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Chevron Corporation 10-K 2007 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, 2006
OR
o TRANSITION REPORT
PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from
to
Commission file number 1-368-2
(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 if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
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. þ
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, or a non-accelerated
filer. See definition of “accelerated filer and large
accelerated filer” in
Rule 12b-2
of the Act. (Check one):
Large accelerated filer
þ Accelerated
filer
o Non-accelerated
filer o
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the
Act). Yes o No þ
Aggregate market value of the voting and non-voting common
equity held by non-affiliates computed by reference to the price
at which the common equity was last sold, or the average bid and
asked price of such common equity, as of the last business day
of the registrant’s most recently completed second fiscal
quarter — $136,407,118,275 (As of June 30, 2006)
Number of Shares of Common Stock outstanding as of
February 23, 2007 — 2,157,780,998
DOCUMENTS INCORPORATED BY REFERENCE
(To The Extent Indicated Herein)
Notice of the 2007 Annual Meeting and 2007 Proxy Statement, to
be filed pursuant to
Rule 14a-6(b)
under the Securities Exchange Act of 1934, in connection with
the company’s 2007 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
our control and are difficult to predict. Therefore, actual
outcomes and results may differ materially from what is
expressed or forecasted in such forward-looking statements. The
reader should not place undue reliance on these forward-looking
statements, which speak only as of the date of this report.
Unless legally required, Chevron undertakes no obligation to
update publicly any forward-looking statements, whether as a
result of new information, future events or otherwise.
Among the important factors that could cause actual results to
differ materially from those in the forward-looking statements
are crude oil and natural gas prices; refining margins and
marketing margins; chemicals prices and competitive conditions
affecting supply and demand for aromatics, olefins and additives
products; actions of competitors; 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 or severe weather; the potential
liability for remedial actions under existing or future
environmental regulations and litigation; significant investment
or product changes under existing or future environmental
statutes, regulations and litigation; the potential liability
resulting from pending or future litigation; the company’s
acquisition or disposition of assets; government-mandated sales,
divestitures, recapitalizations, changes in fiscal terms or
restrictions on scope of company operations; 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” 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.
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Chevron
Corporation,1
a Delaware corporation, manages its investments in subsidiaries
and affiliates and provides administrative, financial,
management and technology support to U.S. and foreign
subsidiaries that engage in fully integrated petroleum
operations, chemicals operations, mining operations of coal and
other minerals, power generation and energy services. The
company conducts business activities in the United States and
approximately 180 other countries. Exploration and production
(upstream) operations consist of exploring for, developing and
producing crude oil and natural gas and also marketing natural
gas. Refining, marketing and transportation (downstream)
operations relate to refining crude oil into finished petroleum
products; marketing crude oil and the many products derived from
petroleum; and transporting crude oil, natural gas and petroleum
products by pipeline, marine vessel, motor equipment and rail
car. Chemical operations include the manufacture and marketing
of commodity petrochemicals, plastics for industrial uses, and
fuel and lubricant oil additives.
A list of the company’s major subsidiaries is presented on
pages E-4
and E-5 of
this Annual Report on
Form 10-K.
As of December 31, 2006, Chevron had nearly 62,500
employees (including about 6,600 service station employees).
Approximately 28,800, or 46 percent, of the company’s
employees were employed in U.S. operations.
On August 10, 2005, the company acquired Unocal Corporation
(Unocal), an independent oil and gas exploration and production
company. This acquisition was accounted for under the rules of
Financial Accounting Standards Board Statement No. 141,
Business Combinations. Unocal’s principal upstream
operations were in North America and Asia, including the Caspian
region. Other activities included ownership interests in
proprietary and common carrier pipelines, natural gas storage
facilities and mining operations. Further discussion of the
Unocal acquisition is contained in Note 2 beginning on
page FS-34
of this Annual Report on
Form 10-K.
Petroleum industry operations and profitability are influenced
by many factors, and individual petroleum companies have little
control over some of them. Governmental policies, particularly
in the areas of taxation, energy and the environment have a
significant impact on petroleum activities, regulating how
companies are structured and where and how companies conduct
their operations and formulate their products and, in some
cases, limiting their profits directly. Prices for crude oil and
natural gas, petroleum products and petrochemicals are
determined by supply and demand for these commodities. 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 to
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 petroleum companies as well
as independent and national petroleum companies for the
acquisition of crude oil and natural gas leases and other
properties and for the equipment and labor required to develop
and operate those properties. In its downstream business,
Chevron also competes with fully integrated major petroleum
companies and other independent refining, marketing and
transportation entities in the sale or acquisition of various
goods or services in many national and international markets.
1 Incorporated
in Delaware in 1926 as Standard Oil Company of California, the
company adopted the name Chevron Corporation in 1984 and
ChevronTexaco Corporation in 2001. In 2005, ChevronTexaco
Corporation changed its name to Chevron Corporation. As used in
this report, the term “Chevron” and such terms as
“the company,” “the corporation,”
“our,” “we” and “us” may refer to
Chevron Corporation, one or more of its consolidated
subsidiaries, or all of them taken as a whole, but unless stated
otherwise, it does not include “affiliates” of
Chevron — i.e., those companies accounted for by the
equity method (generally owned 50 percent or less) or
investments accounted for by the cost method. All of these terms
are used for convenience only and are not intended as a precise
description of any of the separate companies, each of which
manages its own affairs.
Table of Contents
Refer to pages FS-2 through FS-9 of this
Form 10-K
in Management’s Discussion and Analysis of Financial
Condition and Results of Operations for a discussion on the
company’s current business environment and outlook.
Chevron’s primary objective is to create value and achieve
sustained financial returns from its operations that will enable
it to outperform its competitors. As a foundation for achieving
this objective, the company had established the following
strategies, which continue into 2007:
The company will also continue to invest in renewable-energy
technologies, with an objective of capturing profitable
positions in important renewable sources of energy.
The upstream, downstream and chemicals activities of the company
and its equity affiliates are widely dispersed geographically,
with operations in North America, South America, Europe, Africa,
the Middle East, Asia, and Australasia. Tabulations of segment
sales and other operating revenues, earnings and income taxes
for the three years ending December 31, 2006, and assets as
of the end of 2006 and 2005 — for the United States
and the company’s international geographic
areas — are in Note 8 to the consolidated
financial statements beginning on
page FS-38
of this Annual Report on
Form 10-K.
In addition, 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-41
to FS-43.
Total reported expenditures for 2006 were $16.6 billion,
including $1.9 billion for Chevron’s share of
expenditures by affiliated companies, which did not require cash
outlays by the company. In 2005 and 2004, expenditures were
$11.1 billion and $8.3 billion, respectively,
including the company’s share of affiliates’
expenditures of $1.7 billion and $1.6 billion in the
corresponding periods. The 2005 amount excludes the
$17.3 billion acquisition of Unocal.
Of the $16.6 billion in expenditures for 2006,
77 percent, or $12.8 billion, related to upstream
activities. Approximately the same percentage was also expended
for upstream operations in 2005 and 2004. International upstream
accounted for about 70 percent of the worldwide upstream
investment in each of the three years, reflecting the
company’s continuing focus on opportunities that are
available outside the United States.
In 2007, the company estimates capital and exploratory
expenditures will be 18 percent higher at
$19.6 billion, including $2.4 billion of spending by
affiliates. About three-fourths, or $14.6 billion, is
budgeted for exploration and production activities, with
$10.6 billion of that amount outside the United States.
Refer also to a discussion of the company’s capital and
exploratory expenditures on
page FS-13
of this Annual Report on
Form 10-K.
The table on the following page summarizes the net production of
liquids and natural gas for 2006 and 2005 by the company and its
affiliates.
Table of Contents
Net
Production1
of Crude Oil and Natural Gas Liquids and Natural Gas
Table of Contents
In 2006, Chevron conducted exploration and production operations
in the United States and approximately 35 other countries.
Worldwide oil-equivalent production of 2.67 million barrels
per day in 2006, including volumes produced from oil sands in
Canada and production under the Boscan operating service
agreement in Venezuela, increased approximately 6 percent
from 2005. The increase between periods was mostly attributable
to the Unocal acquisition. Refer to the “Results of
Operations” section beginning on
page FS-6
for a detailed discussion of the factors explaining the
2004–2006 changes in production for crude oil and natural
gas liquids and natural gas.
The company estimates that its average worldwide oil-equivalent
production in 2007 will be approximately 2.6 million
barrels per day. This estimate is subject to many uncertainties,
including quotas that may be imposed by OPEC, the price effect
on production volumes calculated under cost-recovery and
variable-royalty provisions of certain contracts, changes in
fiscal terms or restrictions on scope of company operations, and
production that may have to be shut in due to weather
conditions, civil unrest, changing geopolitics or other
disruptions to daily operations. Future production levels also
are affected by the size and number of economic investment
opportunities and, for new large-scale projects, the time lag
between initial exploration and the beginning of production.
Expected additions to production capacity in 2008 through 2010
may permit worldwide oil-equivalent production levels to
increase from 2007 levels. 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 oil and gas development projects.
Refer to Table IV on
page FS-68
of this Annual Report on
Form 10-K
for data about the company’s average sales price per unit
of crude oil and natural gas produced as well as the average
production cost per unit for 2006, 2005 and 2004.
The following table summarizes gross and net productive wells at
year-end 2006 for the company and its affiliates:
Productive
Oil and Gas
Wells1
at December 31, 2006
Table V, beginning on
page FS-68,
provides a tabulation of the company’s proved net oil and
gas reserves, by geographic area, as of each year-end 2004
through 2006 and an accompanying discussion of major changes to
proved
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reserves by geographic area for the three-year period. During
2006, the company provided oil and gas reserves estimates for
2005 to the Department of Energy, Energy Information Agency.
Such estimates are consistent with, and do not differ more than
5 percent from, the information furnished to the Securities
and Exchange Commission on the company’s Annual Report on
Form 10-K.
During 2007, the company will file estimates of oil and gas
reserves with the Department of Energy, Energy Information
Agency, consistent with the reserve data reported in
Table V.
At December 31, 2006, the company owned or had under lease
or similar agreements undeveloped and developed oil and gas
properties located throughout the world. The geographical
distribution of the company’s acreage is shown in the
following table.
Acreage1
at December 31, 2006
(Thousands of Acres)
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 certain natural gas
sales contracts specify delivery of fixed and determinable
quantities.
In the United States, the company is contractually committed to
deliver to third parties and affiliates approximately
281 billion cubic feet of natural gas through 2009 from
U.S. reserves. The company believes it can satisfy these
contracts from quantities available from production of the
company’s proved developed U.S. reserves. These
contracts include variable-pricing terms.
Outside the United States, the company is contractually
committed to deliver to third parties a total of approximately
560 billion cubic feet of natural gas from 2007 through
2009 from Argentina, Australia, Canada, Colombia and the
Philippines. The sales contracts contain variable pricing
formulas that are generally referenced to the prevailing market
price for crude oil, natural gas or other petroleum products at
the time of delivery and in some cases consider inflation or
other factors. The company believes it can satisfy these
contracts from quantities available from
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production of the company’s proved developed reserves in
Argentina, Australia, Colombia and the Philippines. The company
plans to meet its Canadian contractual delivery commitments of
27 billion cubic feet through third-party purchases.
Details of the company’s development expenditures and costs
of proved property acquisitions for 2006, 2005 and 2004 are
presented in Table I on
page FS-63
of this Annual Report on
Form 10-K.
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, 2006. 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
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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, 2006. “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
Details of the company’s exploration expenditures and costs
of unproved property acquisitions for 2006, 2005 and 2004 are
presented in Table I on
page FS-63
of this Annual Report on
Form 10-K.
Chevron’s 2006 key upstream activities, 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 below include references to
“total production” and “net production,”
which are defined under “Production” in
Exhibit 99.1 on
page E-11
of this Annual Report on
Form 10-K.
In addition to the activities discussed, Chevron was active in
other geographic areas, but those activities are considered less
significant.
The discussion below also references the status of proved
reserves recognition for significant long-lead-time projects not
yet on production and for projects recently placed on
production. Reserves are not discussed for recent discoveries
that have yet to advance to a project stage and for production
in mature areas.
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Upstream activities in the United States are concentrated in the
Gulf of Mexico, Louisiana, Texas, New Mexico, the Rocky
Mountains and California. Average daily net production during
2006 was 462,000 barrels of crude oil and natural gas
liquids and 1.8 billion cubic feet of natural gas, or
763,000 barrels per day on an oil-equivalent basis. Refer to
Table V beginning on
page FS-68
for a discussion of the net proved reserves and different
hydrocarbon characteristics for the company’s major
U.S. producing areas.
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In the Gulf of Mexico deepwater areas, the company’s
producing fields during 2006 included:
The company’s interests in the deepwater Typhoon and Boris
fields were sold during 2006. The production platform at Typhoon
capsized during Hurricane Rita in 2005 and was safely converted
into an artificial reef prior to the sale.
During 2006, Chevron was engaged in other development and
exploration activities in the deepwater Gulf of Mexico.
Development work continued at the 58 percent-owned and
operated Tahiti Field, where production
start-up is
expected in 2008. Development drilling commenced in February
2006, and well completion work is expected to be finalized
during 2007. Initial booking of proved undeveloped reserves
occurred in 2003, and the transfer of these reserves into the
proved developed category is anticipated near the time of
production
start-up.
With an estimated production life of 30 years, Tahiti is
designed to have a maximum total daily production of
125,000 barrels of crude oil and 70 million cubic feet
of natural gas.
At the 63 percent-owned and operated Blind Faith discovery,
a subsea development plan utilizing a semi-submersible
production system was approved by Chevron and its partner in
late 2005, at which time the company made its initial booking of
proved undeveloped reserves. Development drilling at Blind Faith
commenced in early 2007. Reclassification of the reserves to the
proved developed category is anticipated near the time of
production
start-up in
2008. Initial total daily production rates for the field are
estimated at 30,000 barrels of crude oil and 30 million
cubic feet of natural gas, thereafter rising to maximum rates of
40,000 barrels of crude oil and 35 million cubic feet
of natural gas. The expected production life of the field is
approximately 20 years.
In the fourth quarter 2006, the company announced its decision
to participate in the ultra-deep Perdido Regional Development in
the U.S. Gulf of Mexico. The development encompasses the
installation of a producing host facility designed to service
multiple fields, including Chevron’s 33 percent-owned
Great White, 60 percent-owned Silvertip and
58 percent-owned Tobago. Chevron has a 38 percent
interest in the Perdido Regional Host. All of these fields and
the production facility are partner-operated. First oil is
expected to occur by 2010, with the facility capable of handling
130,000 barrels of oil-equivalent per day. The
company’s initial booking of proved undeveloped reserves
occurred in 2006, and the phased reclassification of these
reserves to the proved developed category is anticipated near
the time of production
start-up.
The project has an expected life of approximately 25 years.
Exploration activities in 2006 included the announcement of a
discovery early in the year at the 60 percent-owned and
operated Big Foot prospect located in Walker Ridge
Block 29. A sidetrack well at Big Foot was completed
mid-year and encountered the same pay intervals as the discovery
well. Additional appraisal drilling is planned for the first
half of 2007.
At the 50 percent-owned and operated Jack discovery in
Walker Ridge Block 758, a successful extended production
flow test on the Jack #2 well was completed in
mid-2006. Additional appraisal drilling is scheduled for the
2007–2008 time frame. Data evaluation continued in early
2007 at the nearby 41 percent-owned and operated Saint Malo
prospect. Saint Malo was discovered in 2003, and an appraisal
well was completed in 2004. Future appraisal drilling is being
planned based on ongoing technical studies that are
incorporating additional regional data. At the
25 percent-owned and nonoperated 2005 Knotty Head
discovery, a successful sidetrack well was drilled during 2006.
