80 percent in 2009 and about
70 percent in 2008, reflecting the company’s
continuing focus on opportunities available outside the United
States.
In 2011, the company estimates capital and exploratory
expenditures will be $26.0 billion, including
$2.0 billion of spending by affiliates. Approximately
85 percent of the total, or $22.6 billion, is budgeted
for exploration and production activities, with
$17.2 billion of that amount for projects outside the
United States. Acquisition costs associated with the announced
purchase of Atlas Energy, Inc., are not included.
Refer also to a discussion of the company’s capital and
exploratory expenditures on
page FS-13.
The table on the following page summarizes the net production of
liquids and natural gas for 2010 and 2009 by the company and its
affiliates. Worldwide oil-equivalent production, including
volumes from synthetic oil in 2010 and oil sands in 2009, was
2.763 million barrels per day, up about 2 percent from
2009. The increase was mainly associated with the
start-up and
ramp-up of
several major capital projects — the expansion at
Tengiz in Kazakhstan, the Tahiti Field in the U.S. Gulf of
Mexico, Frade in Brazil, Agbami in Nigeria, and
Tombua-Landana
and Mafumeira Norte in Angola. Normal field declines and the
impact of higher prices on cost-recovery volumes and other
contractual provisions decreased net production from last
year’s comparative period. Refer to the “Results of
Operations” section beginning on
page FS-7
for a detailed discussion of the factors explaining the
2008 — 2010 changes in production for crude oil and
natural gas liquids, and natural gas.
The company estimates its average worldwide oil-equivalent
production in 2011 will be approximately 2.790 million
barrels per day based on the average West Texas Intermediate
crude oil price of $79 per barrel in 2010. 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 production-sharing and variable-royalty
provisions of certain agreements, changes in fiscal terms or
restrictions on the scope of company operations, delays in
project startups, fluctuations in demand for natural gas in
various markets, weather conditions that may shut in production,
civil unrest, changing geopolitics, delays in completion of
maintenance turnarounds,
greater-than-expected
declines in production from mature fields, or other disruptions
to operations. The outlook for future production levels is also
affected by the size and number of economic investment
opportunities and, for new large-scale projects, the time lag
between initial exploration and the beginning of production.
Refer to the “Review of Ongoing Exploration and Production
Activities in Key Areas,” beginning on page 9, for a
discussion of the company’s major crude oil and natural gas
development projects.
Table of Contents
Net
Production of Crude Oil and Natural Gas Liquids and Natural
Gas1,2,3
Table of Contents
Refer to Table IV on
page FS-71
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 2010, 2009 and 2008.
The following table summarizes gross and net productive wells at
year-end 2010 for the company and its affiliates:
Productive
Oil and Gas
Wells1 at
December 31, 2010
Refer to Table V beginning on
page FS-71
for a tabulation of the company’s proved net crude oil and
natural gas reserves by geographic area, at the beginning of
2008 and each year-end from 2008 through 2010. A discussion of
reserves governance and major changes to proved reserves by
geographic area for the three-year period ending
December 31, 2010 is summarized in the discussion for Table
V. Discussion is also provided beginning on
page FS-71
regarding the nature of, status of and planned future activities
associated with the development of proved undeveloped reserves.
The company recognizes reserves for projects with various
development periods, sometimes exceeding five years. The
external factors that impact the duration of a project include
scope and complexity, remoteness or adverse operating
conditions, infrastructure constraints, and contractual
limitations. During 2010, the company provided crude oil and
natural gas reserves estimates for 2009 to the Department of
Energy, Energy Information Administration (EIA) that agree with
the 2009 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 2009 Annual Report on
Form 10-K.
During 2011, the company will file estimates of crude oil and
natural gas reserves with the Department of Energy, EIA,
consistent with the 2010 reserve data reported in Table V.
Table of Contents
The net proved reserve balances at the end of each of the three
years 2008 through 2010 are shown in the following table.
At December 31, 2010, 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.
Acreage1,2
at December 31, 2010
(Thousands of Acres)
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The company sells crude oil and natural gas from its producing
operations under a variety of contractual obligations. Most
contracts generally commit the company to sell quantities based
on production from specified properties, but some natural gas
sales contracts specify delivery of fixed and determinable
quantities, as discussed below.
In the United States, the company is contractually committed to
deliver to third parties 253 billion cubic feet of natural
gas through 2013. The company believes it can satisfy these
contracts through a combination of equity production from the
company’s proved developed U.S. reserves and third
party purchases. These contracts include a variety of pricing
terms, including both index and fixed-price contracts.
Outside the United States, the company is contractually
committed to deliver a total of 953 billion cubic feet of
natural gas from 2011 through 2013 from Australia, Colombia,
Denmark and the Philippines to third parties. The sales
contracts contain variable pricing formulas that are generally
referenced to the prevailing market price for crude oil, natural
gas or other petroleum products at the time of delivery. The
company believes it can satisfy these contracts from quantities
available from production of the company’s proved developed
reserves in these countries.
Refer to Table I on
page FS-66
for details associated with the company’s development
expenditures and costs of proved property acquisitions for 2010,
2009 and 2008.
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, 2010. 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
Table of Contents
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, 2010. “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
Refer to Table I on
page FS-66
for detail of the company’s exploration expenditures and
costs of unproved property acquisitions for 2010, 2009 and 2008.
Chevron’s 2010 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-25.
The discussion that follows references the status of proved
reserves recognition for significant long-lead-time projects not
on production and for projects recently placed on production.
Reserves are not discussed for recent discoveries that have not
advanced to a project stage or for mature areas of production
that do not have individual projects requiring significant
levels of capital or exploratory investment. Amounts indicated
for project costs represent total project costs, not the
company’s share of costs for projects that are less than
wholly owned.
Table of Contents
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 2010 was
708,000 barrels per day.
In California, the company has significant production in the
San Joaquin Valley. In 2010, average net oil-equivalent
production was 199,000 barrels per day, composed of
178,000 barrels of crude oil, 96 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).
regions. During the moratorium, Chevron participated in a number
of industry efforts to identify opportunities to improve
industry standards in prevention, intervention and spill
response. In July 2010, Chevron and several other major energy
companies announced plans to build and deploy a rapid response
system that will be available to capture and contain oil in the
unlikely event of a potential future well blowout in the
deepwater Gulf of Mexico. In October 2010, the Secretary of the
Interior lifted the moratorium on deepwater drilling activity,
provided that operators certify compliance with new rules and
requirements. The drilling moratorium and the ensuing slowdown
in issuing drilling permits have resulted in delays in shallow
water drilling activity, delayed drilling of exploratory
deepwater wells and impacted development drilling on both
operated and nonoperated projects in the Gulf of Mexico. In
addition, the company’s net oil-equivalent production in
the Gulf of Mexico was reduced by about 10,000 barrels per
day for the full year.
Chevron was engaged in various exploration and development
activities in the deepwater Gulf of Mexico during 2010. First
oil at the Perdido Regional Development was achieved in first
quarter 2010. The development includes a 37.5 percent
nonoperated working interest in a producing host facility in
Alaminos Canyon designed to service multiple nonoperated fields,
including Chevron’s 33.3 percent-owned Great White,
60 percent-owned Silvertip and 57.5 percent-owned
Tobago. The development has an expected production life of
approximately 25 years.
The final investment decision was made for the Tahiti 2
waterflood project in third quarter 2010. Tahiti 2 is the second
development phase for the 58 percent-owned and operated
Tahiti Field and is designed to increase recovery and maintain
Table of Contents
production near the facility capacity of 125,000 barrels of
oil per day. The project includes three water injection wells,
two additional production wells and the facilities required to
deliver water to the injection wells. Drilling began on the
first water injection well in September 2010. The field has an
estimated production life of 30 years. As of the end of
2010, proved reserves had not been recognized for this second
development phase of the Tahiti Field.
During 2010, work continued at the 60 percent-owned and
operated Big Foot discovery. The project completed front-end
engineering and design (FEED) in June 2010 and a final
investment decision was made in December 2010. Total maximum
production is expected to reach 79,000 barrels of
oil-equivalent per day. First production is expected in 2014,
and at the end of 2010 proved reserves had not been recognized.
The field has an estimated production life of 20 years.
The topsides modifications to the host facility of the
Caesar/Tonga Project were completed in 2010. The company has a
20.3 percent nonoperated working interest in the Caesar and
Tonga partnerships unitized area. Development plans include a
total of four wells and a subsea tieback to a nearby third-party
production facility. Work on the subsea system, commissioning of
the topsides and the initial well completion program carried
over into 2011. A recent mechanical issue involving the
production riser system has delayed first production. Proved
reserves have been recognized for the project.
The Jack and St. Malo fields are located within 25 miles of
each other and are being jointly developed. Chevron has a
50 percent working interest in Jack and a 51 percent
working interest in St. Malo, following the acquisition of an
additional 9.8 percent equity interest in St. Malo in March
2010. Both fields are company operated. The FEED activities
initiated in 2009 continued into 2010, and a final investment
decision was achieved in October 2010. The facility is planned
to have an initial design capacity of 177,000 barrels of
oil-equivalent per day. Total project costs for the initial
phase of development are estimated at $7.5 billion and
start-up is
expected in 2014. The project has an estimated production life
of 30 years. At the end of 2010, proved reserves had not
been recognized.
Assessment of development concepts continued in 2010 for the
appraised resource potential on the Mad Dog II Development
Project, in which the company has a 15.6 percent
nonoperated working interest. These areas are outside the
drilling radius of the existing floating production facility. A
decision on the development concept, followed by the project
moving into the FEED stage, is expected to occur in the
second-half 2011. At the end of 2010, proved reserves had not
been recognized.
Studies to screen and evaluate future development alternatives
in the Tubular Bells unitized area, in which the company has a
30 percent nonoperated working interest, continued into
2010, and a subsea tieback to a planned third-party host
facility was selected as the development concept. FEED commenced
in fourth quarter 2010 with a final investment decision expected
in second quarter 2011. At the end of 2010, proved reserves had
not been recognized.
Deepwater exploration activities in 2010 included participation
in five exploratory wells — two wildcat, two appraisal
and one delineation. Drilling operations on two exploratory
wells were interrupted and stopped in second quarter 2010 as a
result of the deepwater drilling moratorium in the Gulf of
Mexico, including drilling of the first appraisal well at the
55 percent-owned and operated Buckskin discovery. The first
appraisal well at Knotty Head was completed in March 2010 and
interpretation of well results continued into 2011. Chevron has
a 25 percent nonoperated working interest in the Knotty
Head discovery. At the end of 2010, the company had not
recognized proved reserves for any of these exploration projects.
During 2010, the company added 15 new leases to its deepwater
portfolio as a result of bid awards stemming from a Gulf of
Mexico lease sale early in the year.
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 to enable the import of
natural gas for the North America market. 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 pipeline 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.
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 2010, the company’s U.S. production outside
California and the Gulf of Mexico averaged 249,000 net
oil-equivalent barrels per day, composed of 91,000 barrels
of crude oil, 773 million cubic feet of natural gas and
29,000 barrels of natural gas liquids.
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The company continues to pursue its interest in tight carbonate
oil resources in West Texas in the Wolfcamp and associated
formations where advances in drilling and completion
technologies have opened up widespread targets such as the
100 percent-owned and operated Lupin Project, where first
oil was realized in mid-2010. Additional production growth is
expected from both operated and nonoperated interests in these
formations in future years through continued use of these
advances in drilling and completion technologies. The company
also continued the appraisal of the Haynesville shale gas play
in East Texas.
In the Piceance Basin in northwestern Colorado, the company
continued development of its 100 percent-owned and operated
natural gas field. Development drilling and completion
activities continued in 2010, with 115 completed wells available
to supply natural gas to the central processing facility. The
2010 work plan focused on optimization of the existing wells and
facilities, completion of previously drilled wells, and
designing a pilot to test liquefied petroleum gas (LPG) as an
alternative fracture fluid beginning in fourth quarter 2011.
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 2010.
In February 2011, Chevron acquired Atlas Energy, Inc. The
acquisition provides an attractive natural gas resource position
in the Appalachian basin, primarily located in southwestern
Pennsylvania, and consists of approximately 850,000 total acres
of Marcellus Shale and Utica Shale. The acquisition provides a
49 percent interest in Laurel Mountain Midstream, LLC, an
affiliate that owns more than 1,000 miles of natural gas
gathering lines servicing the Marcellus. The acquisition also
provides assets in Michigan, which include Antrim Shale
producing assets and approximately 380,000 total acres in the
Antrim and Collingwood/Utica Shale.
“Other Americas” is composed of Canada, Greenland,
Argentina, Brazil, Colombia, Trinidad and Tobago, and Venezuela.
Net oil-equivalent production from these countries averaged
247,000 barrels per day during 2010, including the
company’s share of synthetic oil production.
production from the HSE unitized area is expected in late 2011.
At the end of 2010, proved reserves had not been recognized for
the unitized blocks.
FEED commenced in third quarter 2010 for the development of the
heavy-oil Hebron Field. The project has an expected economic
life of 30 years. At the end of 2010, proved reserves had
not been recognized for this project.
At AOSP, the company’s production of synthetic oil averaged
24,000 barrels per day during 2010, including first
production from the Jackpine Mine in third quarter 2010 as a
result of AOSP Expansion 1 Project activities. The project is
expected to increase total daily maximum design capacity by
100,000 barrels, to more than 255,000 barrels per day
in early 2011. Oil sands are mined from both the Muskeg River
and Jackpine mines and bitumen is extracted from the oil sands
and upgraded into synthetic oil. Expansion of the Scotford
Upgrader, also part of the AOSP Expansion 1 Project, is expected
to be completed in first-half 2011.