Additional appraisal drilling and possible development
alternatives were being evaluated in early 2007. At the
30 percent-owned and nonoperated Tubular Bells prospect, an
appraisal well in 2006 successfully tested the eastern portion
of the reservoir structure. Additional appraisal work is being
planned to further delineate the reservoir and to evaluate
potential deeper targets. Plans were in progress in early 2007
at the 22 percent-owned and nonoperated Puma discovery to
complete an in-progress appraisal well and to schedule
additional appraisal drilling for 2007.
At the end of 2006, the company had not yet recognized proved
reserves for any of the exploration projects discussed above.
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Besides the activities connected with the development and
exploration projects in the Gulf of Mexico area, Chevron also
moved forward with the federal, state and local permitting
process for construction of a natural gas import terminal at
Casotte Landing in Jackson County, Mississippi. In February
2007, the company received approval from the Federal Energy
Regulatory Commission to construct the facility. The terminal
would be located adjacent to the company’s Pascagoula
Refinery and be designed to process imported liquefied natural
gas (LNG) for distribution to industrial, commercial and
residential customers in Mississippi, Florida and the Northeast.
The terminal would have an initial natural-gas processing
capacity of 1.3 billion cubic feet per day. A decision to
construct the facility will be timed to align with the
company’s LNG supply projects.
The company also has contractual rights to 1 billion cubic
feet per day of regasification capacity at the third party-owned
Sabine Pass LNG terminal beginning in 2009. Also in the Sabine
Pass area, the company has up to 1 billion cubic feet per
day of pipeline capacity in a new pipeline that will be
connected to the Sabine Pass LNG terminal. The new pipeline
system will provide access to Chevron’s Sabine and
Bridgeline pipelines, which connect to the Henry Hub.
Interconnect capacity of 600 million cubic feet per day has
also been secured to an existing pipeline. The Henry Hub is the
pricing point for natural gas futures contracts traded on the
New York Mercantile Exchange (NYMEX) and is located on the
natural gas pipeline system in Louisiana. Henry Hub
interconnects to nine interstate and four intrastate pipelines.
Other U.S. Areas: Outside California and the
Gulf of Mexico, the company manages operations in areas of the
midcontinent United States that extend from the Rockies to
southern Texas. In the Piceance Basin of northwestern Colorado,
the company drilled 14 tight-gas delineation wells during 2006
on the Skinner Ridge properties. Development drilling is
scheduled to begin in the second quarter 2007 with the delivery
of two custom-built drilling rigs. Chevron also operates 10
offshore platforms and five producing natural gas fields in
Alaska’s Cook Inlet and owns nonoperated production on the
North Slope. During 2006, the company’s operations outside
California and the Gulf of Mexico averaged daily net production
of 141,000 barrels of crude oil and natural gas liquids and
about 1 billion cubic feet of natural gas
(315,000 barrels of oil-equivalent).
b) Africa
In Area B of Block 0, average daily net production from six
producing fields was 52,000 barrels of crude oil and
condensate and 7,000 barrels of LPG in 2006. Included in
this production were 28,000 barrels of liquids per day from
the Sanha condensate natural gas utilization and Bomboco crude
oil project. Initial reclassification of reserves from proved
undeveloped to proved developed for this project occurred in
2004 and is expected to continue during the drilling program
that is scheduled for completion in 2007. Maximum total daily
production from the Sanha and Bomboco fields reached 100,000
barrels of liquids in 2006.
In Block 14, net production from the Kuito, Belize, Lobito
and Landana fields averaged 25,000 barrels of crude oil per
day in 2006. Belize and Lobito are part of the Benguela
Belize-Lobito Tomboco (BBLT) development project. Phase 1
of the BBLT project involved the installation of an integrated
drilling and production platform and the
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development of the Benguela and Belize fields. First oil was
produced at the Belize Field in January 2006. Phase 2 of
the project involved the installation of subsea production
systems, pipelines and wells for the development of Lobito and
Tomboco fields. First oil was produced from the Lobito Field in
June 2006. Maximum total production for both phases of BBLT is
estimated at 200,000 barrels of crude oil per day and is
scheduled to occur in 2008. Proved undeveloped reserves for
Benguela and Belize were initially recognized in 1998 and for
Lobito and Tomboco in 2000. Certain proved developed reserves
for Belize and Lobito were recognized in 2006, and additional
BBLT reserves are expected to be reclassified to proved
developed as project milestones are met. The concession period
for these fields expires in 2027.
Another major project in Block 14 is the development of the
Tombua and Landana fields. Construction on the project started
in 2006. The maximum total daily production of
100,000 barrels of crude oil is expected to occur by 2010.
First oil was produced from the Landana North reservoir in June
2006, using the BBLT infrastructure. Proved undeveloped reserves
were recognized for Tombua and Landana in 2001 and 2002,
respectively. Initial reclassification from proved undeveloped
to proved developed for Landana occurred in 2006. Further
reclassification is expected from 2009, when the
Tombua-Landana
facilities are completed, through 2012, when the drilling
program is scheduled for completion. The concession for these
fields expires in 2028. The total cost of the
Tombua-Landana
project is estimated at $3.8 billion.
Four exploration wells were drilled in Block 14 in 2006.
One well resulted in a crude oil discovery at the deepwater
Lucapa prospect. A second well appraised a prior-year discovery
at Gabela, where development options are being studied. The
remaining two wells are expected to be completed in the
first-half 2007.
In Chevron’s other two concessions, the nonoperated working
interests are 20 percent in Block 2, which is adjacent
to the northwestern part of Angola’s coast, south of the
Congo River, and 16 percent in the onshore FST area.
Combined net production from these properties in 2006 was
4,000 barrels of crude oil per day.
In addition to the producing activities in Angola, Chevron has a
36 percent interest in the planned Angola LNG project,
which will be integrated with natural gas production in the
area. As of early 2007, participants in the Angola LNG project
were finalizing the engineering, procurement, construction and
commissioning contract for the
5-million-metric-ton-per-year
onshore LNG plant to be located in the northern part of the
country. Chevron and Sonangol, Angola’s national oil
company, are co-leaders of the project. Construction is expected
to begin in late 2007. At the end of 2006, the company had not
yet recognized proved reserves for the natural gas associated
with this project.
Democratic Republic of the Congo: Chevron has an
18 percent nonoperated working interest in a
production-sharing contract (PSC) off the coast of Democratic
Republic of the Congo. Daily net production from seven fields
averaged 3,000 barrels of crude oil in 2006.
Republic of the Congo: Chevron has a 32 percent
nonoperated working interest in the Nkossa, Nsoko and
Moho-Bilondo exploitation permits and a 29 percent
nonoperated working interest in the Kitina and Sounda
exploitation permits, all of which are offshore Republic of the
Congo. Net production from the Republic of the Congo fields
averaged 11,000 barrels of crude oil per day in 2006. The
Moho-Bilondo development continued in 2006, with first
production expected in 2008. The development plan calls for
crude oil produced by subsea well clusters to flow into a
floating processing unit. Maximum total daily production of
80,000 barrels of crude oil is expected by 2010. Proved
undeveloped reserves were initially recognized in 2001. Transfer
to the proved developed category is expected near the time of
first production. The Moho-Bilondo concession expires in 2030.
Angola-Republic of the Congo Joint Development
Area: Chevron is operator and holds a 31 percent
interest in the 14K/A-IMI Unit, located in a joint development
area shared equally between Angola and Republic of the Congo. In
2006, Chevron submitted a conceptual field development plan to a
committee of representatives from the two countries.
Chad/Cameroon: Chevron is a nonoperating partner in
a project to develop crude oil fields in southern Chad and
transport the crude oil by pipeline to the coast of Cameroon for
export. Chevron has a 25 percent working interest in the
producing operations and a 21 percent interest in the
pipeline. Average daily net production from five fields in 2006
was 34,000 barrels of crude oil. The first of the
satellite-field development projects was completed in the first
quarter of 2006, and first oil was achieved in 2005 from the Nya
Field and in March 2006 from the Moundouli Field. The second
satellite-field development project, Maikeri, was approved for
funding in the second half of 2006, with first oil anticipated
for fourth quarter 2007. The Chad producing operations are
conducted under a concession agreement that expires in 2030.
Libya: In 2005, the company was awarded
Block 177 in Libya’s first exploration license round
under the Exploration and Production Sharing Agreement IV.
Chevron is the operator and holds a 100 percent interest in
the block.
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Acquisition and evaluation of seismic data is scheduled for
completion in late 2007. A drilling program is scheduled for
2008.
and OML 128. Agbami is designed as an all-subsea development,
with the wells tied back to a floating production, storage and
offloading (FPSO) vessel. The subsea wells will be connected to
the FPSO by a system of flexible flowlines, manifolds and
control umbilicals. All wells are to be drilled by a mobile
drilling unit. Development drilling and completion operations
were conducted throughout 2006.
During 2006, the Agbami development achieved the following major
milestones: the FPSO hull was floated out of drydock in South
Korea; topside modules fabricated in South Korea were installed
on the FPSO and modules fabricated in Nigeria were received at
the shipyard in South Korea. All other major equipment items
were shipped to South Korea for installation, and manufacturing
began on the equipment for the subsea wells. Completion of the
FPSO and subsequent transport to Nigeria are expected in the
fourth quarter 2007.
Agbami’s maximum total daily production of
250,000 barrels of crude oil and natural gas liquids is
expected to be reached within the first year after
start-up in
the second half 2008. The company initially recognized proved
undeveloped reserves for Agbami in 2002. A portion of the proved
undeveloped reserves will be reclassified to proved developed in
advance of production
start-up.
The expected field life is approximately 20 years.
For Chevron’s Aparo discovery in 2003 on OML 132 (formerly
Oil Prospecting License [OPL] 213), the company entered into a
joint-study agreement in 2004 with the partner group of the
Bonga SW Field in OML 118 (formerly OPL 212) for the
unitization and joint development of Aparo, which straddles OML
132 and OPL 249. Negotiation of final terms for a unitization
agreement for this development was ongoing as of early 2007.
Front-end engineering and design (FEED) continued through 2006,
and discussions were under way in early 2007 with potential
contractors. Development will likely involve an FPSO and subsea
wells. Partners are expected to make the investment decision
during 2007, with production
start-up
estimated to occur in 2011. Maximum total production of
150,000 barrels of crude oil per day is expected to be
reached within one year of production
start-up.
The company recognized initial proved undeveloped reserves in
2006 for its approximate 20 percent nonoperated working
interest in the unitized project.
The company holds a 30 percent nonoperated working interest
in the Usan project, located offshore in OPL 222. FEED for the
Usan Field continued through 2006 on a selected FPSO concept.
Technical tendering for the major contracts were under way as of
early 2007. Project partners expect to make the investment
decision during 2007. The company recognized proved undeveloped
reserves for the project in 2004. Production
start-up is
estimated for late 2011, before which time certain proved
undeveloped reserves are expected to be reclassified to the
proved developed category. Maximum total production of
180,000 barrels of crude oil per day is expected to be
achieved within one year of
start-up.
The end date of the concession period will be determined after
final regulatory approvals are obtained.
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Chevron operates and holds a 95 percent interest in the
2003 Nsiko discovery, also on OPL 249. Two successful appraisal
wells were drilled in 2004, with subsurface evaluations and
field development planning ongoing in early 2007. The company
expects FEED to begin in late 2007. Maximum total production of
100,000 barrels of oil per day is anticipated within one
year of initial
start-up,
targeted for 2012. At the end of 2006, no proved reserves had
been recognized for this project.
The Nnwa Field in OML 129 (formerly OPL 218) was discovered
in 1999 and extends into two adjacent non-Chevron leased blocks.
Chevron’s nonoperated working interest in OML 129 is
46 percent. A later discovery in OML 129 was made in the
Bilah Field. Commerciality of these fields is dependent upon
resolution of the Nigerian Deepwater Gas fiscal regime and
collaboration agreements with adjacent blocks. The Bilah Field
discovery was under evaluation in early 2007 for further
appraisal and the viability of a stand-alone condensate liquid
recovery scheme.
Chevron is a participant in the South Offshore Water Injection
Project, an enhanced crude-oil recovery project in the south
offshore area of OML 90. The company operates and holds a
40 percent interest as part of the joint venture with NNPC.
The objective of the project is to increase production by
providing water injection, natural-gas lift and production
debottlenecking in the South Offshore Asset Area (Okan and Delta
fields). The
25-year-life
project is in its development phase and by the end of 2006 was
contributing incremental production of approximately
7,000 net barrels of crude oil per day. Maximum total
production from this project is expected to be 35,000 barrels of
crude oil per day in 2010. The major project milestones expected
in 2007 include commencement of water injection from the new
Delta South Water Inject Platform facility, drilling of 10
additional wells and the installation of pipelines. Initial
recognition of proved developed and proved undeveloped reserves
was made in 2005. Reclassification of proved reserves to the
proved developed category is expected to occur after the
evaluation of the water injection performance.
In May 2006, the company announced the discovery of crude oil at
the Uge-1
well in the 20 percent-owned and nonoperated offshore OPL
214. Future drilling is contingent primarily on completing
technical studies.
Chevron is involved in projects in Nigeria that support the
company’s strategic initiative to commercialize its
significant natural gas resource base outside the United States.
Construction began in early 2006 on the Phase 3A expansion
of the Escravos Gas Plant (EGP). Engineering, procurement and
construction are expected to continue through 2007, with
start-up
targeted for early 2009. The scope of EGP Phase 3A includes
offshore natural gas gathering and compression infrastructure
and a second plant, which potentially would increase processing
capacity from 285 million to 680 million cubic feet of
natural gas per day and increase LPG and condensate export
capacity from 4,000 to 43,000 barrels per day. Proved
undeveloped reserves associated with EGP Phase 3A were
recognized in 2002. These reserves are expected to be
reclassified to proved developed as various project milestones
are reached and related projects are completed. The anticipated
life of the project is 25 years. Chevron holds a
40 percent operated interest in this project.
Refer also to page 25 for a discussion on the planned
gas-to-liquids
facility at Escravos.
Chevron holds a 38 percent interest in the West African Gas
Pipeline, which is expected to start up in the first-half 2007
and supply Nigerian natural gas to customers in Ghana, Benin and
Togo for industrial applications and power generation. A
350-mile
offshore segment of the West African Gas Pipeline connects to an
existing onshore pipeline in Nigeria. Chevron is the managing
sponsor in West African Pipeline Company Limited, which
constructed, owns and will operate the pipeline.
In February 2006, Chevron signed a Project Development Agreement
for a 19 percent nonoperated working interest in the
Olokola LNG Project, which involves construction of a
four-train,
22-million-metric-ton-per-year
natural gas liquefaction facility and marine terminal located in
a free trade zone between Lagos and Escravos. Chevron is
expected to supply approximately 1.8 billion cubic feet per
day of natural gas to the LNG plant. The project entered FEED in
the first quarter 2006. The partners’ investment decision
is scheduled for 2007, and initial production is targeted for
2012. The company had not recognized proved reserves for this
project at the end of 2006.
Nigeria-São Tomé e Príncipe Joint Development
Zone (JDZ): Chevron is the operator of JDZ Block 1
and holds a 46 percent interest following the sale of a
5 percent interest in 2006. In March 2006, the first
exploration well was completed and encountered hydrocarbons. In
early 2007, commercial options were being examined to determine
the possible need for additional drilling.