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The company acquired a new exploration lease in the Beaufort Sea
in 2010 and also holds other exploration licenses and leases in
the Orphan Basin offshore Atlantic Canada, the Mackenzie Delta
region of the Northwest Territories and the Beaufort Sea region
of Canada’s Arctic, including a 34 percent nonoperated
working interest in the offshore Amauligak discovery. In
addition, through 2010 the company acquired approximately
200,000 acres in Alberta’s Duvernay formation to
explore for shale gas and plans to commence an appraisal
drilling program in the second-half 2011. At the end of 2010,
proved reserves had not been recognized for any of these
exploration areas.
Greenland: Evaluation of the
2-D seismic
survey acquired over License 2007/26 in Block 4 offshore
West Greenland commenced in 2010 and is planned to continue into
2011. Chevron has a 29.2 percent nonoperated working
interest in this exploration license.
begin in the second-half 2011. The facility is expected to
produce up to 140,000 barrels of crude oil per day. First
production is expected in 2013. Evaluation of the field
development concept for Maromba continued into 2011. At the end
of 2010, proved reserves had not been recognized for these
projects.
In the Santos Basin, evaluation of investment options continued
into 2011 for the 20 percent-owned and partner-operated
Atlanta and Oliva fields. At the end of 2010, proved reserves
had not been recognized for these deepwater 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. During 2010, the company
conducted a seismic survey of the offshore,
near-shore
and onshore development areas. Daily net production averaged
249 million cubic feet of natural gas in 2010.
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 2010 averaged 223 million cubic feet of
natural gas per day. In 2010, a Loran/Manatee field-specific
treaty was signed by the governments of Trinidad and Tobago and
Venezuela related to the company’s 2005 successful
exploratory well in the Manatee Area of Block 6(d). At the
end of 2010, proved reserves had not been recognized for this
field.
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Venezuela: Chevron holds interests in two producing
affiliates located in western Venezuela and one producing
affiliate in the Orinoco Belt. Chevron has a 30 percent
interest in the Petropiar affiliate that operates the Hamaca
heavy-oil
production and upgrading project located in 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 2010 from these operations,
including synthetic oil from Hamaca, was 58,000 barrels per
day, composed of 54,000 barrels of crude oil, synthetic oil
and natural gas liquids and 25 million cubic feet of
natural gas.
In February 2010, a Chevron-led consortium was selected to
participate in a heavy-oil project in three blocks within the
Carabobo Area of eastern Venezuela’s Orinoco Belt. A joint
operating company, Petroindependencia, was formed in
May 2010, and work toward commercialization of the Carabobo
3 Project was initiated. The consortium holds a combined
40 percent interest in the project, with Petróleos de
Venezuela, S.A. (PDVSA), Venezuela’s national crude oil and
natural gas company, holding the remaining interest.
Chevron’s interest in the project is 34 percent.
The company operates in two exploratory blocks in the Plataforma
Deltana area offshore eastern Venezuela, 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. PDVSA has the option
to increase its ownership in each of the three company-operated
blocks up to 35 percent upon declaration of commerciality.
In Block 2, which includes the Loran Field, a Declaration
of Commerciality was accepted by the Venezuelan government in
March 2010. The Loran Field in Block 2 is projected to
provide the initial natural gas supply for a planned Delta
Caribe liquefied natural gas plant, Venezuela’s first LNG
project. Chevron has a 10 percent nonoperated working
interest in the LNG facility. At the end of 2010, proved
reserves had not been recognized in these exploratory blocks.
In Africa, the company is engaged in exploration and production
activities in Angola, Chad, Democratic Republic of the Congo,
Liberia, Nigeria and Republic of the Congo. Net oil-equivalent
production in Africa averaged 469,000 barrels per day
during 2010.
In the Greater Vanza/Longui Area of Block 0, development
concept selection studies continued in 2010 with the start of
FEED planned for second quarter 2011. FEED activities continued
on the south extension of the N’Dola field development
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with a final investment decision expected in fourth quarter
2011. At year-end 2010, no proved reserves had been recognized
for these projects.
In Block 0, the Area A gas management projects are designed
to eliminate routine flaring of natural gas by injecting excess
natural gas into various reservoirs. Three of the four projects
are in service and have reduced flaring by approximately
65 million cubic feet per day, as of year-end 2010. The
Malongo Flare and Relief Modification Project is scheduled for
start-up in
fourth quarter 2011. In Area B, work continued during the year
on the Nemba Enhanced Secondary Recovery and Flare Reduction
Project. The first stage of the project was planned to be
completed with the start of gas injection in second quarter 2011
on the existing South Nemba platform. The next stage, which
includes completion of a new platform and additional compression
facilities, is scheduled to begin gas injection in 2014.
Also in Block 0, a two-well exploration and appraisal
program was completed in 2010. The first well, completed in
February 2010, was successful and development opportunities are
being evaluated. The second well, completed in June 2010,
was not successful. Two additional exploratory wells are planned
for 2011.
In the 31 percent-owned Block 14, net production in
2010 averaged 34,000 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 drilling continued at the Tombua and Landana fields
during 2010. Drilling is planned to continue in 2011 with
maximum total daily production of 75,000 barrels of crude
oil anticipated in second quarter 2011.
In the Lucapa Field, development alternatives continued to be
evaluated during 2010, and a successful exploration
well was completed in the fourth quarter. The project is expected to enter FEED in third quarter 2011. A new development area in the Malange Field was awarded in 2010, following a successful 2009 appraisal well. As of the end of 2010, development of the Negage Field remained suspended until cooperative arrangements between Angola and Democratic Republic of the Congo could be finalized. At the end of 2010, proved reserves had not been recognized for these projects.
In the 20 percent-owned Block 2 and the
16.3 percent-owned FST areas, combined production during
2010 averaged 2,000 barrels of net liquids per day.
In addition to the exploration and production activities in
Angola, Chevron has a 36.4 percent ownership interest in
the Angola LNG affiliate that began construction in 2008 of an
onshore natural gas liquefaction plant in Soyo, Angola. The
plant is designed to process more than 1 billion cubic feet
of natural gas per day with expected average total daily sales
of 670 million cubic feet of regasified LNG and up to
63,000 barrels of natural gas liquids. Construction
continued during 2010 with plant
start-up
scheduled for 2012. The estimated total cost of the LNG plant is
$9.0 billion, with an estimated life in excess of
20 years. The company also holds a 38.1 percent
interest in a pipeline project that is expected to transport up
to 250 million cubic feet of natural gas per day from
Block 0 and Block 14 to the Angola LNG plant. This
project is expected to enter construction in the second-half
2011 and be completed by 2013. Proved reserves have been
recognized for the producing operations associated with these
projects.
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. The Lianzi development project
continued FEED through 2010. A final investment decision is
expected in fourth quarter 2011. No proved reserves have been
recognized for the project.
Republic of the Congo: Chevron has a
31.5 percent nonoperated working interest in the Nkossa,
Nsoko and
Moho-Bilondo
permit areas and a 29.3 percent nonoperated working
interest in the Kitina permit area, all of which are offshore.
Maximum total production of 93,000 barrels of crude oil per
day was reached in fourth quarter 2010 at Moho-Bilondo.
Chevron’s development and production rights for
Moho-Bilondo expire in 2030. The development and production
rights for Nsoko, Kitina and Nkossa expire in 2018, 2019 and
2027, respectively. Net production from the Republic of the
Congo fields averaged 25,000 barrels of oil-equivalent per
day in 2010.
During 2010, two successful exploration wells were drilled in
the Moho-Bilondo permit area. Development alternatives are under
evaluation.
Democratic Republic of the Congo: Chevron has a
17.7 percent nonoperated working interest in an offshore
concession. Daily net production in 2010 averaged
2,000 barrels of oil-equivalent.
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deepwater offshore blocks. In 2010, the company’s net
oil-equivalent production in Nigeria averaged
253,000 barrels per day, composed of 239,000 barrels
of liquids and 86 million cubic feet of natural gas.
During July 2010, an equity redetermination at the Agbami Field,
located in deepwater Oil Mining Lease (OML) 127 and OML
128, reduced the company’s ownership by about
1 percent, to 67.3 percent. In May 2010, drilling
started on a 10-well Phase 2 development program that is
designed to offset field decline. The program is expected to
continue through 2014 with the first wells expected to be
completed and placed on production in second-half 2011. 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 third-party-owned Bonga SW Field in offshore OML
118 share a common geologic structure and are planned to be
jointly developed under a unitization agreement. The agreement
will be finalized in advance of a final investment decision.
Subsurface and surface facility studies are expected to be
completed in second quarter 2011. A decision on project scope is
expected by third quarter 2011, prior to entering FEED. At the
end of 2010, no proved reserves were recognized for this project.
Chevron operates and holds a 95 percent interest in the
deepwater Nsiko discovery in OML 140. Development activities
continued in 2010, with FEED expected to start after commercial
terms are resolved and further exploration drilling is
completed. At the end of 2010, the company had not recognized
proved reserves for this project.
The company 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 (FPSO) vessel. During 2010, development drilling
and construction of the FPSO vessel continued. The FPSO vessel
is expected to depart the fabrication facility in second quarter
2011. Production
start-up is
scheduled for 2012, with maximum total production of
180,000 barrels of crude oil per day expected 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.
Additional exploration drilling is planned for third quarter
2011 in Oil Prospecting License (OPL) 214 and OPL 223. The
company has 20 percent and 27 percent nonoperated
working interests in the licenses, respectively. At the end of
2010, proved reserves had not been recognized for these
exploration activities.
In the Niger Delta, construction on the Phase 3A expansion of
the Escravos Gas Plant (EGP) was completed in 2009, and first
gas was delivered to the new facilities in June 2010. As a
result of the expansion, the plant’s total daily processing
capacity increased from 285 million to 680 million
cubic feet of natural gas, and daily LPG and condensate export
capacity increased from 15,000 to 58,000 barrels. By
year-end 2010, plant input had ramped up to 230 million
cubic feet of natural gas per day, resulting in daily natural
gas sales into the domestic market of 180 million cubic
feet and daily export sales of 8,000 barrels of LPG and
condensate. The anticipated life of EGP Phase 3A is
25 years. Phase 3B of the EGP project is designed to gather
120 million cubic feet of natural gas per day from eight
offshore fields and to compress and transport the natural gas to
onshore facilities. The engineering, procurement, construction
and installation contract for the gas gathering and compression
platform is expected to be signed in second quarter 2011. The
Phase 3B project is expected to be completed in 2013. Proved
reserves associated with this project have been recognized.
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The 40 percent-owned and operated Gas Supply Expansion
project includes facilities to develop the Sonam natural gas
field in the Escravos area and to add a third gas processing
train at EGP. The project is designed to deliver
215 million cubic feet of natural gas per day to the
domestic market and produce 43,000 barrels of liquids per
day. A final investment decision is expected in third quarter
2011. At the end of 2010, proved reserves associated with the
project had not been recognized.
The company has a 40 percent-owned and operated interest in
the Onshore Asset Gas Management project that is designed to
restore approximately 125 million cubic feet per day of
natural gas production from certain onshore fields that have
been shut in since 2003 due to civil unrest. Two
on-site
construction contracts were awarded in third quarter 2010 and
start-up is
scheduled for 2012.
Chevron has a 75 percent-owned and operated interest in a
gas-to-liquids
facility at Escravos that is being developed with the Nigerian
National Petroleum Corporation. The
33,000 barrel-per-day
facility is designed to process 325 million cubic feet per
day of natural gas supplied from the Phase 3A expansion of EGP.
At the end of 2010, work on the project was approximately
70 percent complete and
start-up is
planned for 2013. The estimated cost of the plant is
$8.4 billion.
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. As of early 2011, timing of the final investment
decision remains uncertain. At the end of 2010, proved reserves
associated with this project had not been recognized.
Chevron is the largest shareholder, with a 37 percent
interest, in the West African Gas Pipeline Company Limited
affiliate, which constructed, owns and operates the
421-mile
West African Gas Pipeline. The pipeline supplies Nigerian
natural gas to customers in Benin, Ghana and Togo for industrial
applications and power generation. Compression facilities
designed to increase capacity to 170 million cubic feet per
day were commissioned in February 2011.
Liberia: In 2010, Chevron acquired a 70 percent
interest and operatorship in three deepwater blocks off the
coast of Liberia. Three-D seismic data was purchased in
September, and an exploration well is planned for fourth quarter
2011.
In Asia, the company is engaged in upstream activities in
Azerbaijan, Bangladesh, Cambodia, China, Indonesia, Kazakhstan,
Myanmar, the Partitioned Zone located between Saudi Arabia and
Kuwait, the Philippines, Russia, Thailand, Turkey, and Vietnam.
During 2010, net oil-equivalent production averaged
1,069,000 barrels per day.
per day and transports the majority of ACG production. Another
production export route for crude oil is the Western Route
Export Pipeline, wholly owned by AIOC, with capacity to
transport 100,000 barrels per day from Baku, Azerbaijan, to
the marine terminal at Supsa, Georgia.
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Kazakhstan: Chevron participates in two major
upstream developments in western Kazakhstan. The company holds a
50 percent interest in the Tengizchevroil (TCO) affiliate,
which is operating and developing the Tengiz and Korolev crude
oil fields under a concession that expires in 2033.
Chevron’s net oil-equivalent production in 2010 from these
fields averaged 308,000 barrels per day, composed of
252,000 barrels of crude oil and natural gas liquids and
338 million cubic feet of natural gas. During 2010, 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 by
tanker to Baku for transport by the BTC pipeline to Ceyhan or by
rail to Black Sea ports.
Also during 2010, TCO continued to evaluate alternatives for
another expansion project to increase total daily crude oil
production between 250,000 and 300,000 barrels. The
expansion project will rely on technology developed for the Sour
Gas Injection/Second Generation Plant project completed in 2008.
Approval of FEED is anticipated in the second-half 2011. As of
year-end 2010, no proved reserves have been recognized for this
expansion project.
Chevron holds a 20 percent nonoperated working interest in
the Karachaganak project, which is being developed in phases.