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c) Asia-Pacific
On Barrow and Thevenard islands off the northwest coast of
Australia, Chevron operates crude oil producing facilities that
had combined net production of 5,000 barrels per day in
2006. Chevron’s interest in this operation is
57 percent for Barrow Island and 51 percent for
Thevenard Island.
Also off the northwest coast of Australia, Chevron is the
operator of the Gorgon-area fields and has a 50 percent
ownership interest across most of the Greater Gorgon Area.
Chevron and its two joint-venture participants signed a
Framework Agreement in 2005 that will enable the combined
development of Gorgon and the nearby natural gas fields as one
world-scale project. In early 2007, progress continued toward
securing environmental regulatory approvals necessary for the
development of the Greater Gorgon LNG project on Barrow Island.
A two-train,
10-million-metric-ton-per-year
LNG development is planned for the island, with natural gas
supplied from the Gorgon and Jansz natural gas fields.
Elsewhere in the Greater Gorgon Area during 2006, concept
studies were undertaken on the
Wheatstone-1
natural gas discovery located northeast of the Gorgon Field.
Appraisal drilling is scheduled for 2007. The company also
announced in 2006 two significant natural gas discoveries at the
67 percent-owned Clio-1 and 50 percent-owned Chandon-1
exploration wells located offshore northwestern coast in the
Greater Gorgon development area. Additional work on these two
company-operated prospects includes a
3-D seismic
survey program that started in late 2006 to better determine the
potential of the natural gas find and subsequent development
options.
Chevron was also awarded exploration rights to Blocks WA-374-P
(Greater Gorgon Area) and WA-383-P (Exmouth West) in the
Carnarvon Basin offshore Western Australia. Chevron holds a
50 percent operated interest in the blocks. Operations
commenced in WA-374-P with the acquisition of
3-D seismic
data. On WA-383-P, a three-year work program includes
geotechnical studies and
2-D seismic
work. In early 2007, the company was also named operator and
awarded a 50 percent interest in exploration acreage in
Block W06-12 in the Greater Gorgon Area. A three-year work
program includes geotechnical studies, seismic surveys and
drilling of an exploration well.
At the end of 2006, the company had not recognized proved
reserves for any of the Greater Gorgon Area fields. Recognition
is contingent on securing sufficient LNG sales agreements and
achieving other key project milestones. The company has signed
separate nonbinding Heads of Agreements totaling
4.2 million metric tons per year with three companies in
Japan to supply LNG from the Gorgon project. As of early 2007,
negotiations were continuing to finalize binding sales
agreements. Purchases by each of these customers are expected to
range from 1.2 million metric tons per year to
1.5 million metric tons per year of LNG over 25 years
beginning after 2010.
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Kazakhstan: Chevron holds a 20 percent
nonoperated working interest in the Karachaganak project that is
being developed in phases. During 2006, Karachaganak daily net
production averaged 38,000 barrels of liquids and
143 million cubic feet of natural gas.
The Karachaganak operations are conducted under a
40-year
concession agreement that expires in 2038. In 2006, access to
the Caspian Pipeline Consortium (CPC) and Atyrau-Samara
pipelines allowed Karachaganak sales of approximately 143,000
barrels per day (27,000 net barrels) of processed liquids at
prices available in world markets. A fourth train was approved
in December 2006 that is designed to increase this export of
processed liquids by 56,000 barrels per day (11,000 net
barrels). The fourth train is expected to start up in 2009.
Phase III of Karachagnak field development is contingent
upon the Republic of Kazakhstan’s identifying and enabling
a commercially attractive outlet for the increased natural gas
volumes. Timing for the recognition of Phase III proved
reserves and an increase in production are uncertain, and both
depend on achieving a natural gas sales agreement and finalizing
a viable Phase III project design.
Refer also to page 23 for a discussion of Tengizchevroil, a
50 percent-owned affiliate with operations in Kazakhstan.
Russia: In 2005, OAO Gazprom, Russia’s largest
natural gas producer, included Chevron on a list of companies
that could continue discussions concerning the development and
related commercial activities of the Shtokmanovskoye Field, a
very large natural gas field offshore Russia in the Barents Sea.
In October 2006, OAO Gazprom issued a public statement
indicating its plan to develop Shtokmanovskoye without foreign
partners. Refer also to page 24 for a discussion of the
company’s interest in a Russian joint venture.
Bangladesh: Chevron is the operator of four onshore
blocks, with a 98 percent interest in Blocks 12, 13
and 14 and a 43 percent interest in Block 7. In 2006,
the properties averaged daily net production of 126 million
cubic feet of natural gas. Following a two-year development
program, production from the Bibiyana Field in Block 12 is
scheduled to start in the first-half 2007, reaching maximum
total production of 500 million cubic feet per day by late
2010. The development program includes a gas processing plant
with capacity of 600 million cubic feet per day and a
natural gas pipeline. Initial proved reserves were recognized in
2005. In 2006, additional proved reserves were recognized based
on additional development wells drilled during the year, and
certain proved undeveloped reserves were reclassified to the
proved developed category in recognition of imminent completion
of the gas plant and pipeline infrastructure required for
production
start-up.
The Bibiyana PSC expires in 2034.
17
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Thailand: Chevron has both operated and nonoperated
working interests in several different offshore blocks in
Thailand. The company’s daily net production averaged
73,000 barrels of crude oil and condensate and
856 million cubic feet of natural gas in 2006.
Operated interests include concessions with ownership interests
ranging from 35 percent to 80 percent in
Blocks 10 through 13 and B12/27, 52 percent-owned
Blocks B8/32 and 9A, 60 percent-owned G4/43 and
71 percent-owned G4/48.
In the concession containing Blocks 10 through 13 and
B12/27, debottlenecking of all central processing platforms was
completed, which is expected to add more than 160 million
cubic feet per day of natural gas processing capability. The
company anticipates this additional capacity will be used when
PTT Public Company Limited completes the third natural gas
pipeline to shore in 2007. In late 2007, the company expects to
complete the evaluation of a possible second natural gas central
processing facility in Platong to support a Heads of Agreement
signed in 2003 for additional natural gas sales to meet future
natural gas demands in Thailand. This Platong Gas II Project, in
which the company has a 70 percent interest, would add
330 million cubic feet per day of processing capacity in
the Platong area, which spans Blocks 10, 10A, 11 and 11A in
the Gulf of Thailand. The new facilities would include a central
processing platform, pipelines and five initial wellhead
platforms. First gas sales would occur in 2010. Proved reserves
would be recognized throughout the
12-year
project life as the required wellhead platforms are developed.
In Blocks B8/32 and 9A, crude oil is produced from six operating
areas within the Pattani Field. First production from Lanta area
in Block G4/43 is anticipated in the first-half 2007.
Chevron has a 16 percent nonoperated working interest in
Blocks 14A, 15A, 16A and G9/48, known collectively as the
Arthit Field. Development of Arthit is progressing with six
wellhead platforms installed and 41 wells drilled in 2006.
First production is planned for 2008.
In 2006, the company signed two exploration concessions, Blocks
G4/48 and G9/48. Two delineation wells are scheduled to be
drilled in Block G4/48 in 2007. One exploration well in Block
G9/48 is required to be drilled by the first quarter 2009. As of
early 2007, processing and interpretation of seismic data were
under way in Block G9/48. Chevron also holds exploration
interests in a number of blocks that are currently inactive,
pending resolution of border issues between Thailand and
Cambodia.
Vietnam: The company is operator in two PSCs
offshore southwest Vietnam in the northern part of the Malay
Basin. Chevron has a 42 percent interest in Blocks B and
48/95 and a 43 percent interest in Block 52/97. In
April 2006, the company signed a
30-year PSC
for Block 122 located offshore eastern Vietnam. The company
has a 50 percent operated interest in this block and has
undertaken a three-year work program for seismic acquisition and
drilling of an exploratory well.
In July 2006, the company submitted a revised summary
development plan to state-owned PetroVietnam for Blocks B, 48/95
and 52/97 for the Vietnam Gas Project. The final detailed
development plan is expected to be submitted in the third
quarter 2007, with FEED projected to begin by the end of 2007.
First natural gas production is targeted for 2011 but is
dependent on the progress of commercial negotiations. Maximum
total production of approximately 500 million cubic feet of
natural gas per day is projected within four years of the
production
start-up.
Recognition of initial proved reserves is expected to follow
execution of the gas sales agreements and anticipated project
sanction in 2008. Total development cost for the project is
approximately $3.5 billion.
18
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China: Chevron has a 33 percent nonoperated
working interest in Blocks 16/08 and 16/19 located in the
Pearl River Delta Mouth Basin, a 25 percent nonoperated
working interest in QHD-32-6 in Bohai Bay, and a 16 percent
nonoperated working interest in the unitized and producing
Bozhong 25-1
Field in Bohai Bay Block 11/19. Daily net production from
the company’s interests in China averaged
23,000 barrels of crude oil and condensate and
18 million cubic feet of natural gas in 2006. Production
during 2006 included first natural gas in January from the
HZ21-1 natural gas development project, located in
Block 16/08. Chevron also has interests ranging from
36 percent to 50 percent in four prospective onshore
natural gas blocks in the Ordos Basin totaling about
1.5 million acres.
Partitioned Neutral Zone (PNZ): Saudi Arabian
Chevron Inc., a Chevron subsidiary, holds a
60-year
concession that expires in 2009 to produce crude oil from
onshore properties in the PNZ, which is located between the
Kingdom of Saudi Arabia and the State of Kuwait. In September
2006, Chevron submitted to the Kingdom of Saudi Arabia a
proposal to extend the concession agreement. Under the current
concession, Chevron has the right to Saudi Arabia’s
50 percent undivided interest in the hydrocarbon resource
and pays a royalty and other taxes on volumes produced. During
2006, average daily net production was 111,000 barrels of
crude oil and 19 million cubic feet of natural gas.
Facilities for the first phase of a steamflood project were
completed in December 2005, and steam injection began in
February 2006. The success of the first phase has led to the
approval of funding for a second phase steamflood pilot project
that is expected to be completed by late 2008. This pilot is a
unique application of steam injection into a carbonate reservoir.
Philippines: The company holds a 45 percent
nonoperated working interest in the Malampaya natural gas field
located about 50 miles offshore Palawan Island. Daily net
production in 2006 was 108 million cubic feet of natural
gas and 6,000 barrels of condensate. Chevron also develops
and produces steam resources under an agreement with the
National Power Corporation, a Philippine government-owned
company. The combined generating capacity is 634 megawatts.
In North Duri, located in the Rokan PSC, development is
progressing on steamflood activity for the sequential
development of three possible expansion areas. The first
expansion involves the development of Area 12, in which the
company has a 100 percent interest, and is planned to come
onstream in 2008, with maximum total daily production estimated
at 34,000 barrels of crude oil in 2012. Proved undeveloped
reserves for North Duri were recognized in previous years, and
reclassification from proved undeveloped to proved developed
will occur during various stages of sequential project
completion.
A drilling campaign is scheduled to continue through 2007 in
South Natuna Sea Block B, with first oil from Kerisi Field
expected in late 2007. In 2006, the company executed a farm-out
agreement relinquishing five Indonesian PSCs in exchange for a
40 percent nonoperated working interest in the NE
Madura III Block.
In early 2007, the company submitted preliminary plans of
development to the government of Indonesia for the Bangka,
Gendalo Hub and Gehem Hub deepwater natural gas projects,
located in the Kutei Basin. These projects will
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likely be developed in parallel, with first production for all
projects targeted for 2013. The actual timing is partially
dependent on government approvals, market conditions and the
achievement of key project milestones.
The development concept for the 50 percent-owned and
operated Sadewa project, located in the Kutei Basin is under
evaluation and is expected to be completed in late 2007.
Assuming the evaluation is positive, initial proved reserves
recognition would be expected to occur in 2008, with first
production expected in 2010.
Daily net production from all producing areas in Indonesia
averaged 198,000 barrels of crude oil and 302 million
cubic feet of natural gas in 2006.
e) Other
International Areas
The company concentrates its exploration efforts in the Campos
and Santos basins. In the nonoperated Campos Basin Block BC-20,
two areas — 38 percent-owned Papa-Terra (formerly
RJS610) and 30 percent-owned RJS609 — have been
retained for development following the end of the exploration
phase of this block. In the Papa-Terra area, the appraisal phase
has been completed confirming hydrocarbons in three separate
reservoirs. In June 2006, a field development plan was submitted
to the government. FEED for the Papa-Terra Field is expected to
commence in late 2007 after completing an appraisal program
planned for mid-2007. In the RJS609 area, all appraisal drilling
was completed to fulfill requirements for a Declaration of
Commerciality that was filed in December 2006 for a new field,
designated Maromba. Elsewhere in Campos, the company holds a
30 percent nonoperated working interest in the
BM-C-4
Block, in which drilling of the final obligatory exploration
well began in October 2006. As of early 2007, drilling of the
Guarana prospect was ongoing, with completion and evaluation
expected to occur later in 2007. In the 20 percent-owned
and nonoperated Santos Basin BS-4 Block, the evaluation of an
exploration campaign was completed in 2006, with the Declaration
of Commerciality filed in December 2006 designating two new
fields, Atlanta and Oliva.
Colombia: The company operates three natural gas
fields in Colombia — the offshore Chuchupa and the
onshore Ballena and Riohacha. The fields are part of the Guajira
Association contract, a joint venture agreement that was
extended in 2003. At that time, additional proved reserves were
recognized. The company continues to operate the fields and
receives 43 percent of the production for the remaining
life of each field as well as a variable production volume from
a fixed-fee Build-Operate-Maintain-Transfer (BOMT) agreement
based on prior Chuchupa capital contributions. The BOMT
agreement expires in 2016. Net production averaged
174 million cubic feet of natural gas per day in 2006. New
production capacity was commissioned in 2006 and will help meet
the demand of the growing Colombian natural gas market.
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Trinidad and Tobago: The company has a
50 percent nonoperated working interest in four blocks in
offshore Trinidad, which include the Dolphin and Dolphin Deep
producing natural gas fields and the Starfish discovery. Net
natural gas production from Dolphin and Dolphin Deep in 2006
averaged 174 million cubic feet per day.
Natural gas supply to the Atlantic LNG Train 3 from the Dolphin
Field began in 2005. In July 2006, Chevron delivered the first
natural gas from the Dolphin Deep development to the Atlantic
LNG Train 3 and Train 4. The initial phase of the development
became fully operational during 2006 and supplied an average of
38 million net cubic feet of natural gas per day to Train 3
and 31 million net cubic feet of natural gas per day to
Train 4. Proved reserves associated with the Train 4 gas sales
agreement were recognized in 2004. Reserves associated with
Trains 3 and 4 were transferred to the proved developed category
in 2005. The contract period for Train 3 ends in 2023 and for
Train 4 in 2026.
Chevron also holds a 50 percent operated interest in the
Manatee area of Block 6d. After successful exploration
drilling results in 2005, the company assessed alternative
development strategies for the Loran Field in Venezuela and
Manatee area in 2006. As of early 2007, negotiations were in
progress between Trinidad and Tobago and Venezuela to unitize
the Loran and Manatee discoveries.
Venezuela: As of October 2006, the company’s
operations at the Boscan and LL-652 fields were converted to two
joint stock companies. From that date, these activities were
treated as affiliate operations and accounted for under the
equity method. Refer to page 23 for a further discussion of
these operations.
The company also has ongoing exploration activity in two blocks
offshore Plataforma Deltana, in which the company is operator
and holds a 60 percent interest. In Block 2, which
includes the Loran Field, evaluation and project development
work continued during 2006. In the 100 percent-owned and
operated Block 3, Chevron discovered natural gas in 2005.
The discovery is in close proximity to the Loran natural gas
field and provides significant resources that will be included
in the detailed evaluation as a potential gas supply source for
Venezuela’s first LNG train. Seismic work elsewhere in
Block 3 started in 2006. Chevron also has 100 percent
interest in the Cardon III exploration block, located
offshore western Venezuela north of the Maracaibo producing
region. Seismic work in this block, which has natural gas
potential, is planned for 2007.
Refer also to page 23 for a discussion of the Hamaca heavy
oil production and upgrading project in Venezuela.
Canada: The company’s assets in Canada include
a 27 percent nonoperated working interest in the Hibernia
Field offshore eastern Canada, a 20 percent nonoperated
working interest in the Athabasca Oil Sands Project (AOSP) and
exploration acreage in the Mackenzie Delta and Orphan Basin.
Excluding volumes mined at the AOSP, daily net production in
2006 from the company’s Canadian operations was
46,000 barrels of crude oil and natural gas liquids and
6 million cubic feet of natural gas. The company also owns
a 28 percent operated interest in the Hebron project
offshore eastern Canada. Negotiations with the government of
Newfoundland and Labrador on commercial terms for the
development of the field were suspended in April 2006, and the
project team was demobilized. The timing for a possible
resumption of negotiations was uncertain as of early 2007.
At the AOSP, which began operations in 2003, bitumen is mined
from oil sands and upgraded into synthetic crude oil using
hydroprocessing technology. Chevron’s share of bitumen
production in 2006 averaged 27,000 barrels per day.
In 2006, the company elected to participate in the first phase
of expansion of the AOSP. The expansion is being designed to
produce approximately 100,000 barrels of bitumen per day
(20,000 net barrels) and upgrade it into synthetic crude
oil at an estimated total cost of $10 billion. The
expansion will increase total AOSP design capacity to
approximately 255,000 barrels of bitumen per day by 2010.
This phase of expansion includes the construction of mining and
extraction facilities at the Jackpine Mine, for which net proved
undeveloped oil sands reserves were recorded in 2006.
Net proved oil sands reserves at the end of 2006 were
443 million barrels, increasing from 2005 primarily due to
the addition of reserves for the Jackpine Mine and proved
developed oil sands reserves for the Muskeg River Mine.
Securities and Exchange Commission regulations define these
reserves as mining-related and not a part of conventional oil
and gas reserves.
Chevron also holds a 60 percent operated interest in the
Ells River “In Situ” Oil Sands Project in the
Athabasca region. This project consists of heavy oil leases of
more than 75,000 acres that were acquired in 2005 and 2006.
The area contains significant volumes with the potential for
recovery using Steam Assisted Gravity Drainage, a proven
technology that employs steam and horizontal drilling to extract
the bitumen through wells rather than through mining operations.
Initial drilling began in January 2007.
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Norway: At the 8 percent-owned and nonoperated
Draugen Field, the company’s share of production during
2006 was 6,000 barrels of crude oil per day. In the
30 percent-owned and nonoperated PL 324 Field, the first
exploration well is planned for the first-half 2007. In the
40 percent-owned and operated PL 325, seismic data was
acquired in 2006. Pending the results of the ongoing seismic
processing, a first exploration well is planned for 2008. At PL
283, in which Chevron holds a 25 percent nonoperated
working interest, an exploration well that tested natural gas in
the Stetind prospect in 2006 will be followed by another
exploration well in mid-2007.
Through an Area of Mutual Interest with a partner in the Barents
Sea, Chevron was awarded a 40 percent nonoperated working
interest in PL 397 in April 2006, encompassing six blocks
located in the Nordkapp East Basin. A
3-D seismic
survey was acquired and is planned to be processed in 2007.
United Kingdom: Offshore United Kingdom, the
company’s daily net production in 2006 from nine fields was
75,000 barrels of crude oil and 242 million cubic feet
of natural gas. Of this volume, daily net production from the
85 percent-owned and operated Captain Field was
37,000 barrels of crude oil and from the co-operated and
32 percent-owned Britannia Field was 5,000 barrels of crude
oil and 138 million cubic feet of natural gas. In December
2006, Chevron exchanged interests in the nonproducing North Sea
Blocks 16/22 and 16/23 for an additional 2 percent
interest in the Chevron-operated Alba Field, raising the
company’s total interest to 23 percent. Daily net
production from this field averaged 11,000 barrels of crude
oil in 2006.
As of early 2007, development activities were continuing at the
Britannia satellite fields Callanish and Brodgar, in which
Chevron holds 17 percent and 25 percent nonoperated
working interests, respectively. A new platform and all subsea
equipment and pipelines were installed in 2006. Production
start-up
from these two satellite fields is expected to occur in 2008.
Together, these fields are expected to achieve maximum total
daily production of 25,000 barrels of crude oil and
133 million cubic feet of natural gas several months after
both fields start up. Proved undeveloped reserves were initially
recognized in 2000. In 2006, proved undeveloped reserves were
reclassified to the proved developed category. This project has
an expected production life of approximately 15 years.
Production
start-up
occurred in June 2006 at the Area C project in the eastern
portion of the Captain Field. The project included the
installation of subsea infrastructure and the drilling of two
new subsea wells. Maximum total production of
14,000 barrels of crude oil per day was achieved in
September 2006. Initial proved undeveloped reserves were booked
in 2004 and were reclassified as proved developed in 2006
following completion of development drilling. Further additions
to proved reserves are expected to occur as the field matures.
The Alder discovery, west of the Britannia Field, is being
evaluated and likely to be developed as a tieback to existing
infrastructure. The company has a 70 percent operated
interest in the project, which is expected to start up and reach
maximum total daily production rates of 9,000 barrels of
crude oil and 80 million cubic feet of natural gas in 2011.
No proved reserves had been recognized as of year-end 2006.
22
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In late 2006, the first well in a three-well program began
drilling to evaluate the commercial potential of the
Rosebank/Lochnagar discovery and adjacent acreage.
In early 2007, Chevron was awarded eight operated exploration
blocks and two nonoperated blocks west of Shetland Islands in
the 24th United Kingdom Offshore Licensing Round.
Kazakhstan: The company holds a 50 percent
interest in Tengizchevroil (TCO), which is developing the Tengiz
and Korolev crude oil fields located in western Kazakhstan under
a 40-year
concession that expires in 2033. Chevron’s share of daily
net production in 2006 averaged 135,000 barrels of crude
oil and natural gas liquids and 193 million cubic feet of
natural gas.
TCO is undergoing a significant expansion composed of two
integrated projects referred to as the Second Generation Plant
(SGP) and Sour Gas Injection (SGI). At a total combined
cost of approximately $6 billion, these projects are
designed to increase TCO’s crude oil production capacity
from 300,000 barrels per day to between 460,000 and
550,000 barrels per day in 2008. The actual production
level within the estimated range is dependent partially on the
effects of the SGI, which are discussed below. The
start-up of
the SGP/SGI project is expected in 2007.
SGP involves the construction of a large processing train for
treating crude oil and the associated sour gas (i.e., high in
sulfur content). The SGP design is based on the same
conventional technology employed in the existing processing
trains. Proved undeveloped reserves associated with SGP were
recognized in 2001. During 2006, 55 wells were drilled,
deepened
and/or
completed in the Tengiz and Korolev reservoirs to generate
volumes required for the new SGP train, and reserves associated
with the project were reclassified to the proved developed
category. Over the next decade, ongoing field development is
expected to result in the reclassification of additional proved
undeveloped reserves to proved developed.
SGI involves taking a portion of the sour gas separated from the
crude oil production at the SGP processing train and reinjecting
it into the Tengiz reservoir. Chevron expects that SGI will have
two key effects. First, SGI will reduce the sour gas processing
capacity required at SGP, thereby increasing liquid production
capacity and lowering the quantities of sulfur and gas that
would otherwise be generated. Second, it is expected that over
time SGI will increase production efficiency and recoverable
volumes as the injected gas maintains higher reservoir pressure
and displaces oil toward producing wells. Between 2007 and 2008,
the company anticipates recognizing additional proved reserves
associated with the SGI expansion. The primary SGI risks include
uncertainties about compressor performance associated with
injecting high-pressure sour gas and subsurface responses to
injection.
Essentially all of TCO’s production is 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. CPC is seeking stockholder
approval for an expansion to accommodate increased TCO volumes
beginning in 2009. During 2006, TCO continued the construction
of expanded rail car loading and rail export facilities, which
is expected to be completed by third quarter 2007. As of early
2007, other alternatives were also being explored to increase
export capacity prior to expansion of the CPC pipeline.
Venezuela: Chevron has a 30 percent interest in
the Hamaca heavy oil production and upgrading project located in
Venezuela’s Orinoco Belt. The crude oil upgrading began in
late 2004. In 2005, the facility reached total design capacity
of processing and upgrading 190,000 barrels per day of
heavy crude oil (8.5 degrees API gravity) into
180,000 barrels of lighter, higher-value crude oil (26
degrees API gravity). In 2006, daily net production averaged
36,000 barrels of liquids and 8 million cubic feet of
natural gas. In late February 2007, the President of Venezuela
issued a decree announcing the government’s intention for
the state-owned oil company, Petróleos de Venezuela
S.A., to increase its ownership later this year in all Orinoco
Heavy Oil Associations, including Chevron’s
30 percent-owned Hamaca project, to a minimum of
60 percent. The impact on Chevron from such an action is
uncertain but is not expected to have a material effect on the
company’s results of operations, consolidated financial
position or liquidity.
The company operated the onshore Boscan Field for 10 years
under an operating service agreement with Petróleos de
Venezuela S.A. In October 2006, the contract was converted into
a joint stock company, Petroboscan, in which Chevron is a
39 percent owner. At the same time, operatorship was
transferred from Chevron to Petroboscan. No proved reserves had
been recognized under the operating service agreement, but
proved reserves associated with this new
20-year
production contract were recorded in 2006. Under the operating
service agreement, Boscan had average net production of 109,000
oil-equivalent barrels per day for the first nine months of
2006. Net production for the final three months of 2006 under
the joint stock company was 30,000 oil-equivalent barrels per
day.
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The company operated the LL-652 Field for eight years under a
risked-service agreement with a 63 percent interest until
the contract was converted in October 2006 to a
25 percent-owned joint stock company, Petroindependiente.
Under the new contract, Petroindependiente is the operator
during the
20-year
contract period. Located in Lake Maracaibo,
LL-652’s
net production averaged 3,000 barrels of liquids per day
and 25 million cubic feet of natural gas per day during
2006. Chevron had previously booked reserves for LL-652 under
the risked-service agreement.
Russia: In October 2006, Chevron signed a framework
agreement with OAO Gazpromneft, establishing a Russian joint
venture for exploration and development activities focused in
the Yamal-Nenets region of Western Siberia. Chevron will
maintain a 49 percent joint-operated interest in the
venture. Refer to page 17 for a discussion of the
company’s other activities in Russia.
The company sells natural gas and natural gas liquids from its
producing operations under a variety of contractual
arrangements. Outside the United States, the majority of the
company’s natural gas sales occur in Australia, Indonesia,
Latin America, Thailand and the United Kingdom and in the
company’s affiliate operations in Kazakhstan. International
natural gas liquids sales take place in Africa, Australia and
Europe. 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 natural gas and natural gas liquids sales
volumes. Refer also to “Contract Obligations” on
page 7 for information related to the company’s
contractual commitments for the sale of crude oil and natural
gas.
Downstream —
Refining, Marketing and Transportation
At the end of 2006, the company’s refining system consisted
of 20 fuel refineries and an asphalt plant. The company operated
nine of these facilities, and 12 were operated by affiliated
companies.
The daily refinery inputs for 2004 through 2006 for the company
and affiliate refineries are as follows:
Petroleum
Refineries: Locations, Capacities and Inputs
(Inputs and Capacities in Thousands of Barrels per Day)
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Average crude oil distillation capacity utilization during 2006
was 90 percent, compared with 86 percent in 2005. In
general, this increase resulted from less planned and unplanned
downtime in 2006, due partly to downtime in 2005 that was
attributable to hurricanes in the U.S. Gulf of Mexico. No
downtime was caused by hurricanes in 2006. At the U.S. fuel
refineries, crude oil distillation capacity utilization averaged
99 percent in 2006, compared with 90 percent in 2005,
and cracking and coking capacity utilization averaged
86 percent and 76 percent in 2006 and 2005,
respectively. Cracking and coking units, including fluid
catalytic cracking units, are the primary facilities used in
fuel refineries to convert heavier products into gasoline and
other light products.
The company’s U.S. West Coast, Gulf Coast and Salt
Lake refineries produce low-sulfur fuels that meet 2006 federal
government specifications. Investments required to produce
low-sulfur fuels in Europe, Canada, South Africa and Australia
were completed in 2006. The company is evaluating alternatives
for clean-fuel projects in its Southeast Asia refineries.
In 2006, the company completed an expansion of the Pascagoula,
Mississippi, refinery’s Fluid Catalytic Cracking Unit to
increase the production of gasoline and other light products. In
addition, construction projects began at the El Segundo,
California, refinery to increase heavy, sour crude oil
processing capability and at the Pembroke, United Kingdom,
refinery to increase the capability to process Caspian-blend
crude oils. Completion of these projects is expected in 2007.
Additional projects to upgrade the company’s refineries in
Mississippi and California were being evaluated in early 2007.
Also in 2006, GS Caltex, the company’s
50 percent-owned affiliate, began construction of an
upgrade project at the
650,000-barrel-per-day
Yeosu refining complex in South Korea. At a total estimated cost
of $1.5 billion, this project is designed to increase the
yield of high-value refined products and reduce feedstock costs
through the processing of heavy crude oil. Completion of the
Yeosu project is expected in late 2007.
In April 2006, Chevron purchased a 5 percent interest in
Reliance Petroleum Limited, a company formed by Reliance
Industries Limited to own and operate a new export refinery
being constructed in Jamnagar, India. The
580,000-barrel-per-day-crude-oil-capacity
refinery is expected to begin operation in December 2008.
Chevron has future rights to increase its equity ownership to
29 percent. The new refinery would be the world’s
sixth largest on a single site.
Refer to
page FS-2
for a discussion of the pending disposition of the
company’s 31 percent interest in the Nerefco Refinery
in the Netherlands.
Chevron processes imported and domestic crude oil in its
U.S. refining operations. Imported crude oil accounted for
about 87 percent and 83 percent of Chevron’s
U.S. refinery inputs in 2006 and 2005, respectively.
The Sasol Chevron Global
50-50 Joint
Venture was established in 2000 to develop a worldwide
gas-to-liquids
(GTL) business. Through this venture, the company is pursuing
GTL opportunities in Qatar and other countries.
In Nigeria, Chevron Nigeria Limited and the Nigerian National
Petroleum Corporation are developing a
34,000-barrel-per-day
GTL facility at Escravos that will process natural gas supplied
from the Phase 3A expansion of the Escravos Gas Plant
(EGP). Plant construction began in 2005, and the first process
modules are expected to be delivered to the site by the second
half of 2007. The GTL plant is expected to be operational by the
end of the decade. Refer also to page 15 for a discussion
on the EGP Phase 3A expansion.
The company markets petroleum products throughout much of the
world. The principal brands for identifying these products are
“Chevron,” “Texaco” and “Caltex.”