During 2010, Karachaganak net oil-equivalent production averaged
64,000 barrels per day, composed of 39,000 barrels of
liquids and 149 million cubic feet of natural gas. In 2010,
access to the CPC and Atyrau-Samara (Russia) pipelines enabled
approximately 175,000 barrels per day (31,000 net
barrels) of Karachaganak liquids to be sold at world-market
prices. The remaining liquids were sold into Russian markets.
During 2010, work continued on a fourth train that is designed
to increase total liquids stabilization capacity by
56,000 barrels per day. The fourth train is expected to
start up in second quarter 2011.
During 2010, Chevron and its partners continued to evaluate
alternatives for a Phase III development of Karachaganak.
Timing for the Phase III project remains uncertain and
depends on finalizing a project design. Proved reserves have not
been recognized for a Phase III project. Karachaganak
operations are conducted under a PSC that expires in 2038.
Kazakhstan/Russia: Chevron has a 15 percent
interest in the CPC affiliate. During 2010, CPC transported an
average of approximately 743,000 barrels of crude oil per
day, including 607,000 barrels per day from Kazakhstan and
136,000 barrels per day from Russia. In December 2010,
partners made a final investment decision to increase the
pipeline capacity by 670,000 barrels per day. The total
estimated cost of the project is $5.4 billion. The project
is expected to be implemented in three phases, with capacity
increasing progressively until reaching full capacity in 2016.
Russia: In June 2010, Chevron signed a Heads of
Agreement with Rosneft covering the exploration, development and
production of hydrocarbons from the Shatsky Ridge Block in the
Black Sea. Technical and commercial evaluation of the
opportunity is ongoing in 2011. No proved reserves have been
recognized for these activities.
Turkey: In September 2010, Chevron signed a Joint
Operating Agreement for a 50 percent interest in a
5.6 million acre exploration block located in the Black
Sea. The initial exploration well was completed in November 2010
and was unsuccessful. Future plans are under evaluation.
Chevron relinquished its 25 percent nonoperated working
interest in the Silopi licenses in southeast Turkey, following
the evaluation of an unsuccessful exploration well, which was
completed in the Lale prospect during first quarter 2010.
Bangladesh: Chevron holds interests in three
operated PSCs covering Blocks 7, 12, 13 and 14. The company
has a 43 percent interest in Block 7 and a
98 percent interest in Blocks 12, 13 and 14. Net
oil-equivalent production from these operations in 2010 averaged
69,000 barrels per day, composed of 404 million cubic
feet of natural gas and 2,000 barrels of liquids. In 2010,
preliminary construction and development activities were
completed at the Muchai compression project, which 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. Also in 2010,
the company completed seismic data evaluation and prepared to
drill an exploration well in Block 7 that is expected to be
completed by mid-2011.
Cambodia: Chevron owns a 30 percent interest
and operates the
1.2 million-acre Block
A, located offshore in the Gulf of Thailand. The company
completed three successful exploration wells during 2010. A
30-year
production permit under the PSC is expected to be approved by
the government in the first-half 2011. A final investment
decision for construction of a wellhead platform and a floating
storage and offloading vessel is expected in 2011. At year-end
2010, proved reserves had not been recognized for the project.
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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. The company’s
average net natural gas production in 2010 was 81 million
cubic feet per day. In July 2010, a compression project entered
service to support additional natural gas demand.
Basin. Concessions for the producing areas within this basin
expire between 2036 and 2040.
During 2010, construction at the 69.9 percent-owned and
operated Platong Gas II project continued. The project is
designed to add 440 million cubic feet per day of
production capacity and
start-up is
expected in fourth quarter 2011. Proved reserves have been
recognized for this project.
During 2010, the company drilled seven exploration wells in the
Pattani Basin. Four of the wells were successful and were under
evaluation to validate the development strategy. Three
unsuccessful explorations wells were drilled in Block G4/50. In
fourth quarter, the company withdrew from this block. At the end
of 2010, proved reserves had not been recognized for these
activities. For 2011, eleven operated exploratory wells are
planned. The company also holds exploration interests in a
number of blocks that are inactive, pending resolution of border
issues between Thailand and Cambodia.
Vietnam: Chevron is the operator of two PSCs in the
Malay Basin off the southwest coast of Vietnam. The company has
a 42.4 percent interest in a PSC that includes Blocks B and
48/95, and a 43.4 percent interest in a PSC for
Block 52/97. The company also has a 20 percent
ownership interest in an operated PSC in Block 122 offshore
eastern Vietnam.
In the blocks off the southwest coast, the Block B Gas
Development is designed to produce natural gas from the Malay
Basin for delivery to state-owned Petrovietnam. The project
includes installation of wellhead and hub platforms, a floating
storage and offloading vessel, field pipelines and a central
processing platform. The project entered FEED in 2010, and a
final investment decision is expected in fourth quarter 2011.
Maximum total production is planned to be about 500 million
cubic feet of natural gas per day. At the end of 2010, proved
reserves had not been recognized for this project.
In conjunction with the Block B Gas Development, a
partner-operated pipeline will be required to support the
offshore development. Chevron has a 28.7 percent interest
in the pipeline, which is planned to transport natural gas to
customers in southern Vietnam. The project entered FEED in 2009,
and the engineering and design work is being performed by the
pipeline operator.
During the year, seismic processing and prospect mapping were
completed for Block 122. Proved reserves had not been
recognized as of the end of 2010. Future activity in
Block 122 may be affected by an ongoing territorial
dispute between Vietnam and China.
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three separate PSCs for the exploration period. The three
deepwater blocks cover approximately 5.2 million acres. One
exploration well is planned for 2011 following the completion of
an environmental impact study and a
3-D seismic
acquisition program.
Also in the Pearl River Mouth Basin, the company has nonoperated
working interests of 32.7 percent in Blocks 16/08 and
16/19. Following storm damage in 2009, production was partially
restored from Block 16/08 and Block 16/19 in March 2010 and is
expected to be fully restored in 2011. Also in Block 16/19,
first production from the joint development of the HZ25-3 and
HZ25-1 crude oil fields was achieved in March 2010.
In the Bohai Bay, the company holds nonoperated interests of
24.5 percent in the QHD-32-6 Field and 16.2 percent in
Block 11/19, both of which are in production. In 2010,
production was partially restored from Block 11/19 after a
shut-in caused by a storm in 2009. Production is expected to be
fully restored in 2013.
Basin in fourth quarter 2010 following an unsuccessful
obligation well in 2009. Chevron also relinquished its interest
in the 100 percent-owned and operated East Ambalat PSC in
December 2010. The relinquishments of NE Madura III and
East Ambalat are both pending approval by the government of
Indonesia.
The company’s net oil-equivalent production in 2010 from
all of its interests in Indonesia averaged 226,000 barrels
per day. The daily oil-equivalent rate comprised 187,000 barrels of liquids and 236 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.
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The expansion in Area 12 was completed in 2010 with the
additional drilling of 72 production, 24 steam injection, and 10
observation wells. During the year,
ramp-up of
steam injection continued with the project reaching a maximum
total daily production of 45,000 barrels in September 2010.
A final investment decision regarding North Duri Area 13 was
reached May 2010, and is awaiting final development plan and bid
award approvals from the government of Indonesia. The Rokan PSC
expires in 2021.
In 2010, Chevron advanced its development plans for the
Gendalo-Gehem deepwater natural gas project located in the Kutei
Basin, awarding major FEED contracts for the floating production
units, subsea and pipeline components, and onshore receiving
facility. Maximum daily total production from the project is
expected to be 1.1 billion cubic feet of natural gas and
31,000 barrels of condensate. Completion of FEED is
dependent upon government approvals and achieving project
milestones. The Bangka deepwater natural gas project progressed
during the year, and entered FEED in fourth quarter 2010. During
2010, the company reached an agreement to farm-out a portion of
its working interest in the PSCs of the two projects. Government
approval of the farm-out is expected in the second-half 2011. In
addition, in 2011 the company expects to farm-in an Indonesian
company to the PSCs for the two projects. Following government
approval of the agreements, the company’s production
interest in the Gendalo-Gehem and Bangka projects will be
55.1 percent and 54 percent, respectively. Proved
reserves have not been recognized for these projects.
Also in the Kutei Basin, the company reached a final investment
decision in August 2010 for an oil development project in the
West Seno Field and recognized proved reserves related to the
project.
A drilling campaign continued through 2010 in South Natuna Sea
Block B to provide additional supply for long-term natural gas
sales contracts, with additional development drilling planned
for 2011. The North Belut development project achieved maximum
total daily production of 240 million cubic feet of natural
gas and 33,000 barrels of liquids in February 2010.
Development of the South Belut project continued during the
year. The Bawal project reached final investment decision in
October 2010 and is expected to begin production in 2012.
Exploration activities continued in the Central Sumatra Basin
during 2010. Two wells drilled in the Rokan Block were
successful and placed on production. Additional appraisal
drilling near the Duri Field identified further expansion
opportunities that will be further assessed with
3-D seismic
in 2011. Chevron’s operated working interests in two
exploration blocks in western Papua, West Papua I and West Papua
III, were reduced to 51 percent in second quarter 2010.
Geological studies of the two blocks continued in 2010, and
2-D seismic
acquisition is expected to start in the first-half 2011.
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 the company’s operation
in North Duri, Sumatra. In December 2010, the company was
awarded a license and operatorship to explore and develop a
geothermal prospect in the Suoh-Sekincau prospect area at
Lampung in southern Sumatra.
carbonate reservoir and, if successful, could significantly
increase heavy oil recovery. No proved reserves have been
recognized for this project.
Also in 2010, assessment of alternatives continued on the
Central Gas Utilization Project to increase natural gas
utilization and eliminate routine flaring. A final investment
decision is expected in 2012. No proved reserves have been
recognized for this project.
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Philippines: The company holds a 45 percent
nonoperated working interest in the Malampaya natural gas field
located 50 miles offshore Palawan Island. Net
oil-equivalent production in 2010 averaged 25,000 barrels
per day, composed of 124 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 2011 to operate the
steam fields, which supply geothermal resources to 637 megawatt
power generation facilities.
In November 2010, Chevron signed a farm-in agreement and a Joint
Operating Agreement with two Philippine corporations to explore,
develop and operate the Kalinga geothermal prospect in northern
Luzon, Philippines. The company has a 90 percent-owned and
operated interest in the project.
In Australia, the company’s exploration and production
efforts are concentrated off the northwest coast. During 2010,
the average net oil-equivalent production from Australia was
111,000 barrels per day.
production in 2013. Proved reserves have been recognized for the
project.
Work also progressed on the NWS Oil Redevelopment Project, which
is designed to replace the existing FPSO vessel and a portion of
existing subsea infrastructure that services production from the
Cossack, Hermes, Lambert and Wanaea offshore fields. Work
commenced in January 2011 on the subsea infrastructure
refurbishment, and construction of the new FPSO vessel is
expected to be completed in second quarter 2011. The project is
expected to start up in third quarter 2011 and extend production
past 2020.
The NWS Venture continues to progress additional gas supply
opportunities through development of several small fields on the
western flank of the Goodwyn reservoirs. The project is expected
to enter FEED in the first-half 2011. 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
2010. 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 holds a
47.3 percent ownership interest across most of the area and
is the operator of the Gorgon Project, which combines the
development of the offshore Gorgon and nearby Io/Jansz natural
gas fields as one large-scale project. Total estimated project
costs for the first phase of development are $37 billion.
The project’s scope also includes a three-train,
15 million-metric-ton-per-year LNG facility, a carbon
sequestration project and a domestic natural gas plant.
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Chevron has signed five binding LNG Sales and Purchase
Agreements (SPAs) with Asian customers for delivery of about
4.7 million metric tons of LNG per year. Negotiations
continue to finalize the two remaining nonbinding Heads of
Agreement (HOAs) to binding SPAs, which would bring LNG delivery
commitments to a combined total of about 90 percent of
Chevron’s share of LNG from the project. Construction on
Barrow Island and other activities for the project progressed
during 2010 with the awarding of approximately $25 billion
of contracts for materials and services, clearing of the plant
site, completion of the first stage of the construction village,
commencement of module fabrication, and progression of studies
on the possible expansion of the project. Proved reserves have
been recognized for the Greater Gorgon Area fields included in
the project, and first production of natural gas from the fields
is expected in 2014. The project’s estimated economic life
exceeds 40 years from the time of
start-up.
FEED activities for the company’s majority-owned and
operated Wheatstone Project continued in 2010. Chevron holds an
80 percent interest in the foundation natural gas
processing facilities, which include a two-train
8.9 million-metric-ton-per-year LNG facility and a separate
domestic gas plant located at Ashburton North, along the
northwest coast of Australia. The company plans to supply
natural gas to the facilities from two Chevron-operated licenses
comprising the majority of the Wheatstone Field and the nearby
Iago Field.
Through the end of 2010, Chevron has signed nonbinding HOAs with
three Asian customers for the delivery of about 80 percent
of Chevron’s net LNG offtake from the Wheatstone Project.
Under these HOAs, the customers also agreed to acquire a
combined 21.8 percent nonoperated working interest in the
Wheatstone field licenses and a 17.5 percent interest in
the foundation natural gas processing facilities at the time of
the final investment decision. Negotiations continue to move the
three nonbinding HOAs to binding SPAs with these customers.
Agreements were also signed in 2009 and amended in 2010 with two
companies to participate in the Wheatstone Project as combined
20 percent LNG facility owners and suppliers of natural gas
for the project’s first two LNG trains. During 2010, a
Native Title Heads of Agreement was reached with the local
indigenous people for the land required at Ashburton North and
submissions were made for various additional environmental
approvals. The final investment decision for the project is
expected in
second-half
2011. At the end of 2010, the company had not recognized proved
reserves for this project.
In the Browse Basin, the Browse LNG development participants
commenced design evaluation for the Brecknock, Calliance and
Torosa fields in early 2010. At the end of 2010, proved reserves
had not been recognized.