The table on the following page shows the company’s and
affiliates’ refined products sales volumes, excluding
intercompany sales, for the three years ending December 31,
2006.
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Refined
Products Sales
Volumes1
(Thousands of Barrels per Day)
In the United States, the company markets under the Chevron and
Texaco brands. The company supplies directly or through
retailers and marketers almost 9,600 branded motor vehicle
retail outlets, concentrated in the mid-Atlantic, southern and
western states. Approximately 600 of the outlets are
company-owned or -leased stations. By the end of 2006, the
company was supplying more than 2,100 Texaco retail sites,
primarily in the Southeast and West. All rights to the Texaco
brand in the United States reverted to Chevron in July 2006.
Outside the United States, Chevron supplies directly or through
retailers and marketers approximately 16,200 branded service
stations, including affiliates, in about 75 countries. In
British Columbia, Canada, the company markets under the Chevron
brand. In Europe, the company has marketing operations under the
Texaco brand primarily in the United Kingdom, Ireland, the
Netherlands, Belgium and Luxembourg. In West Africa, the company
operates or leases to retailers in Benin, Cameroon, Côte
d’Ivoire, Nigeria, Republic of the Congo and Togo. In these
countries, the company uses the Texaco brand. The company also
operates across the Caribbean, Central America and South
America, with a significant presence in Brazil, using the Texaco
brand. In the Asia-Pacific region, southern, Central and East
Africa, Egypt, and Pakistan, the company uses the Caltex brand.
The company also operates through affiliates under various brand
names. In South Korea, the company operates through its
50 percent-owned affiliate, GS Caltex, using the GS Caltex
brand. The company’s 50 percent-owned affiliate in
Australia operates using the Caltex, Caltex Woolworths and Ampol
brands. In Scandinavia, the company sold its 50 percent
interest in the HydroTexaco joint venture in 2006.
The company continued the marketing and sale of service station
sites, focusing on selected areas outside the United States. In
2006, the company sold its interest in more than 450 service
stations, primarily in the United Kingdom and Latin America.
Since the beginning of 2003, the company has sold its interests
in nearly 2,800 service station sites. The vast majority of
these sites will continue to market company-branded gasoline
through new supply agreements.
The company also manages other marketing businesses globally.
Chevron markets aviation fuel in approximately
75 countries, representing a worldwide market share of
about 12 percent, and is the leading marketer of jet fuels
in the United States. The company also markets an extensive line
of lubricant and coolant products in about 175 countries under
brand names that include Havoline, Delo, Ursa and Revtex.
Refer to
page FS-2
for a discussion of the possible disposition of the
company’s fuels marketing operations in the Netherlands,
Belgium and Luxembourg regions.
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Pipelines: Chevron owns and operates an extensive
system of crude oil, refined products, chemicals, natural gas
liquids and natural gas pipelines in the United States. The
company also has direct or indirect interests in other U.S. and
international pipelines. The company’s ownership interests
in pipelines are summarized in the following table.
In the United States during 2006, the company completed the sale
of three refined-product pipeline systems in Texas and New
Mexico as well as its interest in the Windy Hill natural gas
storage project in northeastern Colorado. By year-end 2006, work
to restore the company’s Empire Terminal in Louisiana,
which was damaged in the 2005 hurricanes, was substantially
complete. During 2006, the company began a project to expand
capacity at its Keystone natural gas storage facility by about
3 billion cubic feet to meet increased demand in the
Permian Basin production region near the Waha Hub. The Waha Hub
is a pricing point for natural-gas-basis swap-futures contracts
traded on the New York Mercantile Exchange (NYMEX) and is
located in West Texas south of the natural gas deposits in the
San Juan and Permian Basins.
Chevron also has a 15 percent ownership interest in the
Caspian Pipeline Consortium (CPC). CPC operates a crude oil
export pipeline from the Tengiz Field in Kazakhstan to the
Russian Black Sea port of Novorossiysk. At the end of 2006, CPC
had transported an average of 664,000 barrels of crude oil
per day, including 519,000 barrels per day from the Caspian
region and 145,000 barrels per day from Russia.
In addition, the company has a 9 percent equity interest in
the Baku-Tbilisi-Ceyhan (BTC) pipeline, which transports
Azerbaijan International Operating Company (AIOC) production
from Baku, Azerbaijan, through Georgia to deepwater port
facilities in Ceyhan, Turkey. Chevron holds a 10 percent
nonoperated working interest in AIOC. The first tanker loading
at the Ceyhan marine terminal on the Mediterranean Sea occurred
in June 2006. The pipeline has a crude oil capacity of
1 million barrels per day and is expected to accommodate
the majority of the AIOC production. Another crude oil
production export route is the
515-mile
Baku-Supsa pipeline, wholly owned by AIOC, with crude oil
capacity to transport 145,000 barrels per day from Baku,
Azerbaijan, to the terminal at Supsa, Georgia.
For information on projects under way related to the
Chad/Cameroon pipeline, the West African Gas Pipeline and the
expansion of the CPC pipeline, refer to pages 13, 15
and 23, respectively.
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Tankers: At any given time during 2006, the company
had approximately 70 vessels chartered on a voyage basis or
for a period of less than one year. Additionally, all tankers in
Chevron’s controlled seagoing fleet were utilized during
2006. The following table summarizes cargo transported on the
company’s controlled fleet.
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. At year-end 2006, the company’s
U.S. flag fleet was engaged primarily in transporting
refined products between the Gulf Coast and the East Coast and
from California refineries to terminals on the West Coast and in
Alaska and Hawaii. During the year, the company contracted for
the building of four U.S. flagged product tankers, each
capable of carrying 300,000 barrels of cargo. These tankers
are scheduled for delivery from 2007 through 2010 and are
intended to replace the existing three U.S. flag ships.
The international flag vessels were engaged primarily in
transporting crude oil from the Middle East, Asia, Black Sea,
Mexico and West Africa to ports in the United States, Europe,
Australia and Asia. Refined products were also transported by
tanker worldwide. During 2006, the company took delivery of two
new double-hulled tankers with a total capacity of
2.5 million barrels and terminated the lease on its last
single-hulled vessel.
In addition to the vessels described above, the company owns a
one-sixth interest in each of seven liquefied natural gas (LNG)
tankers transporting cargoes for the North West Shelf (NWS)
project in Australia. Additionally, the NWS project has two LNG
tankers under long-term time charter. In 2005, Chevron placed
orders for two additional LNG tankers to support expected growth
in the company’s LNG business. These carriers are planned
to be delivered in 2009.
The Federal Oil Pollution Act of 1990 requires the scheduled
phase-out by year-end 2010 of all single-hull tankers trading to
U.S. ports or transferring cargo in waters within the
U.S. Exclusive Economic Zone. This has raised the demand
for double-hull tankers. At the end of 2006, 100 percent of
the company’s owned and bareboat-chartered fleet was
double-hulled. The company is a member of many
oil-spill-response cooperatives in areas around the world in
which it operates.
Chevron Phillips Chemical Company LLC (CPChem) is equally owned
with ConocoPhillips Corporation. At the end of 2006, CPChem
owned or had joint venture interests in 30 manufacturing
facilities and six research and technical centers in the United
States, Puerto Rico, Belgium, China, Saudi Arabia, Singapore,
South Korea and Qatar.
In 2006, construction progressed on CPChem’s integrated,
world-scale styrene facility in Al Jubail, Saudi Arabia. Jointly
owned with the Saudi Industrial Investment Group (SIIG), the
project’s operational
start-up is
anticipated in late 2007. The styrene facility is located
adjacent to CPChem and SIIG’s existing aromatics complex in
Al Jubail. Also during the year, CPChem continued development of
plans for a third petrochemical project in Al Jubail.
Preliminary studies are focused on the construction of a
world-scale olefins unit, as well as related downstream units,
to produce polyethylene, polypropylene, 1-hexene and polystyrene.
In addition, construction continued on the Q-Chem II
project in 2006. The Q-Chem II project includes a
350,000-metric-ton-per-year polyethylene plant and a
345,000-metric-ton-per-year normal alpha olefins
plant — each utilizing CPChem proprietary
technology — and is located adjacent to the existing
Q-Chem I complex in Mesaieed, Qatar. The
Q-Chem II
project also includes a separate joint venture to develop a
1.3-million-metric-ton-per-year
ethylene cracker at Qatar’s Ras Laffan Industrial City, in
which Q-Chem II owns 54 percent of the capacity
rights. CPChem and its partners expect to start up the plants in
early 2009. CPChem owns a 49 percent interest in
Q-Chem II.
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Chevron’s Oronite brand fuel and lubricant additives
business is a leading developer, manufacturer and marketer of
performance additives for fuels and lubricating oils. The
company owns and operates facilities in the United States,
Brazil, France, Japan, the Netherlands and Singapore and has
equity interests in facilities in India and Mexico.
Oronite provides additives for lubricating oil in most engine
applications, such as passenger car, heavy-duty diesel, marine,
locomotive and motorcycle engines, and additives for fuels to
improve engine performance and extend engine life.
Other
Businesses
Chevron’s mining companies in the United States produce and
market coal, molybdenum, rare earth minerals and calcined
petroleum coke. Sales occur in both U.S. and international
markets.
The company’s coal mining and marketing subsidiary, The
Pittsburg & Midway Coal Mining Co. (P&M), owns and
operates two surface mines, McKinley, in New Mexico, and
Kemmerer, in Wyoming, and one underground mine, North River, in
Alabama. Sales of coal from P&M’s wholly owned mines
were 12.6 million tons, down 1.0 million tons from
2005. Final reclamation activities continued in 2006 at the
Farco surface mine in Texas.
At year-end 2006, P&M controlled approximately
225 million tons of proven and probable coal reserves in
the United States, including reserves of environmentally
desirable low-sulfur coal. The company is contractually
committed to deliver between 11 million and 12 million
tons of coal per year through the end of 2009 and believes it
will satisfy these contracts from existing coal reserves.
Molycorp Inc. is the company’s mining and marketing
subsidiary for molybdenum and rare earth minerals. Molycorp owns
and operates the Questa molybdenum mine in New Mexico and the
Mountain Pass lanthanides mine in California. In addition, the
company owns a 33 percent interest in Sumikin Molycorp, a
manufacturer of neodymium compounds, located in Japan. During
2006, Molycorp performed environmental remediation activities at
Questa and Mountain Pass, and at its closed rare-earth
processing facility in Pennsylvania. The company’s
35 percent interest in Companhia Brasileira de Metalurgia e
Mineracao, a producer of niobium in Brazil, was sold in 2006.
At year-end 2006, Molycorp controlled approximately
60 million pounds of proven molybdenum reserves at Questa
and 240 million pounds of proven and probable lanthanide
reserves at Mountain Pass.
The company also owns the Chicago Carbon Company, a producer and
marketer of calcined petroleum coke, which operates a
250,000-ton-per-year petroleum coke calciner facility in Lemont,
Illinois.
Chevron’s Global Power Generation (GPG) business has more
than 20 years experience in developing and operating
commercial power projects and owns 15 power assets located in
the United States and Asia. GPG manages the production of more
than 2,334 megawatts of electricity at 11 facilities it owns
through joint ventures. The company operates gas-fired
cogeneration facilities that use waste heat recovery to produce
additional electricity or to support industrial thermal hosts. A
number of the facilities produce steam for use in upstream
operations to facilitate production of heavy oil.
The company has major geothermal operations in Indonesia and the
Philippines and is investigating several advanced solar
technologies for use in oil field operations as part of its
renewable energy strategy. For additional information on the
company’s geothermal operations and renewable energy
projects, refer to pages 19 and 30, respectively.
In September 2006, the company sold its interest in the
8-megawatt Amada Rayong power generation facility in Thailand.
Chevron Energy Solutions (CES) is a wholly owned subsidiary that
provides public institutions and businesses with projects
designed to increase energy efficiency and reliability, reduce
energy costs and utilize renewable and alternative power
technologies. CES has energy-saving projects installed in more
than a thousand buildings nationwide. Major
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projects completed by CES in 2006 include energy efficiency and
renewable power installations for U.S. Postal Service
facilities, the first megawatt-class hydrogen fuel cell
cogeneration plant in California, and cogeneration and biomass
facilities for a municipal water pollution control plant.
The company’s Energy Technology Company supports
Chevron’s upstream and downstream businesses with
technologies that span the hydrocarbon value chain from
exploration to refining and marketing.
The Technology Ventures Company identifies, grows and
commercializes emerging technologies with the potential to
transform energy production and use. The business development
portfolio includes biofuels, hydrogen infrastructure, advanced
batteries, nano-materials and renewable energy applications.
In the second quarter 2006, the company completed the
acquisition of a 22 percent interest in Galveston Bay
Biodiesel L.P., which is building one of the first large-scale
biofuel plants in the United States. During 2006, the company
also entered into research alliances with the University of
California, Davis and the Georgia Institute of Technology. Both
are focused on converting cellulosic biomass into viable
transportation fuels.
Chevron’s research and development expenses were
$468 million, $316 million and $242 million for
the years 2006, 2005 and 2004, respectively.
Some of the investments the company makes in the areas described
above are in new or unproven technologies and business
processes, and ultimate successes are not certain. Although not
all initiatives may prove to be economically viable, the
company’s overall investment in this area is not
significant to the company’s consolidated financial
position.
Virtually all aspects of the company’s businesses are
subject to various U.S. federal, state and local
environmental, health and safety laws and regulations, and
similar laws and regulations in other countries. These
regulatory requirements continue to change and increase in both
number and complexity and to govern not only the manner in which
the company conducts its operations, but also the products it
sells. Chevron expects more environmental-related regulations in
the countries where it has operations. Most of the costs of
complying with the many laws and regulations pertaining to its
operations are embedded in the normal costs of conducting
business.
In 2006, the company’s U.S. capitalized environmental
expenditures were $385 million, representing approximately
7 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 are predominantly in the upstream
and downstream segments and relate mostly to air- and
water-quality projects and activities at the company’s
refineries, oil and gas producing facilities, and marketing
facilities. For 2007, the company estimates U.S. capital
expenditures for environmental control facilities will be
approximately $350 million. The future annual capital costs
of fulfilling this commitment are uncertain and will be governed
by several factors, including future changes to regulatory
requirements.
Further information on environmental matters and their impact on
Chevron and on the company’s 2006 environmental
expenditures, remediation provisions and year-end environmental
reserves are contained in Management’s Discussion and
Analysis of Financial Condition and Results of Operations on
pages FS-17
through
FS-19 of
this Annual Report on
Form 10-K.
The company’s Internet Web site can be found at
http://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 on the company’s Web site soon after
such reports are filed with or furnished to the Securities and
Exchange Commission (SEC). Alternatively, you may access these
reports at the SEC’s Internet Web site:
http://www.sec.gov/.
Table of Contents
Chevron is a major fully integrated petroleum company with a
diversified business portfolio, 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 crude oil prices. Except
in the ordinary course of running an integrated petroleum
business, Chevron does not seek to hedge its exposure to price
changes. A significant, persistent decline in crude oil prices
may have a material adverse effect on its results of operations
and its capital and exploratory expenditure plans.
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, the
company’s business will decline. Creating and maintaining
an inventory of projects depends on many factors, including
obtaining rights to explore, develop and produce hydrocarbons in
promising areas; 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, including hurricanes, floods and other
forms of severe weather, war, civil unrest and other political
events, fires, earthquakes, and explosions, any of which could
result in suspension of operations or harm to people or the
natural environment.
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
by-products, which may be considered pollutants. Any of these
activities could result in liability, either as a result of an
accidental, unlawful discharge or as a result of new conclusions
on the effects of the company’s operations on human health
or the environment.
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
and/or to
impose additional taxes or royalties.
In certain locations, governments have imposed restrictions,
controls and taxes, and in others, political conditions have
existed that may threaten the safety of employees and the
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, 2006, 24 percent of the
company’s proved reserves were located in Kazakhstan. The
company also has significant interests in Organization of
Petroleum Exporting Countries (OPEC)-member countries including
Indonesia, Nigeria and Venezuela. Approximately 25 percent
of the company’s net proved reserves, including affiliates,
were located in OPEC countries at December 31, 2006. In
December 2006, OPEC admitted Angola as a new member effective
January 1, 2007. Oil-equivalent reserves at the end of 2006
in Angola represented 5 percent of the company’s total.
Management believes it is reasonably likely that the scientific
and political attention to issues concerning the existence and
extent of climate change, and the role of human activity in it,
will continue, with the potential for further regulation that
affects the company’s operations. Although uncertain, these
developments could increase costs or reduce
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the demand for the products the company sells. The
company’s production and processing operations (e.g., the
production of crude oil at offshore platforms and the processing
of natural gas at liquefied natural gas facilities) typically
result in emissions of greenhouse gases. Likewise, emissions
arise from midstream and downstream operations, including crude
oil transportation and refining. Finally, although beyond the
control of the company, the use of passenger vehicle fuels and
related products by consumers also results in these emissions.
International agreements, domestic legislation and regulatory
measures to limit greenhouse gas emissions are currently in
various phases of discussion or implementation. These include
the Kyoto Protocol, proposed federal legislation and current
state-level actions. Some of the countries in which Chevron
operates have ratified the Kyoto Protocol, and the company is
currently complying with greenhouse gas emissions limits within
the European Union. Although resolutions supporting “cap
and trade” systems have been introduced in the
U.S. Congress, no bill restricting greenhouse gas emissions
has been passed to date.
In California, the Global Warming Solutions Act became effective
on January 1, 2007. This law caps California’s
greenhouse gas emissions at 1990 levels by 2020; directs the Air
Resources Board, the responsible state agency, to determine
greenhouse gas emissions in and outside California to adopt
mandatory reporting rules for significant sources of greenhouse
gases; delegates to the agency the authority to adopt compliance
mechanisms (including market-based approaches); and permits a
one-year extension of the targets under extraordinary
circumstances. Related regulatory activity is under way within
the California Public Utilities Commission. The company extracts
crude oil and natural gas, operates refineries, and markets and
sells gasoline in California. It is not known at this time
whether or to what extent the state agencies’ regulations
will affect the company’s California operations.
Item 1B. Unresolved
Staff Comments
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 above
under Item 1. Business. Information required by the
Securities Exchange Act Industry Guide No. 2
(“Disclosure of Oil and Gas Operations”) is also
contained in Item 1 and in Tables I through VII on pages
FS-63 to FS-76 of this Annual Report on
Form 10-K.
Note 13, “Properties, Plant and Equipment,” to
the company’s financial statements is on
page FS-43
of this Annual Report on
Form 10-K.
Chevron’s U.S. refineries are implementing a consent
decree with the federal Environmental Protection Agency (EPA)
and four state air agencies to resolve claims about
Chevron’s past application of “New Source Review”
permitting programs under the Clean Air Act. The consent decree
provides that Chevron will pay stipulated penalties for certain
violations of the consent decree, if demand is made by the EPA.
In July 2006, Chevron’s refinery in Pascagoula, Mississippi
exceeded its emission limit under the consent decree for
particulate matter. The exceedance was reported at the time and
the possibility of a penalty was discussed. In January 2007, the
Mississippi Department of Environmental Quality (MDEQ) and the
EPA issued a notice of violation and a request for payment of
$210,000 in stipulated penalties for the July 2006 particulate
matter exceedance. The company, the EPA and the MDEQ are in
negotiation with regard to the nature and amount of the penalty
demand.
None.
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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 either Directors or
members of the Executive Committee or who are chief executive
officers of principal business units. Except as noted below, all
of the Corporation’s Executive Officers have held one or
more of such positions for more than five years.
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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
of this Annual Report on
Form 10-K.
CHEVRON
CORPORATION
In December 2006, the company authorized stock repurchases of up
to $5 billion that may be made from time to time at
prevailing prices as permitted by securities laws and other
requirements and subject to market conditions and other factors.
The program will occur over a period of up to three years and
may be discontinued at any time. As of December 31, 2006,
1,336,000 shares had been acquired under this program for
$100 million.
The selected financial data for years 2002 through 2006 are
presented on
page FS-62
of this Annual Report on
Form 10-K.
The index to Management’s Discussion and Analysis,
Consolidated Financial Statements and Supplementary Data is
presented on
page FS-1
of this Annual Report on
Form 10-K.
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 7 to the Consolidated Financial Statements,
“Financial and Derivative Instruments,” beginning on
page FS-37.
The index to Management’s Discussion and Analysis,
Consolidated Financial Statements and Supplementary Data is
presented on
page FS-1
of this Annual Report on
Form 10-K.
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Item 9. Changes
in and Disagreements With Auditors on Accounting and Financial
Disclosure
None.
(a) Evaluation of Disclosure Controls
and Procedures
Chevron Corporation’s Chief Executive Officer and Chief
Financial Officer, after evaluating the effectiveness of the
company’s “disclosure controls and procedures”
(as defined in
Rules 13a-15(e)
and
15d-15(e)
under the Securities Exchange Act of 1934 (the “Exchange
Act”)), as of December 31, 2006, have concluded that
as of December 31, 2006, the company’s disclosure
controls and procedures were effective and designed to provide
reasonable assurance that material information relating to the
company and its consolidated subsidiaries required to be
included in the company’s periodic filings under the
Exchange Act would be made known to them by others within those
entities.
(b) Management’s Report on
Internal Control Over Financial Reporting
The company’s management is responsible for establishing
and maintaining adequate internal control over financial
reporting, as such term is defined in Exchange Act
Rules 13a-15(f).
The company’s management, including the Chief Executive
Officer and Chief Financial Officer, conducted an evaluation of
the effectiveness of its 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
its internal control over financial reporting was effective as
of December 31, 2006.
The company management’s assessment of the effectiveness of
its internal control over financial reporting as of
December 31, 2006, has been audited by
PricewaterhouseCoopers LLP, an independent registered public
accounting firm, as stated in its report that is included on
page FS-26 of this Annual Report on
Form 10-K.
(c) Changes in Internal Control Over
Financial Reporting
During the quarter ended December 31, 2006, 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.
None.
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PART III
The information on Directors appearing under the heading
“Election of Directors — Nominees For
Directors” in the Notice of the 2007 Annual Meeting of
Stockholders and 2007 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 2007 Annual
Meeting of Stockholders (the “2007 Proxy Statement”),
is incorporated by reference in this Annual Report on
Form 10-K.
See Executive Officers of the Registrant on pages 33 and 34
of this Annual Report on
Form 10-K
for information about Executive Officers of the company.
The information contained under the heading “Stock
Ownership Information — Section 16(a)
Beneficial Ownership Reporting Compliance” in the 2007
Proxy Statement is incorporated by reference in this Annual
Report on
Form 10-K.
The information contained under the heading “Board
Operations — Business Conduct and Ethics Code” in
the 2007 Proxy Statement is incorporated by reference in this
Annual Report on
Form 10-K.
The company has a separately designated standing Audit Committee
established in accordance with Section 3(a)(58)(A) of the
Exchange Act. The members of the Audit Committee are Charles R.
Shoemate (Chairperson), Linnet F. Deily, Robert E. Denham and
Franklyn G. Jenifer, all of whom are independent under the New
York Stock Exchange Corporate Governance Rules. Of these Audit
Committee members, Charles R. Shoemate, Linnet F. Deily and
Robert E. Denham are audit committee financial experts as
determined by the Board within the applicable definition of the
SEC.
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 appearing under the headings “Executive
Compensation” and “Directors’ Compensation”
in the 2007 Proxy Statement is incorporated herein by reference
in this Annual Report on
Form 10-K.
“The members of the Compensation Committee of the Board of
Directors during the last fiscal year were Carla A. Hills (until
her retirement on April 26, 2006), Robert J. Eaton, Samuel
H. Armacost, Ronald D. Sugar and Carl Ware, none of whom is a
present or former officer or employee of the company. In
addition, during 2006, no officers had an “interlock”
relationship, as that term is defined by the SEC, to
report.”
The information appearing under the heading “Management
Compensation Committee Report” in the 2007 Proxy Statement
is incorporated herein by reference in 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 2007 Proxy Statement shall not be deemed
“filed” for purposes of Section 18 of the
Exchange Act nor shall it be deemed incorporated by reference in
any filing under the Securities Act of 1933.
The information appearing under the heading “Stock
Ownership Information — Security Ownership of
Certain Beneficial Owners and Management” in the 2007 Proxy
Statement is incorporated by reference in this Annual Report on
Form 10-K.
The information contained under the heading “Equity
Compensation Plan Information” in the 2007 Proxy Statement
is incorporated by reference in this Annual Report on
Form 10-K.
The information appearing under the heading “Board
Operations” in the 2007 Proxy Statement is incorporated by
reference in this Annual Report on
Form 10-K.
The information appearing under the headings “Ratification
of Independent Registered Public Accounting Firm —
Principal Accountant Fees and Services” and
“Ratification of Independent Registered Public Accounting
Firm — Audit Committee Pre-Approval Policies and
Procedures” in the 2007 Proxy Statement is incorporated by
reference in this Annual Report on
Form 10-K.
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PART IV
Item 15. Exhibits,
Financial Statement Schedules
(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 28th day of February,
2007.
Chevron Corporation
David J. O’Reilly, 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 28th day of February, 2007.
INDEX TO MANAGEMENT’S DISCUSSION AND ANALYSIS,
FS-1
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KEY FINANCIAL RESULTS
INCOME FROM CONTINUING OPERATIONS BY MAJOR
Refer to the “Results of Operations” section
beginning on page FS-6 for a detailed discussion of
financial results by major operating area for the
three years ending December 31, 2006.
BUSINESS ENVIRONMENT AND OUTLOOK Chevron’s current and future earnings depend
largely on the profitability of its upstream
(exploration and production) and
downstream (refining, marketing and transportation)
business segments. The single biggest factor that
affects the results of operations for both segments is
movement in the price of crude oil. In the downstream
business, crude oil is the largest cost component of
refined products. The overall trend in earnings is
typically less affected by results from the company’s
chemicals business and other activities and
investments. Earnings for the company in any period may
also be influenced by events or transactions that are
infrequent and/ or unusual in nature. Chevron and the
oil and gas industry at large are currently
experiencing an increase in certain costs that exceeds
the general trend of inflation in many areas of the
world. This increase in costs is affecting the
company’s
operating expenses for all business segments and capital expenditures, particularly for the upstream business. To sustain its long-term competitive position in
the upstream business, the company must develop and
replenish an inventory of projects that offer adequate
financial returns for the investment required.
Identifying promising areas for exploration, acquiring
the necessary rights to explore for and to produce
crude oil and natural gas, drilling successfully, and
handling the many technical and operational details in
a safe and cost-effective manner are all important
factors in this effort. Projects often require long
lead times and large capital commitments. Changes in
economic, legal or political circumstances can have
significant effects on the profitability of a project
over its expected life. In the current environment of
higher commodity prices, certain governments have
sought to renegotiate contracts or impose additional
costs on the company. Other 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. In late February 2007, the
President of Venezuela issued a decree announcing the
government’s intention for the state-owned oil company,
Petróleos de Venezuela S.A., to increase its ownership later
this year in all Orinoco Heavy Oil Associations, including
Chevron’s 30 percent-owned Hamaca project, to a minimum of
60 percent. The impact on Chevron from such an action is
uncertain but is not expected to have a material effect on the
company’s results of operations, consolidated financial position
or liquidity.
The company also continually evaluates
opportunities to dispose of assets that are not key to
providing sufficient long-term value, or to acquire
assets or operations complementary to its asset base to
help augment the company’s growth. During the first
quarter 2007, the company authorized the sale of its 31
percent ownership interest in the Nerefco Refinery and
the associated TEAM Terminal in the Netherlands. The
transaction is subject to signing of the sales
agreement and obtaining necessary regulatory approvals.
The company expects to record a gain upon close of the
sale. In early 2007, the company was also in
discussions regarding the possible sale of its fuels
marketing operations in the Netherlands, Belgium and
Luxembourg. Neither the refining nor marketing assets
were classified as held-for-sale as of December 31,
2006, in
accordance with the held-for-sale criteria of
Financial Accounting Standards Board (FASB) Statement
No. 144,
Impairment or Disposal of Long-Lived Assets. Other
asset dispositions and restructurings may occur in
future periods and could result in significant gains or
losses.
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 that may be caused by
military conflicts, civil unrest or political
uncertainty.
FS-2
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Moreover, any of these factors could also inhibit the
company’s production capacity in an affected region.
The company monitors developments closely in the
countries in which it operates and holds investments,
and attempts to manage risks in operating its
facilities and business.
Price levels for capital and exploratory costs and
operating expenses associated with the efficient
production of crude oil and natural gas can also be
subject to external factors beyond the company’s
control. External factors include not
only the general level of inflation, but also prices charged by the industry’s product- and service-providers, which can be affected by the volatility of the industry’s own supply and demand conditions for such products and services. The oil and gas industry worldwide experienced significant price increases for these items during 2005 and 2006, and an upward trend in prices may continue into 2007. Capital and exploratory expenditures and operating expenses also can be affected by uninsured damages to production facilities caused by severe weather or civil unrest. Industry price levels for crude oil generally
increased in the first half of 2006 and declined in the
second half. Prices at the end of 2006 were slightly
lower than at the beginning of the year. The spot price
for West Texas Intermediate (WTI) crude oil, a
benchmark crude oil, averaged $66 per barrel in 2006,
an increase of approximately $9 per barrel from the
2005 average price. The rise in crude oil prices
between years reflected, among other things, increasing
demand in growing economies, the heightened level of
geopolitical uncertainty in some areas of the
world and supply concerns in other key producing
regions. For early 2007 into late February, the WTI
spot price averaged about $56 per barrel.
As was the case in 2005, a wide differential in
prices existed in 2006 between high-quality,
light-sweet crude oils (such as the U.S. benchmark
WTI) and heavier types of crude. The price for the
heavier crudes has been dampened because of ample
supply and lower relative demand due to the limited
number of refineries that are able to process this
lower-quality feedstock into light products (i.e.,
motor gasoline, jet fuel, aviation gasoline and diesel
fuel). The price
for higher-quality, light-sweet crude oil has remained
high, as the demand for light products, which can be
more easily manufactured by refineries from light-sweet
crude oil, has been strong worldwide. Chevron produces
heavy crude oil in California, Chad, Indonesia, the
Partitioned Neutral Zone between Saudi Arabia and
Kuwait, Venezuela and in certain fields in Angola,
China and the United Kingdom North Sea. (Refer to page
FS-11 for the company’s average U.S. and international
crude oil prices.)
In contrast to price movements in
the global market for crude oil, price changes for
natural gas are more closely aligned with regional
supply and demand conditions. In the United States
during 2006, benchmark prices at Henry Hub averaged
about $6.50 per thousand cubic feet (MCF), compared
with about $8 in 2005. For early 2007 into late
February, prices averaged about $7 per MCF.