During 2010, Chevron announced natural gas discoveries at the
50 percent-owned Brederode prospect in Block
WA-364-P,
the 50 percent-owned Yellowglen prospect in Block WA-268-P,
the 50 percent-owned Sappho prospect in Block WA-392-P, and
the 67 percent-owned Clio and Acme prospects in Block
WA-205-P. In February 2011, the company announced a natural gas
discovery in the 50 percent-owned Orthrus prospect in Block
WA-24-R. All prospects are Chevron operated. The Clio and Acme
prospects are expected to help support potential expansion
opportunities at the Wheatstone LNG facilities while the
Yellowglen, Sappho and Orthrus prospects are expected to help
underpin further expansion opportunities on the Gorgon
Project. Proved reserves had not been recognized for any of
these exploration discoveries.
In Europe, the company is engaged in exploration and production
activities in Denmark, the Netherlands, Norway, Poland, Romania
and the United Kingdom. Net oil-equivalent production in Europe
averaged 159,000 barrels per day during 2010.
Denmark: Chevron has a 15 percent working
interest in the partner-operated Danish Underground Consortium
(DUC), which produces crude oil and natural gas from 13 of 15
fields in the Danish North Sea. Net oil-equivalent production in
2010 from DUC averaged 51,000 barrels per day, composed of
32,000 barrels of crude oil and 116 million cubic feet
of natural gas. During 2010, four development wells were drilled
and completed in the Halfdan, Tyra and Valdemar fields. The
installation of new facilities for the Halfdan Phase IV
project was completed in 2010, with
hook-up and
tie-in planned for second quarter 2011.
Netherlands: Chevron operates and holds interests
ranging from 34.1 percent to 80 percent in 10 blocks
in the Dutch sector of the North Sea. In 2010, the
company’s net oil-equivalent production from the producing
blocks was 8,000 barrels per day, composed of
2,000 barrels of crude oil and 35 million cubic feet
of natural gas. Five blocks comprise the A/B Gas Project, where
development continued in 2010 and into 2011. In September 2010,
the company acquired a 60 percent interest in the P/1 and
P/2 blocks, which contain several natural gas discoveries.
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covers 1.5 million acres. A
2-D seismic
program is planned to begin in fourth quarter 2011 on the EV-2
Barlad concession.
United Kingdom: The company’s average net
oil-equivalent production in 2010 from 10 offshore fields was
97,000 barrels per day, composed of 64,000 barrels of
crude oil and natural gas liquids and 194 million cubic
feet of natural gas. Most of the production was from the
85 percent-owned and operated Captain Field, the
23.4 percent-owned and operated Alba Field, and the
32.4 percent-owned and jointly operated Britannia Field.
The 70 percent-owned and operated Alder discovery entered
FEED in 2010, following selection of the development concept.
The final investment decision is planned for late 2011.
Evaluation of development alternatives continued during 2010 for
the Clair Ridge Project, located west of the Shetland Islands,
in which the company has a 19.4 percent nonoperated working
interest. Evaluation resulted in the selection of a preferred
alternative consisting of a bridge-linked, twin-jacket
structure. The final investment decision is expected mid-2011.
In the 40 percent-owned and operated Rosebank area
northwest of the Shetland Islands, seismic, geophysical,
geotechnical and environmental surveys were conducted during
2010, and feasibility engineering activities are scheduled to
continue through 2011. At the end of 2010, proved reserves had
not been recognized for any of these development projects.
Also west of the Shetland Islands, a three-well exploration and
appraisal drilling program began in September 2010 and is
expected to be completed in fourth quarter 2011. This program
comprises exploration wells on the Lagavulin prospect in the
60 percent-owned and operated license block P1196 and on
the Aberlour prospect in the 40 percent-owned and operated
license block P1194, followed by appraisal drilling and well
testing of the Cambo discovery in the 32.5 percent
nonoperated license blocks P1028 and P1189. As of the end of
2010, proved reserves had not been recognized for any of these
prospects.
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 2010, U.S. and international sales of natural gas
were 5.9 billion and 4.5 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, Europe,
Kazakhstan, Indonesia,
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Latin America, the Philippines and Thailand.
U.S. and international sales of natural gas liquids were
161 thousand and 105 thousand barrels per day,
respectively, in 2010. Substantially all of the international
sales of natural gas liquids are from company operations in
Africa, Australia, Indonesia and the United Kingdom.
Refer to “Selected Operating Data,” on page
FS-11 in
Management’s Discussion and Analysis of Financial Condition
and Results of Operations, for further information on the
company’s sales volumes of natural gas and natural gas
liquids. Refer also to “Delivery Commitments” on
page 8 for information related to the company’s
delivery commitments for the sale of crude oil and natural gas.
Downstream
At the end of 2010, the company had a refining network capable
of processing more than 2 million barrels of crude oil per
day. Operable capacity at December 31, 2010, and daily
refinery inputs for 2008 through 2010 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)
Average crude oil distillation capacity utilization during 2010
was 92 percent, compared with 91 percent in 2009. At
the U.S. fuel refineries, crude oil distillation capacity
utilization averaged 95 percent in 2010, compared with
96 percent in 2009, and cracking and coking capacity
utilization averaged 90 percent and 85 percent in 2010
and 2009, respectively. Cracking and coking units are the
primary facilities used in fuel refineries to convert feedstocks
into gasoline and other light products. Chevron processes both
imported and domestic crude oil in its U.S. refining
operations. Imported crude oil accounted for about
84 percent and 85 percent of Chevron’s
U.S. refinery inputs in 2010 and 2009, respectively.
At the Pascagoula Refinery, the company commissioned a
continuous catalytic reformer that is expected to improve
equipment reliability and utilization and to allow the refinery
to optimize production of high-value products. Also in
Pascagoula, a final investment decision was reached in first
quarter 2011 to construct a facility to produce approximately
25,000 barrels per day of premium base oil for use in
manufacturing high-performance finished lubricants, such as
motor oils for consumer and commercial applications. Project
completion is expected by year-end 2013.
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At the refinery in El Segundo, construction began in late 2010
on a new processing unit designed to further improve the
facility’s overall reliability, enhance high-value product
yield and provide additional flexibility to process a broad
range of crude slates. Project completion is expected in 2012.
At the Richmond Refinery, the company continued to evaluate its
options with respect to permitting of the Renewal Project. The
project is designed to improve the refinery’s ability to
process higher sulfur crudes, without changing the
refinery’s capacity to process crude blends in the
intermediate-light gravity range. Improved ability to process
higher sulfur crudes is expected to provide increased
flexibility to process lower API-gravity crudes within the
refinery’s existing capacity range. Refer also to a
discussion of contingencies related to this project in
Note 24 to the Consolidated Financial Statements on
page FS-59.
Outside the United States, GS Caltex, the company’s
50 percent-owned affiliate, commissioned and reached full
capacity on a new 60,000-barrel-per-day heavy-oil hydrocracker
at the Yeosu Refinery in South Korea during 2010. Also at the
Yeosu Refinery, GS Caltex announced plans to construct a
53,000-barrel-per-day gas oil fluid catalytic cracking unit. The
unit is scheduled for
start-up in
2013. Both units are designed to increase high-value product
yield and lower feedstock costs. Construction began in 2010 on
modifications to the 64 percent-owned Star Petroleum
Refinery in Thailand to meet regional specifications for cleaner
motor gasoline and diesel fuels. Project completion is scheduled
for 2012. Also in 2010, the company solicited bids for the sale
of certain operations in the United Kingdom and Ireland,
including the Pembroke Refinery.
The company markets petroleum products under the principal
brands of “Chevron,” “Texaco” and
“Caltex” throughout many parts of the world. The table
below identifies the company’s and affiliates’ refined
products sales volumes, excluding intercompany sales, for the
three years ended December 31, 2010.
Refined
Products Sales Volumes
(Thousands of Barrels per Day)
In the United States, the company markets under the Chevron and
Texaco brands. At year-end 2010, the company supplied directly
or through retailers and marketers approximately 8,250 Chevron-
and Texaco-branded motor vehicle service stations, primarily in
the southern and western states. Approximately 500 of these
outlets are company-owned or -leased stations. In 2010, the
company discontinued sales of Chevron- and Texaco-branded motor
fuels in the District of Columbia, Delaware, Indiana, Kentucky,
North Carolina, New Jersey, Maryland, Ohio, Pennsylvania, South
Carolina, Virginia, West Virginia and parts of Tennessee, 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 represented
approximately 8 percent of the company’s total
U.S. retail fuels sales volumes in 2009. In addition, the
company has completed six of 13 planned U.S. terminal
divestitures.
Outside the United States, Chevron supplied directly or through
retailers and marketers approximately 11,300 branded service
stations, including affiliates. In British Columbia, Canada, the
company markets under the Chevron brand. The
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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.
The company progressed its ongoing effort to concentrate
downstream resources and capital on strategic assets. In
December 2010 and February 2011, the company completed the sale
of fuels-marketing businesses in Malawi, Mauritius,
Réunion, Tanzania and Zambia. The company expects to
complete the sale of its fuels-marketing businesses in
Mozambique and Zimbabwe later in 2011, following receipt of
required local regulatory and government approvals. In November
2010, the company signed an agreement for the sale of its
fuels-marketing and aviation fuels businesses in Antigua,
Barbados, Belize, Costa Rica, Dominica, French Guiana, Grenada,
Guadeloupe, Guyana, Martinique, Nicaragua, St. Kitts, St. Lucia,
St. Vincent, and Trinidad and Tobago and expects to complete all
transactions by third quarter 2011, following receipt of
required local regulatory and government approvals. In February
2011, the company announced an agreement to sell its fuels,
finished lubricants and aviation fuels businesses in Spain. In
2010, the company also solicited bids for its fuels-marketing
and aviation fuels businesses in the United Kingdom and Ireland.
In addition, the company converted more than
150 company-operated service stations into retailer-owned
sites in various countries outside the United States.
Chevron markets commercial aviation fuel at approximately 200
airports, worldwide. The company also markets an extensive line
of lubricant and coolant products under brand names including
Havoline, Delo, Ursa, Meropa and Taro.
Chemicals
Operations
Chevron owns a 50 percent interest in its Chevron Phillips
Chemical Company LLC (CPChem) affiliate. At the end of 2010,
CPChem owned or had joint-venture interests in 36 manufacturing
facilities and four research and technical centers around the
world.
During 2010, CPChem commenced operations at its
49 percent-owned Q-Chem II project 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 in Mesaieed, each utilizing
CPChem’s proprietary technology. Also included in the
project is a separate joint venture for 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, which will provide
ethylene feedstock to the high-density polyethylene and normal
alpha olefins plants.
CPChem’s 35 percent-owned Saudi Polymers Company
continued construction on a petrochemical project in Al Jubail,
Saudi Arabia. The joint-venture project includes olefins,
polyethylene, polypropylene, 1-hexene and polystyrene units.
Project
start-up is
expected in late 2011.
In the United States, CPChem announced in fourth quarter 2010
the development of a 200,000-ton-per-year 1-hexene plant at the
company’s Cedar Bayou complex in Baytown, Texas, with
start-up
expected in 2014. The plant is expected to be the largest
1-hexene unit in the world and will utilize CPChem’s
proprietary 1-hexene technology.
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 primarily in engine applications, such
as passenger car, heavy-duty diesel, marine, locomotive and
motorcycle engines, and additives for fuels that are blended to
improve engine performance and extend engine life. During 2010,
the company achieved full capacity at the detergent expansion
facility in Singapore. This additional capacity enhances the
company’s ability to produce detergent components for
applications in marine and automotive engines.
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Transportation
Pipelines: Chevron owns and operates an extensive
network of crude oil, refined product, chemical, natural gas
liquid and natural gas pipelines and other infrastructure assets
in the United States. The company also has direct and indirect
interests in other U.S. and international pipelines. The
company’s ownership interests in pipelines are summarized
in the following table.
Pipeline
Mileage at December 31, 2010
During 2010, the company completed a project to expand capacity
by approximately 2 billion cubic feet at the Keystone
natural gas storage facility near Midland, Texas, bringing total
capacity to nearly 7 billion cubic feet.
Work continued in 2010 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 2012. The company is leading the
construction of a 136 mile,
24-inch
pipeline from the Jack/St. Malo facility to Green Canyon 19 in
the U.S. Gulf of Mexico, where there is an interconnect to
pipelines delivering crude oil into Louisiana.
In 2010, the company sold its 23.4 percent ownership
interest in the Colonial Pipeline Company, which transports
products from supply centers on the U.S. Gulf Coast to
customers located along the Eastern seaboard.
Refer to pages 16, 17 and 18 in the Upstream section for
information on the Chad/Cameroon pipeline, the West Africa Gas
Pipeline, the Baku-Tbilisi-Ceyhan Pipeline, the Western Route
Export Pipeline and the Caspian Pipeline Consortium.
Tankers: All tankers in Chevron’s controlled
seagoing fleet were utilized during 2010. At any given time
during 2010, the company had 41 deep-sea vessels chartered on a
voyage basis, or for a period of less than one year.
Additionally, the table on the following page summarizes the
capacity of the company’s controlled fleet.
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Controlled
Tankers at December 31,
20101
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
replaced two
U.S.-flagged
product tankers in 2010. The company plans to retire one
additional
U.S.-flagged
product tanker in 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, Southeast 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
tankers transporting cargoes for the North West Shelf Venture in
Australia.
Chevron’s fleet of owned and chartered tankers is
completely double-hulled. The company is a member of many
oil-spill-response
cooperatives in areas in which it operates around the world.
Other
Businesses
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 an underground coal
mine, North River, in Alabama, and surface coal mines in
Kemmerer, Wyoming, and McKinley, New Mexico. 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.
As of early 2011, the sale of the North River Mine and other
coal-related assets in Alabama was under negotiation.
Additionally, in January 2011, the company announced the intent
to divest its remaining coal mining operations. Activities
related to full reclamation continued in 2010 at the
company’s McKinley, New Mexico, mine, which ceased coal
production at the end of 2009.
At year-end 2010, Chevron controlled approximately
189 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 8 million tons of coal per year through
the end of 2013 and believes it will satisfy these contracts
from existing coal reserves. Coal sales from wholly owned mines
in 2010 were 8 million tons, down about 2 million tons
from 2009.
In addition to the coal operations, Chevron owns and operates
the Questa molybdenum mine in New Mexico. At
year-end
2010, Chevron controlled approximately 53 million pounds of
proven molybdenum reserves at Questa. Production and underground
development at Questa continued at reduced levels in 2010 in
response to weak prices for molybdenum.
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Chevron’s Global Power Company manages interests in 13
power assets with a total operating capacity of more than 3,100
megawatts, primarily through joint ventures in the United States
and Asia. Twelve of these are efficient combined-cycle and
gas-fired cogeneration facilities that utilize waste heat
recovery to produce electricity and support industrial thermal
hosts. The thirteenth facility is a wind farm, located in
Casper, Wyoming, that is designed to optimize the use of a
decommissioned refinery site for delivery of clean, renewable
energy to the local utility.
The company has major geothermal operations in Indonesia and the
Philippines and is investigating several advanced solar
technologies for use in oil field operations as part of its
renewable-energy strategy. For additional information on the
company’s geothermal operations and renewable energy
projects, refer to pages 21 and 22 and “Research and
Technology” below.
Chevron
Energy Solutions (CES)
CES is a wholly owned subsidiary that develops and builds
sustainable energy projects to increase energy efficiency and
renewable power, reduce energy costs, and ensure reliable,
high-quality energy for government, education and business
facilities. Since 2000, CES has developed hundreds of projects
that help customers reduce their energy costs and environmental
impact. Projects announced in 2010 include the City of Brea
Energy Efficiency and Solar Project in California, the Marine
Corps Logistics Base Albany Landfill Gas Project in Georgia, and
the University of Utah Thermal Storage and New Central Plant
Project.
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 disciplines. 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 2010, CTV
continued to explore technologies such as next-generation
biofuels and advanced solar. In 2010, the company constructed
and commissioned a one megawatt concentrating photovoltaic (CPV)
solar facility on the tailing site of Chevron’s molybdenum
mine in Questa, New Mexico. This beneficial reuse project
is one of the largest CPV installations in the world. Also in
2010, the company constructed and commissioned a 0.74 megawatt
next generation solar photovoltaic installation on a former
refinery site in Bakersfield, California. Seven solar panel
technologies are being tested to establish the viability of
these solar technologies at other Chevron sites.
Chevron’s research and development expenses were
$526 million, $603 million and $702 million for
the years 2010, 2009 and 2008, 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.
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 2010, the company’s U.S. capitalized environmental
expenditures were $639 million, representing about
12 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 2011, the company estimates U.S. capital
expenditures for environmental control facilities will be
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approximately $800 million. The future annual capital costs
are uncertain and will be governed by several factors, including
future changes to regulatory requirements.
Environmental-related regulations, including those intended to
address concerns about greenhouse gas emissions and global
climate change, continue to evolve. For instance, in December
2009, the U.S. Environmental Protection Agency (EPA) issued
a final endangerment finding for greenhouse gases, which found
that emissions of six greenhouse gases threaten the public
health and welfare. Greenhouse gases from new motor vehicles and
engines also contribute to such pollution. Subsequently, in
2010, the EPA finalized two regulations under the Clean Air Act
that establish greenhouse gas emission standards for new
light-duty vehicles and clarify preconstruction permitting
requirements for new or modified stationary source facilities
with greenhouse gas emissions that exceed 75,000 tons per year
of carbon dioxide equivalent. In November 2010, the agency
issued updated guidance on determining the “best available
control technologies” (BACT) that would be required to be
implemented by certain new and modified stationary source
facilities beginning in January 2011, but there remains
significant uncertainty regarding the impact of applying BACT
requirements on a case by case basis. Finally, in two recent
settlement agreements, the EPA agreed to schedules for
undertaking additional greenhouse gas rulemakings applicable to
utilities and refineries. The agency is beginning to develop
these new regulations, which are scheduled to be effective in
May 2012 (utilities) and November 2012 (refineries), so it is
not possible to predict their impact at this time. The
EPA’s endangerment finding, motor vehicle greenhouse gas
standards, and greenhouse gas permit rule have all been
challenged in federal courts and decisions are pending.
The EPA also finalized its revised Renewable Fuel Standard
(RFS2) regulations as required by the Energy Independence and
Security Act of 2007. The regulations require fuel providers to
blend increased volumes of renewable fuels into gasoline and
diesel each year and establish specific greenhouse gas reduction
and feedstock criteria for subcategories of renewable fuel,
including cellulosic fuel, advanced biofuel and biomass-based
diesel. The specific impacts of this regulation are determined
by many factors, including fluctuating markets for renewable
fuels and EPA regulatory decisions on potential waivers of
volume requirements.
Additionally, 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. The state is behind schedule in completing
certain elements of the standard. Consequently, initial carbon
intensity reduction requirements are effective as of January
2011, but CARB has delayed other aspects of compliance until it
completes further updates to the regulation later in the year.
In December 2010, CARB adopted regulations implementing the cap
and trade program requirements of the Global Warming Solutions
Act. The first compliance period of the cap and trade program
begins in 2012 and ends in December 2014. CARB has yet to
develop detailed regulations to implement this portion of the
Act, including the determination of how emissions allowances
will be allocated and traded during this period. 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-17 through FS-20
for additional information on environmental matters and their
impact on Chevron and on the company’s 2010 environmental
expenditures, remediation provisions and year-end environmental
reserves. Refer also to Item 1A. Risk Factors on pages 32
through 34 for a discussion of greenhouse gas regulation and
climate change.
The company’s Internet Web site is 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 on the SEC’s Web site at www.sec.gov.
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Chevron is a global energy 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 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. Chevron accepts the risk of changing
commodity prices as part of its business planning process. As
such, an investment in the company carries significant exposure
to fluctuations in crude oil prices.
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.
Chevron operates in both urban areas and remote and sometimes
inhospitable regions. The company’s operations and
facilities are therefore subject to disruption from either
natural or human causes beyond its control, including
hurricanes, floods and other forms of severe weather, war, civil
unrest and other political events, fires, earthquakes,
explosions and system failures, any of which could result in
suspension of operations or harm to people or the natural
environment.
The
company’s operations have inherent risks and hazards that
require significant and continuous oversight.
Chevron’s results depend on its ability to identify and
mitigate the risks and hazards inherent to operating in the
crude oil and natural gas industry. The company seeks to
minimize these operational risks by carefully designing and
building its facilities and conducting its operations in a safe
and reliable manner. However, failure to manage these risks
effectively could result in unexpected incidents, including
releases, explosions or mechanical failures resulting in
personal injury, loss of life, environmental damage, loss of
revenues, legal liability
and/or
disruption to operations. Chevron has implemented and maintains
a system of policies, behaviors and compliance mechanisms to
manage safety, health, environmental, reliability and efficiency
risks; to verify compliance with applicable laws and policies;
and to respond to and learn from unexpected incidents.
Nonetheless, in certain situations where Chevron is not the
operator, the company may have limited influence and control
over third parties, which may limit its ability to manage and
control such risks.
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.
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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, 2010,
25 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-three percent of the company’s net proved
reserves, including affiliates, were located in OPEC countries
at December 31, 2010.
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 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 2010, the U.S. Environmental Protection Agency (EPA)
finalized two regulations under the Clean Air Act that establish
greenhouse gas emission standards for new light-duty vehicles
and clarify preconstruction permitting requirements for new or
modified stationary source facilities with greenhouse gas
emissions that exceed 75,000 tons per year of carbon dioxide
equivalent. In addition, the EPA recently agreed to develop
additional regulations on greenhouse gas emissions from
utilities and refineries. The agency is beginning to develop
these new regulations, which are scheduled to be effective in
May 2012 (utilities) and November 2012 (refineries), so it is
not possible to predict their impact at this time.
The U.S. Congress has previously considered and may in the
future consider legislation aimed at reducing greenhouse gas
emissions. At this time it is not possible to predict any
specific Congressional actions in 2011 or beyond, and it is
unclear how any such legislation would reconcile with the Clean
Air Act or current EPA regulations.
In December 2010, California adopted regulations implementing
the cap and trade program requirements of the state’s
Global Warming Solutions Act, also known as AB32. The first
compliance period of the cap and trade program begins in 2012
and ends in December 2014. Chevron may incur costs associated
with emissions reduction activities, and the purchase of
allowances or credits for its facilities in California. In
addition, Chevron’s purchased energy costs from utilities
may increase starting in January 2012, when electricity
generators are required to purchase allowances or credits for
electricity sold in California.
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
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be entitled to receive emission allowance allocations or would
need to purchase compliance instruments on the open market or
through auctions, the price and availability of emission
allowances and credits, and the impact of legislation or other
regulation on the company’s ability to recover the costs
incurred through the pricing of the company’s products.
Material price increases or incentives to conserve or use
alternative energy sources could reduce demand for products the
company currently sells and adversely affect the company’s
sales volumes, revenues and margins.
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.
None.
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-66 through FS-80.
Note 13, “Properties, Plant and Equipment,” to
the company’s financial statements is on
page FS-45.
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 and by the pertinent
provincial and municipal governments. 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 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 $18.9 billion, which would, according to
the engineer, provide financial compensation for purported
damages, including wrongful death claims, and
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pay for, among other items, environmental remediation, health
care systems and additional infrastructure for Petroecuador. The
engineer’s report also asserted that an additional
$8.4 billion could be assessed against Chevron for unjust
enrichment. In 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 was recused. In 2010, Chevron
moved to strike the mining engineer’s report and to dismiss
the case based on evidence obtained through discovery in the
United States indicating that the report was prepared by
consultants for the plaintiffs before being presented as the
mining engineer’s independent and impartial work and
showing further evidence of misconduct. In August 2010, the
judge issued an order stating that he was not bound by the
mining engineer’s report and requiring the parties to
provide their positions on damages within 45 days. Chevron
subsequently petitioned for recusal of the judge, claiming that
he had disregarded evidence of fraud and misconduct and that he
had failed to rule on a number of motions within the statutory
time requirement.
In September 2010, Chevron submitted its position on damages,
asserting that no amount should be assessed against it. The
plaintiffs’ submission, which relied in part on the mining
engineer’s report, took the position that damages are
between approximately $16 billion and $76 billion and
that unjust enrichment should be assessed in an amount between
approximately $5 billion and $38 billion. The next
day, the judge issued an order closing the evidentiary phase of
the case and notifying the parties that he had requested the
case file so that he could prepare a judgment. Chevron
petitioned to have that order declared a nullity in light of
Chevron’s prior recusal petition, and because procedural
and evidentiary matters remain unresolved. In October 2010,
Chevron’s motion to recuse the judge was granted. A new
judge took charge of the case and revoked the prior judge’s
order closing the evidentiary phase of the case. On
December 17, 2010, the judge issued an order closing the
evidentiary phase of the case and notifying the parties that he
had requested the case file so that he could prepare a judgment.
Chevron and Texpet filed an arbitration claim in September 2009
against the Republic of Ecuador before the Permanent Court of
Arbitration in The Hague under the Rules of the United Nations
Commission on International Trade Law. The claim alleges
violations of the Republic of Ecuador’s obligations under
the United States-Ecuador Bilateral Investment Treaty (BIT) and
breaches of the settlement and release agreements between the
Republic of Ecuador and Texpet (described above), which are
investment agreements protected by the BIT. Through the
arbitration, Chevron and Texpet are seeking relief against the
Republic of Ecuador, including a declaration that any judgment
against Chevron in the Lago Agrio litigation constitutes a
violation of Ecuador’s obligations under the BIT. On
February 9, 2011, the Permanent Court of Arbitration issued
an Order for Interim Measures requiring the Republic of Ecuador
to take all measures at its disposal to suspend or cause to be
suspended the enforcement or recognition within and without
Ecuador of any judgment against Chevron in the Lago Agrio case
pending further order of the Tribunal. Chevron expects to
continue seeking permanent injunctive relief and monetary relief
before the Tribunal.
Through a series of recent U.S. court proceedings initiated
by Chevron to obtain discovery relating to the Lago Agrio
litigation and the BIT arbitration, Chevron has obtained
evidence that it believes shows a pattern of fraud, collusion,
corruption, and other misconduct on the part of several lawyers,
consultants and others acting for the Lago Agrio plaintiffs. In
February 2011, Chevron filed a civil lawsuit in the Federal
District Court for the Southern District of New York
against the Lago Agrio plaintiffs and several of their lawyers,
consultants and supporters alleging violations of the Racketeer
Influenced and Corrupt Organizations Act and other state laws.
Through the civil lawsuit, Chevron is seeking relief that
includes an award of damages and a declaration that any judgment
against Chevron in the Lago Agrio litigation is the result of
fraud and other unlawful conduct and is therefore unenforceable.
On February 8, 2011, the Court issued a temporary
restraining order prohibiting the Lago Agrio plaintiffs and
persons acting in concert with them from taking any action in
furtherance of recognition or enforcement of any judgment
against Chevron in the Lago Agrio case until March 8, 2011.
Chevron’s motion for a preliminary injunction is presently
before the Court.
On February 14, 2011, the Provincial Court in Lago Agrio
rendered an adverse judgment in the case. The Provincial Court
rejected Chevron’s defenses to the extent the Court
addressed them in its opinion. The judgment assesses
approximately $8.6 billion in damages and about $0.9 billion for
the plaintiffs’ representatives. It also assesses an
additional amount of approximately $8.6 billion in punitive
damages unless the company provides a public apology. Chevron
continues to believe the Court’s judgment is illegitimate
and unenforceable in Ecuador, the United States and other
countries. The company also believes the judgment is the product
of fraud, and contrary to the legitimate scientific evidence.