Fluctuations in the price for natural gas in the United
States are closely associated with the volumes produced
in North America and the inventory in underground
storage relative to customer demand. Natural gas prices
in the United States are also typically higher during
the winter period when demand for heating is greatest.
In contrast to the United States, certain other
regions of the world in which the company operates have
different supply, demand and regulatory circumstances,
typically resulting in significantly lower average
sales prices for the company’s production of natural
gas. (Refer to page FS-11 for the company’s average
natural gas prices for the United States and
international regions.) Additionally, excess supply
conditions that exist in certain parts of the world
cannot easily serve to mitigate the relatively
high-price conditions in the United States and other
markets because of the lack of infrastructure to
transport and receive liquefied natural gas.
To help address this regional imbalance between
supply and demand for natural gas, Chevron is
planning increased
FS-3
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investments in long-term projects in areas of
excess supply to install infrastructure to produce and
liquefy natural gas for transport by tanker, along with
investments and commitments to regasify the product in
markets where demand is strong and supplies are not as
plentiful. Due to the significance of the overall
investment in these long-term projects, the natural gas
sales prices in the areas of excess supply (before the
natural gas is transferred to a company-owned or
third-party processing facility) are expected to remain
well below sales prices for natural gas that is
produced much nearer to areas of high demand and can be
transported in existing natural gas pipeline networks
(as in the United States).
Besides the impact of the fluctuation in price
for crude oil and natural gas, the longer-term trend
in earnings for the upstream segment is also a
function of other factors, including the company’s
ability to find or acquire and efficiently produce
crude oil and natural gas, changes in fiscal terms,
and the cost of goods and services.
Chevron’s worldwide net oil-equivalent production
in 2006, including volumes produced from oil sands and
production under an operating service agreement,
averaged 2.67 million barrels per day, or 6 percent
higher than production in 2005. The increase between
periods was largely due to volumes associated with the
acquisition of Unocal in August 2005. The company
estimates that oil-equivalent production in 2007 will
average approximately 2.6 million barrels per day. This
estimate is subject to many uncertainties, including
quotas that may be imposed by OPEC, the price effect on
production volumes calculated under cost-recovery and
variable-royalty provisions of certain contracts,
changes in fiscal terms or restrictions on the scope of
company operations, and production disruptions that
could be caused by severe weather, local civil unrest
and changing geopolitics. Future production levels also
are affected by the size and number of economic
investment opportunities and, for new large-scale
projects, the time lag between initial exploration and
the beginning of production. Most of Chevron’s upstream
investment is currently being made outside the United
States. Investments in upstream projects generally are
made well in advance of the start of the associated
crude oil and natural gas production.
Approximately 24 percent of the company’s net
oil-equivalent production in 2006 occurred in the
OPEC-member countries of Indonesia, Nigeria and
Venezuela and in the Partitioned Neutral Zone between
Saudi Arabia and Kuwait. In December 2006, OPEC
admitted Angola as a new member effective January 1,
2007. Oil-equivalent
production for 2006 in Angola represented 6
percent of the company’s total. In October 2006, OPEC
announced its decision to reduce OPEC-member
production quotas by 1.2 million barrels of crude oil
per day, or 4.4 percent, from a production level of
27.5 million barrels, effective
November 1, 2006. In December 2006, OPEC announced an additional
quota reduction of 500,000 barrels of crude oil per
day, effective February 1, 2007. OPEC quotas did not
significantly affect Chevron’s production level in
2006. The impact of quotas on the company’s production
in 2007 is uncertain.
In October 2006, Chevron’s Boscan and LL-652
operating service agreements in Venezuela were
converted to Empresas Mixtas (i.e. joint stock
contractual structures), with Petróleos de Venezuela
S.A., as majority shareholder. Beginning in October,
Chevron reported its equity share of the Boscan and
LL-652 production, which was approximately 90,000
barrels per day less than what the company previously
reported under the operating service agreements. The
change to the Empresa Mixta structure did not have a
material effect on the company’s results of operations,
consolidated financial position or liquidity.
At the end of 2005 in certain onshore areas of
Nigeria, approximately 30,000 barrels per day of the
company’s net production capacity remained shut-in
following civil unrest and damage to production
facilities that occurred in 2003. By the end of 2006,
the company had resumed operations in portions of all
the affected fields, and more than 20,000 barrels per
day of production had been restored. In early 2007,
additional production restoration activities continued
in the area; however, intermittent civil unrest could
adversely impact company operations in the future.
Refer to pages FS-6 through FS-7 for additional
discussion of the company’s upstream operations.
Downstream Earnings for the downstream segment are
closely tied to global and regional supply and demand
for refined products and the associated effects on
industry refining and marketing margins. Other factors
include the reliability and efficiency of the company’s
refining and marketing network, the effectiveness of
the crude-oil and product-supply functions, and the
economic returns on invested capital. Profitability can
also be affected by the volatility of charter expenses
for the company’s shipping operations, which are driven
by the industry’s demand for crude oil and product
tankers. Other factors that are beyond the company’s
control include the general level of inflation and
energy costs to operate the company’s refinery and
distribution network.
The company’s core marketing areas are the West
Coast of North America, the U.S. Gulf Coast, Latin
America, Asia and sub-Saharan Africa. The company
operates or has ownership interests in refineries in
each of these areas, except Latin America. In 2006,
earnings for the segment improved substantially,
mainly as the result of higher average margins for
refined products and improved operations at the
company’s refineries.
FS-4
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Industry margins in the future may be volatile
and are influenced by changes in the price of crude
oil used for refinery feedstock and by changes in the
supply and demand for crude oil and refined products.
The industry supply and demand balance can be affected
by disruptions at refineries resulting from
maintenance programs and unplanned outages, including
weather-related disruptions; refined-product inventory
levels; and geopolitical events.
Refer to pages FS-8 through FS-9 for additional
discussion of the company’s downstream operations.
Chemicals Earnings in the petrochemicals business
are closely tied to global chemical demand, industry
inventory levels and plant capacity utilization.
Feedstock and fuel costs, which tend to follow crude
oil and natural gas price movements, also influence
earnings in this segment.
Refer to page FS-9 for additional discussion of
chemicals earnings.
OPERATING DEVELOPMENTS Key operating developments and other events
during 2006 and early 2007 included:
Upstream United States In the Gulf of Mexico, the company
announced in September 2006 the completion of a
successful production test on the 50 percent-owned and
operated Jack #2 well. The test was a follow-up to the
2004 Jack discovery and was the deepest well-test ever
accomplished in the Gulf of Mexico.
Also in the Gulf of Mexico, the company announced
in October its decision to develop the Great White,
Tobago and Silvertip fields via a common producing hub, the
Perdido Regional Host,
which will have a
processing capacity of
130,000 barrels of
oil-equivalent per day.
First
production from the 38
percent-owned Perdido
Regional Host is
anticipated by 2010. The
company’s ownership
interests in the fields
are Great White – 33
percent, Tobago – 58
percent and Silvertip –
60 percent.
Angola In June 2006,
the company produced the
first crude oil from the
offshore Lobito field,
located in Block 14.
Lobito is part of the 31
percent-owned and
operated Benguela
Belize–Lobito Tomboco
(BBLT) development
project. As fields and
wells are added over the
next two years, BBLT’s maximum production is expected
to reach approximately 200,000 barrels of oil per day.
Also in Block 14, the company produced first crude oil
in June 2006
from the Landana North reservoir in the 31
percent-owned and operated Tombua-Landana development
area. This initial production is tied back to the
nearby BBLT production facilities. Tombua-Landana is
the company’s third deepwater development offshore
Angola. Maximum production from the completed
Tombua-Landana development is estimated at 100,000
barrels per day by 2010.
In early 2007, the company announced a discovery
of crude oil at the 31 percent-owned and operated
Lucapa-1 well in deepwater Block 14. The company
plans to conduct appraisal drilling and additional
geologic and engineering studies to assess the
potential resource.
Australia In July 2006, the company discovered
natural gas at the Chandon-1 exploration well offshore
the northwestern coast in the Greater Gorgon
development area. The company’s interest in the
property is 50 percent.
Also offshore the northwestern coast, the company
announced in November 2006 a significant natural gas
discovery at its Clio-1 exploration well. The company
holds a 67 percent interest in the block where Clio-1
is located. Chevron will be undertaking further work,
including a 3-D seismic survey program that started in
late 2006, to better determine the potential of the
gas find and subsequent development options.
In early 2007, the company was also named
operator and awarded a 50 percent interest in
exploration acreage in the Greater Gorgon Area. A
three-year work program includes geotechnical studies,
seismic surveys and drilling of an exploration well.
Azerbaijan The first tanker lifting of crude oil
transported through the 9 percent-owned
Baku-Tbilisi-Ceyhan (BTC) pipeline occurred in June
2006. The crude is being supplied by the Azerbaijan
International Oil Company, in which the company has a
10 percent nonoperated working interest.
Brazil In June 2006, the company announced the
decision to develop the 52 percent-owned and operated
offshore Frade Field. Initial production is targeted by
early 2009, with a maximum annual rate estimated at
90,000 oil-equivalent barrels per day in 2011.
Canada The company acquired heavy oil leases in
the Athabasca region of northern Alberta, Canada in
2005 and 2006. The leases comprise more than 75,000
acres and contain significant volumes that have
potential for recovery using Steam Assisted Gravity
Drainage technology.
Also in Alberta, the company announced its
decision in October 2006 to participate in the
expansion of the Athabasca Oil Sands Project (AOSP).
The expansion is expected to add 100,000 barrels per
day of mining and upgrading capacity at an estimated
total project cost of $10 billion. Completion of the
expansion is planned for 2010, increasing total
capacity of the project to approximately 255,000
barrels per day. The company holds a 20 percent
nonoperated working interest in AOSP.
Nigeria In May 2006, the company announced the
discovery of crude oil at the nonoperated Uge-1
exploration well in the 20 percent-owned offshore Oil
Prospecting License 214. Future drilling is contingent
primarily on the outcome of ongoing technical studies.
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Table of Contents
Norway In April 2006, the company was
awarded the rights to six blocks in the 19th Norwegian
Licensing Round. The 40 percent-owned blocks are
located in the Nordkapp East Basin in the Norwegian
Barents Sea. A 3-D seismic survey was acquired and is
planned to be processed in 2007.
Thailand In early 2006, the company signed two
petroleum exploration concessions in the Gulf of
Thailand. Chevron has a 71 percent operated interest in
one concession, which is in the proximity of the
company’s Tantawan and Plamuk fields. Initial drilling
in the concession is scheduled during 2007. Drilling is
projected by 2009 for the other concession, in which
Chevron has a 16 percent nonoperated working interest.
United Kingdom In June 2006, the company produced
the first crude oil from the 85 percent-owned and
operated Area C in the Captain Field. The project
reached maximum production of 14,000 barrels of crude
oil per day in September 2006.
In early 2007, the company was awarded eight
operated exploration blocks and two nonoperated blocks
west of Shetland Islands in the 24th United Kingdom
Offshore Licensing Round.
Vietnam In April 2006, the company signed a
30-year production-sharing contract with Vietnam Oil
and Gas Corporation for Block 122 offshore eastern
Vietnam. The company has a 50 percent interest in this
block and has undertaken a three-year work program for
seismic acquisition and drilling of an exploratory
well.
Downstream United States In December 2006, the company
completed the expansion of the Fluid Catalytic
Cracking Unit at the company’s refinery in Pascagoula,
Mississippi, increasing the refinery’s gasoline
manufacturing capacity by about 10 percent. The
company also submitted an environmental permit
application for construction of facilities to increase
gasoline output by another 15 percent.
India In April 2006, the company acquired a 5
percent interest in Reliance Petroleum Limited, a
company formed by Reliance Industries Limited to
construct, own and operate a refinery in Jamnagar,
India. The new refinery would be the world’s sixth
largest, designed for a crude oil processing capacity
of 580,000 barrels per day. Chevron and Reliance
Industries also signed two memoranda of understanding
to jointly pursue other downstream and upstream
business opportunities. If discussions pursuant to the
memoranda of understanding lead to definitive
agreements, Chevron may increase its equity stake in
Reliance Petroleum to 29 percent.
Other Biofuels In May 2006, the company announced that
it had completed the acquisition of a 22 percent
interest in
Galveston Bay Biodiesel L.P., which is building one of
the first large-scale biodiesel plants in the United
States. The following month, the company entered into a
research alliance with the Georgia Institute of
Technology to pursue advanced technology aimed at
making cellulosic biofuels and hydrogen into
transportation fuels. In September, the company
announced a research collaboration with the University
of California, Davis aimed at converting cellulosic
biomass into transportation fuels.
Common Stock Dividends and Stock Repurchase
Program In April 2006, the company increased its
quarterly common stock dividend by 15.5 percent to
$0.52 per share. In November, the company completed
its second $5 billion common stock buyback program
since 2004 and in December authorized the acquisition
of up to $5 billion of additional shares over a
period of up to three years.
RESULTS OF OPERATIONS Major Operating Areas The following section
presents the results of operations for the company’s
business segments – upstream, downstream and chemicals
– as well as for “all other,” which includes mining,
power generation businesses, and the various companies
and departments that are managed at the corporate
level. Income is also presented for the U.S. and
international geographic areas of the upstream and
downstream business segments. (Refer to Note 8,
beginning on page FS-38, for a discussion of the
company’s “reportable segments,” as defined in FASB No.
131, Disclosures About Segments of an Enterprise and
Related Information.) This section should also be read
in conjunction with the discussion in “Business
Environment and Outlook” on pages FS-2 through FS-5.
U.S. upstream income of $4.3 billion in 2006
increased approximately $100 million from 2005.
Earnings in 2006 benefited about $850 million from
higher average prices on oil-equivalent production and
the effect of seven additional months of production
from the Unocal properties that were acquired in
August 2005. Substantially offsetting these benefits
were increases in operating expense and expenses for
depreciation and exploration. Included in the
operating expense increases were costs associated with
the carryover effects of hurricanes in the Gulf of
Mexico in 2005.
Income of $4.2 billion in 2005 was $230 million
higher
than 2004. The 2004 amount included gains of
approxi-
FS-6
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mately $400 million from asset sales. Higher prices for
crude oil and natural gas in 2005 and five months of
earnings from the former Unocal operations contributed
approximately $2 billion to the increase between
periods. Approximately 90 percent of this amount
related to the effects of higher prices on
heritage-Chevron production. These benefits were
substantially offset by the adverse effects of lower
production, higher operating expenses and higher
depreciation expense associated with the heritage
Chevron properties.
The company’s average realization for crude oil
and natural gas liquids in 2006 was $56.66 per barrel,
compared with $46.97 in 2005 and $34.12 in 2004. The
average natural gas realization was $6.29 per thousand
cubic feet in 2006, compared with $7.43 and $5.51 in
2005 and 2004, respectively.
Net oil-equivalent production in 2006 averaged
763,000 barrels per day, up 5 percent from 2005 and
down 7 percent from 2004. The increase between 2005 and
2006 was due to the full-year benefit of production
from the former Unocal
properties. The decrease from 2004 was associated mainly with the effects of hurricanes, property sales and normal field declines, partially offset by additional volumes from the former Unocal properties. The net liquids component of oil-equivalent
production for 2006 averaged 462,000 barrels per day,
an increase of approximately 2 percent from 2005 and a
decrease of 9 percent from 2004. Net natural gas
production averaged 1.8 billion cubic feet per day in
2006, up 11 percent from 2005 and down 3 percent from
2004.