Chevron will appeal this decision in Ecuador. Chevron cannot
predict the timing or ultimate outcome of the appeals process in
Ecuador. Chevron will continue a vigorous defense of any
imposition of liability. Because Chevron has no substantial
assets in Ecuador, Chevron would expect enforcement actions as a
result of this judgment to be brought in other jurisdictions.
Chevron expects to contest any such actions.
The ultimate outcome of the foregoing matters, including 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
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associated with the judgment, the 2008 engineer’s report
and the September 2010 plaintiffs’ submission, management
does not believe these documents have 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).
California
Air Resources Board
As reported in the company’s annual report on
Form 10-K
for the year ended December 31, 2009, 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.
As reported in the company’s annual report on
Form 10-K
for the year ended December 31, 2009, 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 continue.
As reported in the company’s quarterly report on
Form 10-Q
for the quarter ended September 30, 2010, on July 14,
2009, CARB issued a notice of violation against Chevron Products
Company for alleged violations of CARB’s regulations
governing the certification of gasoline that occurred during
storage at a third-party facility and which had been
self-reported by the company on discovery. The company has
determined that resolution of this matter may result in the
payment of a civil penalty exceeding $100,000.
Other
Government Proceedings
As reported in the company’s annual report on
Form 10-K
for the year ended December 31, 2009, 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.
As reported in the company’s quarterly report on
Form 10-Q
for the quarter ended March 31, 2010, in March 2010, the
United States Department of Justice (DOJ) indicated that it
intends to seek a civil penalty against the company’s
service station operations in Puerto Rico for alleged violations
of the Commonwealth of Puerto Rico’s underground storage
tank regulations. The alleged violations include failure to test
leak detectors, perform release monitoring and maintain
compliance records. The DOJ’s action may result in payment
of a civil penalty exceeding $100,000.
As reported in the company’s quarterly report on
Form 10-Q
for the quarter ended June 30, 2010, Chevron has entered
into negotiations with the United States Environmental
Protection Agency (EPA) with respect to alleged air pollution
violations at the company’s Perth Amboy, New Jersey
refinery identified in a September 16, 2008 Compliance
Order issued by the EPA. The alleged violations relate to
certain management and reporting requirements set forth in the
EPA’s Leak Detection and Repair regulations (these
regulations pertain to the control and monitoring of fugitive
emissions from refinery process equipment). Based on discussions
with the EPA, it appears that the resolution of this matter will
result in the payment of a civil penalty exceeding $100,000.
In the fourth quarter 2010, Chevron paid the United States
Department of Transportation a $423,000 civil penalty as the
result of an 800 barrel crude oil spill that occurred on
June 12, 2010. The spill originated from a pipeline that
runs from the company’s Rangely Colorado Field to its Salt
Lake Refinery.
The California Attorney General has alleged violations of the
State’s underground storage tank regulations at the
company’s service stations in the State of California. The
allegations are part of a state-wide enforcement action which
the company determined in the fourth quarter 2010 may
result in the payment of a civil penalty exceeding $100,000.
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PART II
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
The selected financial data for years 2006 through 2010 are
presented on
page FS-65.
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.
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-15
and in Note 10 to the Consolidated Financial Statements,
“Financial and Derivative Instruments,” beginning on
page FS-39.
The index to Management’s Discussion and Analysis,
Consolidated Financial Statements and Supplementary Data is
presented on
page FS-1.
None.
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The company’s management has evaluated, with the
participation of the Chief Executive Officer and the Chief
Financial Officer, the effectiveness of the company’s
disclosure controls and procedures (as defined in
Rule 13a-15(e)
and
15d-15(e)
under the Securities Exchange Act of 1934 (the “Exchange
Act”)) as of the end of the period covered by this report.
Based on this evaluation, the Chief Executive Officer and the
Chief Financial Officer concluded that the company’s
disclosure controls and procedures were effective as of
December 31, 2010.
The company’s management is responsible for establishing
and maintaining adequate internal control over financial
reporting, as such term is defined in Exchange Act
Rule 13a-15(f).
The company’s management, including the Chief Executive
Officer and the Chief Financial Officer, conducted an evaluation
of the effectiveness of the company’s internal control over
financial reporting based on the Internal Control —
Integrated Framework 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, 2010.
The effectiveness of the company’s internal control over
financial reporting as of December 31, 2010, 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, 2010, 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 company’s coal and other mine safety information is
presented in Exhibit 99.2 on
page E-28.
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PART III
Executive
Officers of the Registrant at February 24, 2011
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.
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 2011 Annual Meeting and
2011 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 2011 Annual
Meeting of Stockholders (the “2011 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 2011 Proxy Statement is
incorporated by reference into this Annual Report on
Form 10-K.
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The information required by Item 406 of
Regulation S-K
and contained under the heading “Board
Operations — Business Conduct and Ethics Code” in
the 2011 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 2011 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
2011 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 2011 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 2011 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 2011 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.
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 2011 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 2011 Proxy Statement is incorporated by
reference into this Annual Report on
Form 10-K.
The information required by Item 404 of
Regulation S-K
and contained under the heading “Board
Operations — Transactions with Related Persons”
in the 2011 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
2011 Proxy Statement is incorporated by reference into this
Annual Report on
Form 10-K.
The information required by Item 9(e) of Schedule 14A
and contained under the heading “Proposal to Ratify the
Appointment of the Independent Registered Public Accounting
Firm” in the 2011 Proxy Statement is incorporated by
reference into this Annual Report on
Form 10-K.
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(a) The following documents are filed as part of this
report:
(1) Financial
Statements:
(2) Financial
Statement Schedules:
(3) Exhibits:
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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 24th day of February,
2011.
Chevron Corporation
John S. Watson, Chairman of the Board
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the Registrant and in the capacities indicated on
the 24th day of February, 2011.
Financial Table of Contents
FS-2
FS-25
FS-32
FS-1
Table of Contents
Management’s Discussion and Analysis of Financial Condition and Results of Operations Key Financial Results
Earnings by Major Operating Area
The activities reported in Chevron’s upstream and downstream operating segments have
changed effective January 1, 2010. Results for the chemicals businesses are now reported as part of
the downstream segment. In addition, the company’s significant upstream-enabling operations,
primarily a gas-to-liquids project and major international export pipelines, have been reclassified
from the downstream segment to the upstream segment. Prior period information in this report has
been revised to conform to the 2010 presentation.
Refer to the “Results of Operations” section beginning on page FS-7 for a discussion of
financial results by major operating area for the three years ended December 31, 2010.
Business Environment and Outlook
Chevron is a global energy company with substantial business activities in the following
countries: Angola, Argentina, Australia, Azerbaijan, Bangladesh, Brazil, Cambodia, Canada, Chad,
China, Colombia, Democratic Republic of the Congo, Denmark, Indonesia, Kazakhstan, Myanmar, the
Netherlands, Nigeria, Norway, the Partitioned Zone between
Saudi Arabia and Kuwait, the Philippines, Republic of the Congo, Singapore, South Africa, South
Korea, Thailand, Trinidad and Tobago, the United Kingdom, the United States, Venezuela and Vietnam.
Earnings of the company depend mostly on the profitability of its upstream and downstream
business segments. The single biggest factor that affects the results of operations for 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 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 page FS-7 for discussions of net gains on asset sales
during 2010. Asset dispositions and restructurings may also occur in future periods and could
result in significant gains or losses.
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In recent years, Chevron and the oil and gas industry generally experienced an increase in
certain costs that exceeded the general trend of inflation in many areas of the world. 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. Industry costs began to level out in fourth quarter 2009 and rose
slightly in 2010. The company continues to actively manage its schedule of work, contracting,
procurement and supply-chain activities to effectively manage costs.
The company closely monitors developments in the financial and credit markets, the level of
worldwide economic activity and the implications for the company of movements in prices for crude
oil and natural gas. Management takes these developments into account in the conduct of daily
operations and for business planning. The company remains confident of its underlying financial
strength to address potential challenges presented in the current environment. (Refer also to the
“Liquidity and Capital Resources” section beginning on page FS-12.)
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 seeks 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 can also be affected by
damage to production facilities caused by severe weather or civil unrest.
The chart at the left shows the trend in benchmark prices for West Texas Intermediate (WTI)
crude oil and U.S. Henry Hub natural gas. The WTI price averaged $79 per barrel for the full-year
2010, compared to $62 in 2009. As of mid-February 2011, the WTI
price was about $85.
A differential in crude oil prices exists between high quality (high-gravity, low-sulfur)
crudes and those of lower quality (low-gravity, high-sulfur). The amount of the differential in any
period is associated with the supply of heavy crude available versus the demand, which is a
function of the 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
widened during 2010 primarily due to both strong diesel prices and relatively weaker fuel oil
prices.
Chevron produces or shares in the production of heavy crude oil in California, Chad,
Indonesia, the Partitioned Zone between Saudi Arabia and Kuwait, Venezuela and in certain fields in
Angola, China and the United Kingdom sector of the North Sea. (See page FS-11 for the company’s
average U.S. and international crude oil realizations.)
In contrast to price movements in the global market for crude oil, price changes for natural
gas in many regional markets are more closely aligned with supply-and-demand conditions in those
markets. In the United States, prices at Henry Hub averaged about $4.50 per thousand cubic feet
(MCF) during 2010, compared with about $3.80 during 2009. As of mid-February 2011, the Henry Hub
spot price was about $4.20 per MCF. Fluctuations in the price for natural gas in the United States
are closely associated with customer demand relative to the volumes produced in North America and
the level of inventory in underground storage.
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Management’s Discussion and Analysis of Financial Condition and Results of Operations 
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. In some of
these locations Chevron is investing in long-term projects 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 $4.60 per MCF during 2010, compared
with about $4.00 per MCF during 2009. These realizations reflect a strong demand for energy in
certain Asian markets. (See page FS-11 for the company’s average natural gas realizations for the
U.S. and international regions.)
The company’s worldwide net oil-equivalent production in 2010 averaged 2.763 million barrels
per day. About one-fifth of the company’s net oil-equivalent production in 2010 occurred in the
OPEC-member countries of Angola, Nigeria, Venezuela and the Partitioned Zone between Saudi Arabia
and Kuwait. OPEC quotas had no effect on the company’s net crude oil production in 2010, while
production in 2009 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 2009. At the December
2010 meeting, members of OPEC supported maintaining production quotas in effect since December
2008.
The company estimates that oil-equivalent production in 2011 will average approximately 2.790
million barrels per day. This estimate is subject to many factors and
uncer-
tainties, including additional quotas that may be imposed by OPEC, price effects on production
volumes calculated under production sharing and variable-royalty provisions of certain agreements,
changes in fiscal terms or restrictions on the scope of company operations, delays in project
startups, fluctuations in demand for natural gas in various markets, weather conditions that may
shut in production, civil unrest, changing geopolitics, delays in completion of maintenance
turnarounds, greater-than-expected declines in production from mature fields, or other disruptions
to operations. The outlook for future production levels is also affected by the size and number of
economic investment opportunities and, for new large-scale projects, the time lag between initial
exploration and the beginning of production. Investments in upstream projects generally begin well
in advance of the start of the associated crude oil and natural gas production. A significant
majority of Chevron’s upstream investment is made outside the United States.
Refer to the “Results of Operations” section on pages FS-7 through FS-8 for additional
discussion of the company’s upstream business.
Refer
to Table V beginning on page FS-71 for a tabulation of the company’s proved net oil and
gas reserves by geographic area, at the beginning of 2008 and each year-end from 2008 through 2010,
and an accompanying discussion of major changes to proved reserves by geographic area for the
three-year period ending December 31, 2010.
Gulf of Mexico Update In April 2010, an accident occurred on the Transocean Deepwater Horizon,
a deepwater drilling rig in the Gulf of Mexico, resulting in a loss of life, the sinking of the rig
and a significant oil spill. The rig was drilling an exploratory well at the BP-operated Macondo
prospect. Chevron was not a participant in the well. Subsequent to the event, the U.S. Department
of the Interior put in place a moratorium on the drilling of wells using subsea blowout preventers
(BOPs) or surface BOPs on a floating facility in the Gulf of Mexico and the Pacific regions. In
October 2010, the Secretary of the Interior lifted the drilling moratorium, provided that operators
certify compliance with all the newly expanded rules and requirements, and demonstrate the
availability of adequate blowout containment resources.
The moratorium and the ensuing slowdown in issuing drilling permits since the moratorium was
lifted have resulted in delays in shallow water drilling activity, delayed the drilling of
exploratory deepwater wells and impacted development drilling on both operated and nonoperated
projects in the Gulf of Mexico. The company’s daily net oil-equivalent production in the Gulf of
Mexico was reduced by about 10,000 barrels per day for the full year. The company has submitted
several deepwater drilling permit applications and plans to submit additional applications in 2011.
Two deepwater drillships are on stand-by, pending issuance of permits from
FS-4
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the U.S. Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE), to drill wells in
the Gulf of Mexico. A third deepwater drillship is drilling a water injection well at the Tahiti
Field. Additionally, the completion of previously drilled wells has recommenced at the nonoperated
Perdido and Caesar/Tonga projects. The future effects of this incident, including any new or
additional regulations that may be adopted and the timing of BOEMRE issuing drilling permits, are
not fully known at this time. Chevron remains committed to deepwater exploration and development in
the Gulf of Mexico and other deepwater basins around the world.
During the moratorium, Chevron
participated in a number of industry efforts to identify opportunities to improve industry
standards in prevention, intervention and spill response. In July 2010, Chevron and several other
companies announced plans to build and deploy a rapid response system that will be available to
capture and contain crude oil in the unlikely event of a future well blowout in the deepwater Gulf
of Mexico. The new system will be engineered to be used in water depths up to 10,000 feet and
designed to have capacity to contain 100,000 barrels per day, with potential for expansion. The
companies committed to equally fund the initial $1 billion investment in the system. There will be
additional ongoing costs for operations and maintenance of the system components. An initial
agreement to secure containment equipment has been announced, and other equipment is expected to be
secured and available in the coming months, with the new system targeted for completion in early
2012. The companies have formed an organization, the Marine Well Containment Company, to operate
and maintain this system. Other companies have been invited and encouraged to participate in this
organization.
Downstream Earnings for the downstream segment are closely tied to margins on the refining,
manufacturing and marketing of products that include gasoline, diesel, jet fuel, lubricants, fuel
oil, fuel and lubricant additives, and petrochemicals. Industry margins are sometimes volatile and
can be affected by the global and regional supply-and-demand balance for refined products and
petrochemicals and by changes in the price of crude oil, other refinery and petrochemical
feedstocks, and natural gas. Industry margins can also be influenced by inventory levels,
geopolitical events, cost of materials and services, refinery or chemical plant capacity
utilization, maintenance programs and disruptions at refineries or chemical plants resulting from
unplanned outages due to severe weather, fires or other operational events.
Other factors affecting profitability for downstream operations include the reliability and
efficiency of the company’s refining, marketing and petrochemical assets, the effectiveness of the
crude oil and product supply functions and the volatility of tanker-charter rates for the company’s shipping operations, which are driven by the industry’s demand for crude oil and product
tankers. Other factors beyond the company’s control include the general level of inflation and
energy costs to operate the company’s refining, marketing and petrochemical assets.
The company’s most significant marketing areas are the West Coast of North America, the U.S.
Gulf Coast, 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. In third quarter
2010, the company completed its exit from the District of Columbia, Delaware, Indiana, Kentucky,
North Carolina, New Jersey, Maryland, Ohio, Pennsylvania, South Carolina, Virginia, West Virginia
and parts of Tennessee, where the company sold Chevron- and Texaco-branded motor fuels to retail
customers through approximately 1,100 stations, and to commercial and industrial customers through
supply arrangements. Sales in these markets represented approximately 8 percent of the company’s
total 2009 U.S. retail fuel sales volumes.
The company’s refining and marketing margins in 2010 improved over 2009, but remain
relatively weak due to the economic slowdown, excess refined product supplies and surplus refining
capacity. Expecting these conditions to continue for several years, in first quarter 2010 the
company announced that its downstream businesses would be restructured to improve operating
efficiency and achieve sustained improvement in financial performance. As part of this
restructuring, employee-reduction programs were announced for the United States and international
downstream operations. The initial estimate included approximately 3,200 employees. Due to
redeployment efforts within the company, it is currently expected that approximately 2,800
employees in the downstream operations will be terminated under these programs before the end of
2011. About 1,100 of the affected employees are located in the United States. During 2010, 1,400
employees were terminated worldwide. Refer to Note 23 of the Consolidated Financial Statements,
beginning on page FS-59, for further discussion. In 2010, the company solicited bids for 13 U.S.
terminals and certain operations in Europe (including the company’s Pembroke Refinery), the
Caribbean, and select Central America and Africa markets. These sales are part of the company’s
ongoing effort to concentrate downstream resources and capital on strategic global assets. These
potential market exits, dispositions of assets, and other actions may result in gains or losses in
future periods. Through fourth quarter 2010, the company completed the sale of six U.S. terminals
and certain marketing businesses in Africa, which resulted in gains that were not material to the
company. Also, in late 2010 the company completed the sale of its 23.4 percent ownership interest
in the Colonial Pipeline Company, which resulted in a gain on sale of nearly $400 million.
Refer to the “Results of Operations” section on page FS-9 for additional discussion of the
company’s downstream operations.
All
Other consists of mining operations, power generation businesses, worldwide cash
management and debt financing activities, corporate administrative functions, insurance operations,
real estate activities, alternative fuels, and technology companies. In first quarter 2010,
employee-reduction programs were announced for the corporate staffs. As of year-end, it was
expected that approximately 400 employees from the corporate staffs will be terminated under the
programs by the end of 2011, including approximately 100 who were terminated in 2010. Refer to Note
23 of the Consolidated Financial Statements, beginning on page FS-59, for further discussion.
FS-5
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Management’s Discussion and Analysis of Financial Condition and Results of Operations Operating Developments
Key operating developments and other events during 2010 and early 2011 included the
following:
Upstream
Australia Construction activities on Barrow Island and other activities for the Gorgon Project
progressed on schedule during 2010 with the award of approximately $25 billion of contracts for
materials and services, clearing of the plant site,
 During 2010, the company announced additional deepwater natural gas discoveries, including the
Clio and Acme prospects in 67 percent-owned Block WA-205-P, Yellowglen prospect in 50
percent-owned Block WA-268-P, Brederode prospect in 50 percent-owned Block WA-364-P,
and Sappho prospect in 50 percent-owned Block WA-392-P. In February 2011, the company announced a
natural gas discovery in the Orthrus prospect in 50 percent-owned Block WA-24-R. These discoveries
are expected to contribute to further growth at company-operated LNG projects in Australia.
Cambodia The company completed three successful exploration wells during 2010. In the
first-half 2011, a 30-year production permit for the production sharing contract is expected to be
approved by the government. A final investment decision for construction of a wellhead platform and
a floating storage and offloading vessel is expected in 2011.
Canada First production was achieved from the Jackpine Mine in third quarter 2010 as a result
of Athabasca Oil Sands Project Expansion 1 activities. In addition, through 2010 the company
acquired approximately 200,000 acres of shale gas leasehold in western Canada. The appraisal of
this acreage is expected to begin by the second-half 2011.
China The company acquired a 100 percent interest in Blocks 53-30 and 64-18, and a 59 percent
interest in Block 42-05, covering a combined total exploratory acreage of approximately 5.2 million
acres in the South China Sea’s Pearl River Mouth Basin.
Indonesia A final investment decision was reached for Development Area 13 of the Duri Field,
where Chevron holds a 100 percent working interest.
The company awarded FEED contracts in December 2010 for the Gendalo-Gehem natural gas
development in the Makassar Strait offshore East Kalimantan, Indonesia. Contracts for floating
production units, subsea and flowline systems, export pipelines, and an onshore receiving facility
were awarded for the project.
Kazakhstan/Russia Approval was obtained from the shareholders and governing bodies of the
Caspian Pipeline Consortium for a $5.4 billion expansion of the Caspian Pipeline. The capacity of
the 935-mile pipeline, which carries crude oil from western Kazakhstan to a dedicated terminal on
the Black Sea, will increase to 1.4 million barrels per day.
Liberia The company acquired a 70 percent interest and operatorship in three deepwater blocks
covering 2.4 million acres off the coast of Liberia in western Africa. A three-year exploratory
program began in fourth quarter 2010.
Poland Acquisition work commenced in October 2010 on a 2-D seismic survey across the company’s four shale gas licenses in southeast Poland. Chevron has a 100 percent-owned and operated
interest in these four concessions, totalling 1.1 million acres.
Republic of the Congo Discoveries were confirmed at the Bilondo Marine 2 and 3 wells within
the Moho-Bilondo license. Chevron has a 31.5 percent interest in the permit area.
Romania The company successfully bid on three shale gas exploration blocks, comprising
approximately 670,000 acres, in the southeast region of the country. In February
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2011, the company acquired a 100 percent interest in the EV-2 Barlad shale gas concession, covering
1.5 million acres in the northeast region of the country.
Russia The company signed a nonbinding HOA for a deepwater development partnership on the
Shatsky Ridge in the eastern Black Sea.
Turkey The company signed a Joint Operation Agreement for an exploration license in the Black
Sea. Chevron acquired a 50 percent interest in a western portion of License 3921, a 5.6
million-acre block located 220 miles northwest of the capital city of Ankara.
United States In March 2010, first oil was achieved at the nonoperated Perdido Regional
Development in the Gulf of Mexico. Located in nearly 8,000 feet of water, Perdido is also the
world’s deepest offshore oil and gas drilling and production spar. Chevron has a 37.5 percent
working interest in the Perdido regional host facility.
The company sanctioned development of the Jack/St. Malo project in October 2010, the company’s first operated project located in the Lower Tertiary trend in the deepwater Gulf of Mexico. Seven
exploration and appraisal wells have been successfully and safely drilled at these fields since
2003. Chevron has a working interest of 50 percent in the Jack Field and 51 percent in the St. Malo
Field.
In December 2010, the company sanctioned development of the 60 percent-owned and operated Big
Foot project in the deepwater Gulf of Mexico.
In April 2010, the company successfully bid for new exploration acreage in a central Gulf of
Mexico lease sale.
In February 2011, the company completed the acquisition of Atlas Energy, Inc., for $4.47
billion including assumed debt. Atlas holds one of the premier acreage positions in the Marcellus
Shale, concentrated in southwestern Pennsylvania.
Venezuela In February 2010, a Chevron-led consortium was named the operator of the Carabobo 3
heavy-oil project, composed of three blocks in the Orinoco Oil Belt of eastern Venezuela. A joint
operating company, Petroindependencia, was formed in May 2010, and work toward commercialization of
the Carabobo 3 project was initiated. The consortium holds a combined 40 percent interest in the
project.
Downstream
Africa
In December 2010 and February 2011, the company completed the sale of its marketing
businesses in Malawi, Mauritius, Réunion, Tanzania and Zambia.
Caribbean and Central America In November 2010, the company announced an agreement to sell its
fuels marketing and aviation fuels businesses in Antigua, Barbados, Belize, Costa Rica, Dominica,
French Guiana, Grenada, Guadeloupe, Guyana, Martinique, Nicaragua, St. Kitts, St. Lucia, St.
Vincent, and Trinidad and Tobago. The transactions are expected to close by third quarter 2011,
following receipt of required local regulatory and government approvals. This sale is part of the
company’s ongoing effort to concentrate downstream resources and capital on strategic global
assets.
Europe In February 2011, the company announced an agreement to sell its fuels, finished
lubricants and aviation fuels businesses in Spain.
South Korea A new, 60,000-barrel-per-day heavy-oil hydrocracker was commissioned and reached
full capacity in third quarter 2010 at the 50 percent-owned GS Caltex Yeosu Refinery in South
Korea. Also at the Yeosu Refinery, GS Caltex announced plans to construct a 53,000-barrel-per-day
gas oil fluid catalytic cracking unit. The unit is scheduled for start-up in 2013. Both units are
designed to increase high-value product yield and lower feedstock costs.
United States In October 2010, the company sold its 23.4 percent ownership interest in the
Colonial Pipeline Company.
In January 2011, the company announced the final investment decision on a $1.4 billion project
to construct a lubricants manufacturing facility at the Pascagoula refinery. The facility will
manufacture 25,000 barrels per day of premium base oil.
Other
Common Stock Dividends The quarterly common stock dividend increased by 5.9 percent in April 2010,
to $0.72 per common share, making 2010 the 23rd consecutive year that the company increased its
annual dividend payment.
Common Stock Repurchase Program In July 2010, the company terminated the three-year $15
billion share repurchase program that had been initiated in September 2007. In its place, the Board
of Directors approved a new, ongoing share repurchase program with no set term or monetary limits.
The company began purchases of its common stock in the fourth quarter, and as of December 31, 2010,
8.8 million common shares had been acquired under the program for $750 million.
Results of Operations
Major Operating Areas The following section presents the results of operations for the
company’s business segments – Upstream and Downstream – as well as for “All Other.” Earnings are
also presented for the U.S. and international geographic areas of the Upstream and Downstream
business segments. (Refer to Note 11, beginning on page FS-41, 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
U.S. upstream earnings of $4.1 billion in 2010 increased $1.9 billion from 2009. Higher
prices for crude oil and natural gas increased earnings by $2.1 billion between periods. Partly
offsetting these effects were higher operating expenses of $200 million, in part due to the Gulf of
Mexico drilling moratorium. Lower exploration expenses were essentially offset by higher tax items
and higher depreciation expenses.
U.S. upstream earnings of $2.3 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,
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Management’s Discussion and Analysis of Financial Condition and Results of Operations 
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 an absence of charges for damages related to the 2008 hurricanes in the Gulf of
Mexico.
The company’s average realization for U.S. crude oil and natural gas liquids in 2010 was
$71.59 per barrel, compared with $54.36 in 2009 and $88.43 in 2008. The average natural gas
realization was $4.26 per thousand cubic feet in 2010, compared with $3.73 and $7.90 in 2009 and
2008, respectively.
Net oil-equivalent production in 2010 averaged 708,000 barrels per day, down 1 percent from
2009 and up 6 percent from 2008. Natural field declines between 2010 and 2009 were mostly offset by
increased production from the Tahiti Field. The increase between 2009 and 2008 was mainly due to
the start-up of the Blind Faith Field in late 2008 and the Tahiti Field in second quarter 2009. The
net liquids component of oil-equivalent production for 2010 averaged 489,000 barrels per day, up 1
percent from 2009 and up 16 percent compared with 2008. Net natural gas production averaged 1.3
billion cubic feet per day in 2010, down approximately 6 percent from 2009 and down about 12
percent from 2008. Refer to the “Selected Operating Data” table on page FS-11 for the three-year
comparative production volumes in the United States.
International Upstream
Earnings of $13.6 billion in 2010 increased $4.9 billion from 2009. Higher prices for crude
oil and natural gas increased earnings by $4.3 billion, and an increase in net oil-equivalent
production in the 2010 period benefited income by about $1.2 billion. This net benefit was partly
offset by higher operating expenses of $500 million. A favorable change in tax items of about $450
million was mostly offset by higher depreciation expenses. The 2009 period included gains of about
$500 million on asset sales and tax items related to the Gorgon Project in Australia. Foreign
currency effects decreased earnings by $293 million in the 2010 period, compared with a reduction
of $578 million a year earlier, primarily reflecting noncash losses on balance sheet remeasurement.
International upstream earnings of $8.7 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.
The company’s average realization for international crude oil and natural gas liquids in 2010
was $72.68 per barrel, compared with $55.97 in 2009 and $86.51 in 2008. The average natural gas
realization was $4.64 per thousand cubic feet in 2010, compared with $4.01 and $5.19 in 2009 and
2008, respectively.
International net oil-equivalent production of 2.06 million barrels per day in 2010 increased
about 3 percent and 11 percent from 2009 and 2008, respectively. The volumes in 2010 include
synthetic oil that was reported in 2009 and 2008 as production from oil sands in Canada. Absent the
impact of prices on certain production-sharing and variable-royalty agreements, net oil-equivalent
production increased 5 percent in 2010 and 4 percent in 2009, when compared with the prior year’s
production.
The net liquids component of international oil-equivalent production was 1.4 million barrels
per day in 2010, an increase of approximately 3 percent from 2009 and 14 percent from 2008.
International net natural gas production of 3.7 billion cubic feet per day in 2010 was up 4 percent
and 3 percent from 2009 and 2008, respectively.
Refer to the “Selected Operating Data” table, on page FS-11, for the three-year comparative of
international production volumes.
FS-8
Table of Contents
U.S. Downstream
U.S. downstream earned $1,339 million in 2010, compared with a loss of $121 million in
2009. Improved margins on refined products increased earnings by about $550 million. Also
contributing to the increase was a nearly $400 million gain on the sale of a 23.4 percent ownership
interest in the Colonial Pipeline Company. Higher earnings from chemicals operations increased
earnings by about $300 million, largely from improved margins at the 50 percent-owned Chevron
Phillips Chemical Company LLC (CPChem).
Earnings decreased approximately $1.5 billion in 2009 from 2008. Lower refined product margins
resulted in an earnings decline of $1.7 billion. Partially offsetting the effects of lower refined
product margins was a decrease in operating expenses, which benefited earnings by $300 million, and
an increase of about $100 million in earnings from CPChem. The improvement for CPChem reflected
lower utility and manufacturing costs, as well as the absence of an impairment recorded in 2008.
These benefits more than offset lower margins on the sale of commodity chemicals.
Sales volumes of refined products were 1.35 million barrels per day in 2010, a decrease of 4
percent from 2009. The decline was mainly in gasoline and jet fuel sales. Sales volumes of refined
products were 1.40 million barrels per day in 2009, a decrease of 1 percent from 2008. U.S. branded
gasoline sales decreased to 573,000 barrels per day in 2010, representing approximately 7 percent
and 5 percent declines from 2009 and 2008, respectively. The decline in 2010, relative to 2009 and
2008, was primarily due to the previously announced exits from selected eastern U.S. retail
markets.
Refer to the “Selected Operating Data” table on page FS-11 for a three-year comparison
of sales volumes of gasoline and other refined products and refinery input volumes.
International Downstream
International downstream earned
$1,139 million in 2010, compared with $594
million in 2009. Higher margins on the
manufacture and sale of gasoline and other
refined products increased earnings by about
$1.0 billion, and a favorable swing in
mark-to-market effects on derivative
instruments benefited earnings by about $300
million. Partially offsetting these items was
the absence of 2009 gains on asset sales of
about $550
million and higher expenses of about $200 million, primarily related to employee reduction and
 Earnings of $594 million in 2009 decreased about $1.2 billion from 2008. A decline of approximately $2.6 billion between periods was associated with weaker margins on the manufacture and sale of gasoline and other refined products and the absence of gains recorded in 2008 on derivative instruments. Foreign currency effects produced an unfavorable variance of about $300 million. Partially offsetting these items were 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 related to refined products marketing operations, primarily in certain countries in Latin America and Africa. International refined product sales volumes of 1.76 million barrels per day in 2010 were 5 percent lower than in 2009, mainly due to asset sales in certain countries in Africa and Latin America. Refined product sales volumes of 1.85 million barrels per day in 2009 were 8 percent lower than in 2008, mainly due to the effects of asset sales and lower demand. Refer to the “Selected Operating Data” table, on page FS-11, for a three-year comparison of sales volumes of gasoline and other refined products and refinery input volumes. FS-9
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Management’s Discussion and Analysis of Financial Condition and Results of Operations All Other
All Other includes mining operations, power generation businesses, worldwide cash
management and debt financing activities, corporate administrative functions, insurance operations,
real estate activities, alternative fuels and technology companies.
Net charges in 2010 increased $209 million from 2009, mainly due to higher expenses for
employee compensation and benefits and higher corporate tax items, partly offset by lower
provisions for environmental remediation at sites that previously had been closed or sold. 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.
Consolidated Statement of Income
Comparative amounts for certain income statement categories are shown below:
Sales and other operating revenues increased in 2010, mainly due to higher prices
for crude oil, natural gas and refined products. Lower 2009 prices resulted in decreased
revenues compared with 2008.
Income from equity affiliates increased in 2010 from 2009 largely due to higher
upstream-related earnings from Tengizchevroil (TCO) in Kazakhstan and Petropiar in Venezuela,
principally related to higher prices for crude oil and increased crude oil production.
Downstream-related affiliate earnings were also higher between the comparative periods, primarily
due to higher earnings from CPChem, as a result of higher margins on sales of commodity chemicals.
Improved margins on refined products and a favorable swing in foreign currency effects at GS Caltex
in South Korea also contributed to the increase in downstream affiliate earnings in the 2010
period. Income from equity affiliates decreased in 2009 from 2008. Upstream-related affiliate
income declined about $1.3 billion mainly due to lower earnings for TCO 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. Refer to Note 12, beginning on page FS-43, for a discussion of Chevron’s
investments in affiliated companies.
Other income of $1.1 billion in 2010 included net gains of approximately $1.1 billion on asset
sales. Other income in both 2009 and 2008 included net gains from asset sales of $1.3 billion.
Interest income was approximately $120 million in 2010, $95 million in 2009 and $340 million in
2008. Foreign currency effects decreased other income by $251 million in 2010 and $466 million in
2009, while increasing other income by $355 million in 2008. In addition, other income in 2008
included approximately $700 million in favorable settlements and other items.
Crude oil and product purchases in 2010 increased $16.8 billion from 2009 due to higher
prices for crude oil, natural gas and refined products. 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.
FS-10
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increased from 2008 mainly due to higher amounts for well write-offs in the United States and
international operations.
Effective income tax rates were 40 percent in 2010, 43 percent in 2009 and 44 percent in
2008. The rate was lower in 2010 than in 2009 primarily due to international upstream impacts. A
lower effective tax rate in international upstream in 2010 was primarily driven by an increased
utilization of tax credits, which had a greater impact on the rate than one-time deferred tax
benefits and relatively low tax rates on asset sales in 2009. Also, a smaller portion of company
income was earned in higher tax rate international upstream jurisdictions in 2010 than in 2009.
Finally, foreign currency remeasurement impacts caused a reduction in the effective tax rate
between periods. The rate was lower in 2009 than in 2008 mainly due to 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.
Refer also to the discussion of income taxes in Note 15 beginning on page FS-47.
Selected Operating Data1,2
FS-11
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Management’s Discussion and Analysis of Financial Condition and Results of Operations Liquidity and Capital Resources
Cash, cash equivalents, time deposits and marketable securities Total balances were $17.1
billion and $8.8 billion at December 31, 2010 and 2009, respectively. Cash provided by operating
activities in 2010 was $31.4 billion, compared with $19.4 billion in 2009 and $29.6 billion in
2008. Cash provided by operating activities was net of contributions to employee pension plans of
approximately $1.4 billion, $1.7 billion and $800 million in 2010, 2009 and 2008, respectively.
Cash provided by investing activities included proceeds and deposits related to asset sales of $2.0
billion in 2010, $2.6 billion in 2009 and $1.5 billion in 2008. Cash provided by operating
activities during 2010 was more than sufficient to fund the company’s $21.8 billion capital and
exploratory program, pay $5.7 billion of dividends to shareholders and repurchase $750 million of
common stock.
Restricted cash of $855 million and $123 million associated with various capital-investment
projects at December 31, 2010 and 2009, 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 $5.7 billion in 2010, $5.3
billion in 2009 and $5.2 billion in 2008. In April 2010, the company increased its quarterly common
stock dividend by 5.9 percent, to $0.72 per share.
Debt and capital lease obligations Total debt and capital lease obligations were $11.5 billion
at December 31, 2010, up from $10.5 billion at year-end 2009.
The $1.0 billion increase in total debt and capital lease obligations during 2010 included
issuance of $1.25 billion of tax-exempt bonds, partially offset by a decrease in short-term
obligations. The company’s debt and capital lease obligations due within one year, consisting
primarily of commercial paper, redeemable long-term obligations and the current portion of
long-term debt, totaled $5.6 billion at December 31, 2010, up from $4.6 billion at year-end 2009.
Of this amount, $5.4 billion and $4.2 billion were reclassified to long-term at the end of each
period, respectively. At year-end 2010, settlement of these obligations was not expected to require
the use of working capital in 2011, as the company had the intent and the ability, as evidenced by
committed credit facilities, to refinance them on a long-term basis.
At December 31, 2010, the company had $6.0 billion in committed credit facilities with various
major banks, expiring in May 2013, which enable the refinancing of short-term obligations on a
long-term basis. These facilities support commercial paper borrowing and can also be used for
general corporate purposes. The 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 the 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, 2010. In addition, the company
has an automatic shelf registration statement that expires in March 2013 for an unspecified amount
of nonconvertible debt securities issued or guaranteed by the company.
The major debt rating agencies routinely evaluate the company’s debt, and the company’s cost
of borrowing can increase or decrease depending on these debt ratings. The company has outstanding
public bonds issued by Chevron Corporation, Chevron Corporation Profit Sharing/Savings Plan Trust
Fund, 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
program and cash that may be generated from asset dispositions. Based on its high-quality debt
ratings, the company believes that it has substantial borrowing capacity to meet unanticipated cash
requirements. The company also can modify capital spending plans during periods of low prices for
crude oil and natural gas and narrow margins for refined products and commodity
FS-12
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Capital and Exploratory Expenditures
chemicals to provide flexibility to continue paying the common stock dividend and
maintain the company’s high-quality debt ratings.
Common stock repurchase program In July 2010, the company terminated the $15 billion share
repurchase program initiated in September 2007. No share repurchases occurred in 2010 under the
program prior to its termination. From the inception of the program, the company acquired 119
million shares at a cost of $10.1 billion. In its place, the Board of Directors approved a new,
ongoing share repurchase program with no set term or monetary limits. The company expects to
repurchase between $500 million and $1 billion of its common shares per quarter, at prevailing
prices, as permitted by securities laws and other legal requirements and subject to market
conditions and other factors. The company began purchases of its common stock in the fourth
quarter, and through December 31, 2010, 8.8 million shares were purchased under the new program for
$750 million.
Capital and exploratory expenditures
Total expenditures for
2010 were $21.8 billion, including
$1.4 billion for the company’s
share of equity-affiliate expenditures. In 2009 and 2008,
expenditures were $22.2 billion and $22.8 billion, respectively,
including the company’s share of
 Of the $21.8 billion of expenditures in 2010, 87 percent, or $18.9 billion, was related to upstream activities. Approximately 80 percent was expended for upstream operations in 2009 and 2008. International upstream accounted for about 82 percent of the worldwide upstream investment in 2010, about 80 percent in 2009 and about 70 percent in 2008, reflecting the company’s continuing focus on opportunities available outside the United States. The company estimates that in 2011, capital and exploratory expenditures will be $26.0 billion, including $2.0 billion of spending by affiliates. Approximately 85 percent of the total, or $22.6 billion, is budgeted for exploration and produc- tion activities, with $17.2 billion of this amount for projects outside the United States. Spending
in 2011 is primarily focused on major development projects in Angola, Australia, Brazil, Canada,
China, Nigeria, Thailand, the United Kingdom and the U.S. Gulf of Mexico. Also included is funding
for base business improvements and focused exploration and appraisal programs in core hydrocarbon
basins.
Worldwide downstream spending in 2011 is estimated at $2.9 billion, with about $1.7 billion
for projects in the United States. Major capital outlays include projects under construction at
refineries in the United States and South Korea.
Investments in technology, power generation and other corporate businesses in 2011 are
budgeted at $500 million.
Noncontrolling interests The company had noncontrolling interests of $730 million and $647
million at December 31, 2010 and 2009, respectively. Distributions to noncontrolling interests
totaled $72 million and $71 million in 2010 and 2009, respectively.
Pension Obligations In 2010, the company’s pension plan contributions were $1.4 billion
(including $1.19 billion to the U.S. plans and $258 million to the international plans). The
company estimates contributions in 2011 will be approximately $950 million ($650 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-20.
Financial Ratios
Financial Ratios
Current
Ratio – current assets divided by current liabilities, which indicates the
company’s ability to repay its short-term liabilities with short-term assets. 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 2010, the book value of inventory was lower than replacement costs,
based on average acquisition costs during the year, by approximately $7.0 billion.
FS-13
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Management’s Discussion and Analysis of Financial Condition and Results of Operations  Debt Ratio – total debt as a percentage of total debt plus Chevron Corporation Stockholders’ Equity, which indicates the company’s leverage. The decrease between 2010 and 2009 was due to a higher Chevron Corporation stockholders’ equity balance. The increase in 2009 over 2008 was primarily due to the increase in debt. Guarantees, Off-Balance-Sheet Arrangements and Contractual Obligations, and Other Contingencies
Direct Guarantee
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 2010, the company had paid $48 million under these indemnities and continues to be obligated for
possible additional indemnification payments in the future.
The company has also provided indemnities relating to contingent environmental liabilities
related to assets originally contributed by Texaco to the Equilon and Motiva joint ventures and
environmental conditions that existed prior to the formation of Equilon and Motiva or that occurred
during the period of 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. 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
with respect 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,
FS-14
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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: 2011 – $17.2 billion; 2012 – $4.1 billion; 2013 – $3.5 billion; 2014 – $3.1
billion; 2015 – $3.0 billion; 2016 and
after – $7.7 billion. A portion of these commitments may
ultimately be shared with project partners. Total payments under the agreements were approximately
$6.5 billion in 2010, $8.1 billion in 2009 and $5.1 billion in 2008.
The following table summarizes the company’s significant contractual obligations:
Contractual Obligations1
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