Refer to the “Selected Operating Data” table, on
page FS-11, for the three-year comparative production
volumes in the United States.
International Upstream – Exploration and Production
International upstream income of
approximately $8.9 billion in 2006 increased $1.3
billion from 2005. Earnings in 2006 benefited
approximately $3.0 billion from higher prices for crude
oil and natural gas and an additional seven months of
production from the former Unocal properties. About 70
percent of this benefit was associated with the
impact of higher prices. Substantially offsetting these
benefits were increases in depreciation expense,
operating expense and exploration expense. Also
adversely affecting 2006 income were higher taxes
related to an increase in tax rates in the U.K. and
Venezuela and settlement of tax claims and other tax
items in Venezuela, Angola and Chad. Foreign currency
effects reduced earnings by $371 million in 2006, but
increased income $14 million in 2005.
Income in 2005 was approximately $7.5 billion,
compared with $5.8 billion in 2004, which included
gains of approximately $850 million from property
sales. Higher prices for crude oil and natural gas in
2005 and five months of earnings from the former
Unocal operations increased income approximately $2.9
billion between periods. About 80 percent of this
benefit arose from the effects of higher prices on
heritage-Chevron production. Partially offsetting
these benefits were higher expenses between periods
for certain income tax items, including the absence of
a $200 million benefit in 2004 relating to changes in
income tax laws. Foreign currency effects increased
income $14 million in 2005 but reduced income $129
million in 2004.
The company’s average realization for crude oil
and natural gas liquids in 2006 was $57.65 per barrel,
compared with $47.59 in 2005 and $34.17 in 2004. The
average natural gas realization was $3.73 per thousand
cubic feet in 2006, compared with $3.19 and $2.68 in
2005 and 2004, respectively.
Net oil-equivalent production of 1.9 million
barrels per day in 2006, including about 100,000 net
barrels per day from oil sands in Canada and
production under an operating service agreement in
Venezuela prior to its conversion to a joint stock
company, increased about 6 percent from 2005 and 13
percent from 2004. This trend was largely the result
of the effects of the Unocal acquisition in August
2005, partially offset by the effect of normal field
declines and property sales in 2004.
The net liquids component of oil-equivalent
production was 1.4 million barrels per day in 2006, an
increase of approximately 2 percent from 2005 and 2004.
Net natural gas production of 3.1 billion cubic feet
per day in 2006 was up 21 percent and 51 percent from
2005 and 2004, respectively.
Refer to the “Selected Operating Data” table,
on page FS-11, for the three-year comparative of
international production volumes.
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Table of Contents
U.S. Downstream – Refining, Marketing and Transportation
U.S. downstream earnings of $1.9 billion in
2006 increased about $1 billion from 2005 and
approximately $700 million from 2004. Average
refined-product margins in 2006 were higher than in
2005, which in turn were also higher than in 2004.
Refinery crude inputs were higher in 2006 than in the
other comparative periods and also benefited
earnings. However, earnings declined in 2005
from
a year earlier due mainly to increased downtime at
the company’s refineries, including the shutdown of
operations at Pascagoula, Mississippi, for more than a
month due to hurricanes in the Gulf of Mexico. The
company’s marketing and pipeline operations along the
Gulf Coast were also disrupted for an extended period
due to the hurricanes. Fuel costs were also higher in
2005 than in 2004.
Sales volumes of refined products in 2006 were
approximately 1.5 million barrels per day, an increase
of 1 percent from 2005 and relatively unchanged from
2004. The reported sales volume for 2006 was on a
different basis than in 2005 and 2004 due to a change
in accounting rules that became effective April 1,
2006, for certain purchase and sale
(buy/sell) contracts with the same counterparty.
Excluding the impact of the accounting change, refined
product sales in 2006 increased by approximately 6
percent and 3 percent from 2005 and 2004, respectively.
Branded gasoline sales volumes of approximately 614,000
barrels per day in 2006 increased about 4 percent from
2005, largely due to the growth of the Texaco brand. In
2005, refined-product sales volumes decreased about 2
percent from 2004, primarily due to disruption related
to the hurricanes.
Refer to the “Selected Operating Data” table, on
page FS-11, for the three-year comparative
refined-product sales volumes in the United States.
Refer also to Note 14, Accounting for Buy/Sell
Contracts, on page FS-43 for a discussion of the
accounting for purchase and sale contracts with the
same counterparty.
International Downstream – Refining, Marketing and Transportation
International downstream income of $2 billion in 2006
increased about $250 million from 2005 and about
$50 million from 2004. The increase in 2006 from 2005
was associated mainly with the
benefit of higher-refined
product margins in
Asia-Pacific and Canada
and improved results from
crude-oil and
refined-product trading
activities. The decrease
in earnings in 2005 from
2004 was due mainly to
lower sales volumes;
higher costs for fuel and
transportation; expenses
associated with a fire at
a 40 percent-owned,
nonoperated terminal in
the United Kingdom; and
tax adjustments in various
countries. These items
more than offset an
improvement in average
refined-product margins
between periods. Foreign
currency effects improved
income by $98 million and
$7 million in 2006 and
2004, respectively, but
reduced income by $24
million in 2005.
FS-8
Table of Contents
Refined-product sales volumes
were 2.1
million barrels per day in 2006, about 6 percent lower
than 2005. Excluding the accounting change for buy/sell
contracts, sales were down 1 percent between 2005 and
2006. Refined-product sales volume of 2.3 million
barrels per day in 2005 were about 4 percent lower than
in 2004, primarily the result of lower gasoline trading
activity and lower fuel oil sales. Refer to the
“Selected Operating Data” table, on page FS-11, for the
three-year comparative refined-product sales volumes in
the international areas.
Chemicals
The chemicals
segment includes the
company’s Oronite
subsidiary and the 50
percent-owned Chevron
Phillips Chemical Company
LLC (CPChem). In 2006,
earnings of $539 million
increased about $200
million from both 2005 and
2004. Margins in 2006 for
commodity chemicals at
CPChem and for fuel and
lubricant additives at
Oronite were higher than
in 2005 and 2004. The
earnings decline from 2004
to 2005 was mainly
attributable to plant
outages and expenses in
the Gulf of Mexico region
due to hurricanes, which
affected both Oronite and
CPChem.
All Other
All Other consists of the company’s
interest in Dynegy Inc., mining operations, power
generation businesses, worldwide cash management and
debt financing activities, corporate administrative
functions, insurance operations, real estate
activities, and technology companies.
Net charges of $516 million in 2006 decreased
$173
million from $689 million in 2005. Excluding the
effects of foreign currency, net charges declined $60
million between periods. Interest income was higher in
2006, and interest expense was lower.
Between 2004 and 2005, net charges increased $669
million. Excluding the effects of foreign exchange,
net charges increased $574 million. Approximately $400
million of the increase was related to larger benefits
in 2004 from
corporate-level tax adjustments. Higher charges in 2005 also were associated with environmental remediation of properties that had been sold or idled and Unocal corporate-level activities. Interest expense was higher in 2005 due to an increase in interest rates and the debt assumed with the Unocal acquisition. CONSOLIDATED STATEMENT OF INCOME Comparative amounts for certain income statement
categories are shown below:
Sales and other operating revenues in 2006
increased over 2005 due primarily to higher prices for
refined products. The increase in 2005 from 2004 was a
result of the same factor plus the effect of higher average prices for crude oil and
natural gas. The higher revenues in 2006 were net of an
impact from the change in the accounting for buy/sell
contracts, as described in Note 14 on page FS-43.
Increased income from equity affiliates in
2006 was mainly due to improved results for
Tengizchevroil (TCO) and CPChem. The improvement in
2005 from 2004 was primarily due to improved results
for TCO and Hamaca (Venezuela). Refer to Note 12,
beginning on page FS-41, for a discussion of Chevron’s
investment in affiliated companies.
Other income of nearly $1.9 billion in 2004
included approximately $1.3 billion of gains from
upstream property sales. Interest income contributed
$600 million, $400 million and $200 million in 2006,
2005 and 2004, respectively. Average interest rates and
balances of cash and
marketable securities increased each year. Foreign
currency losses were $260 million in 2006 and $60
million in both 2005 and 2004.
Crude oil and product purchases in 2006
increased from 2005 on higher prices for crude oil and
refined products and the inclusion of Unocal-related
amounts for a full year in 2006. The increase was
mitigated by the effect of the accounting change in
April 2006 for buy/sell contracts. Purchase costs
increased 35 percent in 2005 from the prior year as a
result of higher prices for crude oil, natural gas and
refined products, as well as to the inclusion of
Unocal-related amounts for five months.
FS-9
Table of Contents
Operating, selling, general and
administrative expenses in 2006 increased 16 percent
from a year earlier. Expenses associated with the
former Unocal operations are included for the full year
in 2006, vs. five months in 2005. Besides this effect,
expenses were higher in 2006 for labor, transportation,
uninsured costs associated with the hurricanes in 2005
and a number of corporate items that individually were
not significant. Total expenses increased in 2005 from
2004 due mainly to the inclusion of former-Unocal
expenses for five months, higher costs for labor and
transportation, uninsured costs associated with storms
in the Gulf of Mexico, and asset write-offs.
Exploration expenses in 2006 increased from
2005 mainly due to higher amounts for well write-offs
and geological and geophysical costs for operations
outside the United States, as well as the inclusion of
expenses for the former Unocal operations for a full
year in 2006. Expenses increased in 2005 from 2004 due
mainly to the inclusion of Unocal-related amounts for
five months.
Depreciation, depletion and amortization
expenses
increased from 2004 through 2006 mainly as a
result of depreciation and depletion expense for the
former Unocal assets and higher depreciation rates
for certain heritage-Chevron crude oil and natural
gas producing fields worldwide.
Interest and debt expense in 2006 decreased
from 2005 primarily due to lower average debt balances
and an increase in the amount of interest capitalized,
partially offset by higher average interest rates on
commercial paper and other variable-rate debt. The
increase in 2005 over 2004 was mainly due to the
inclusion of debt assumed with the Unocal acquisition
and higher average interest rates for commercial paper
borrowings.
Taxes other than on income were essentially
unchanged in 2006 from 2005, with the effect of
higher U.S. refined product sales being offset by
lower sales volumes subject to duties in the
company’s European downstream operations.
The increase in 2005 from 2004 was the result of higher international taxes assessed on product values, higher duty rates in the areas of the company’s European downstream operations and higher U.S. federal excise taxes on jet fuel resulting from a change in tax law that became effective in 2005.
Effective income tax rates were 46 percent in
2006, 44 percent in 2005 and 37 percent in 2004. The
higher tax rate in 2006 included the effect of one-time
charges totaling $400 million, including an increase in
tax rates on upstream operations in the U.K. North Sea
and settlement of a tax claim in Venezuela. Rates were
higher in 2005 compared with the prior year due to an
increase in earnings in countries with higher tax rates
and the absence of benefits in 2004 from changes in the
income tax laws for certain international operations.
Refer also to the discussion of income taxes in Note 16
beginning on page FS-44.
FS-10
Table of Contents
SELECTED OPERATING DATA1,2
INFORMATION RELATED TO INVESTMENT IN At year-end 2006, Chevron owned a 19 percent
equity interest in the common stock of Dynegy Inc., a
provider of electricity to markets and customers
throughout the United States.
Investment in Dynegy Common Stock At December 31,
2006, the carrying value of the company’s investment in
Dynegy common stock was approximately $250 million.
This amount was about $180 million below the company’s
proportionate interest in Dynegy’s underlying net
assets. This difference is primarily the result of
write-downs of the investment in 2002 for declines in
the market value of the common shares below the
company’s carrying value that were deemed to be other
than temporary. The difference had been assigned to the
extent practicable to specific Dynegy assets and
liabilities, based upon the company’s analysis of the
various factors associated with the decline in value of
the Dynegy shares. The company’s equity share of
Dynegy’s reported earnings is adjusted quarterly when
appropriate to recognize a portion of the difference
between these allocated values and Dynegy’s historical
book values. The market value of the company’s
investment in Dynegy’s common stock at December 31,
2006, was approximately $700 million.
Investments in Dynegy Preferred Stock In May
2006, the company’s investment in Dynegy Series C
preferred stock was redeemed at its face value of
$400 million. Upon redemption of the preferred stock,
the company recorded a before-tax gain of $130
million ($87 million after tax).
Dynegy Proposed Business Combination with LS Power
Group Dynegy and LS Power Group, a privately held power
plant investor, developer and manager, announced in
September 2006 that the companies had executed a
definitive agreement to combine Dynegy’s assets and
operations with LS Power Group’s power-generation
portfolio and for Dynegy to acquire a 50 percent
ownership interest in a development joint venture with
LS Power. Upon close of the transaction, Chevron will
receive the same number of shares of the new company’s
Class A common stock that it currently holds in Dynegy.
Chevron’s ownership interest in the combined company
will be approximately 11 percent. The transaction is
subject to specified conditions, including the
affirmative vote of two-thirds of Dynegy’s common
shareholders and the receipt of regulatory approvals.
FS-11
Table of Contents
LIQUIDITY AND CAPITAL RESOURCES Cash, cash equivalents and marketable securities
Total
balances were $11.4 billion and $11.1 billion at
December 31, 2006 and 2005, respectively. Cash provided
by operating activities in 2006 was $24.3 billion,
compared with $20.1 billion in 2005 and $14.7 billion
in 2004.
The 2006 increase in cash provided by operating
activities mainly reflected higher earnings in the
upstream and downstream segments, including a full year
of earnings from the former Unocal operations that were
acquired in August 2005. Cash provided by operating
activities was net of contributions to employee pension
plans of $0.4 billion, $1.0 billion and $1.6 billion in
2006, 2005 and 2004, respectively. Cash provided by
investing activities included proceeds from asset sales
of $1.0 billion in 2006, $2.7 billion in 2005 and $3.7
billion in 2004.
Cash provided by operating activities and asset
sales during 2006 was sufficient to fund the company’s
$13.8 billion capital and exploratory program, pay
$4.4 billion of dividends to stockholders, repay
approximately $2.9 billion in debt and repurchase $5
billion of common stock.
Dividends The company paid dividends of
approximately $4.4 billion in 2006, $3.8 billion in
2005 and $3.2 billion in 2004. In April 2006, the
company increased its quarterly common stock dividend
by 15.5 percent to 52 cents per share.
Debt, capital lease and minority interest
obligations Total debt and capital lease balances were
$9.8 billion at
December 31, 2006, down from $12.9 billion at year-end 2005.
The company also had minority interest obligations of
$209 million, up from $200 million at December 31,
2005.
The $3.1 billion reduction in total debt and
capital lease obligations during 2006 included the
early redemption and maturity of several individual
debt issues. In the first quarter, $185 million of
Union Oil Company bonds matured. In the second quarter,
the company redeemed approximately $1.7 billion of
Unocal debt prior to maturity. In the fourth quarter, a
$129 million Texaco Capital Inc. bond matured, and
Union Oil Company bonds of $196 million were redeemed
prior to maturity. Commercial paper balances at the end
of 2006 were reduced $626 million from year-end 2005.
In February 2007, a $144 million Texaco Capital Inc.
bond matured.
The company’s debt and capital lease obligations
due within one year, consisting primarily of
commercial paper and the current portion of long-term
debt, totaled $6.6 billion at December 31, 2006, up
from $5.6 billion at year-end 2005. Of these amounts,
$4.5 billion and $4.9 billion
were reclassified to long-term at the end of each
period, respectively. At year-end 2006, settlement of
the reclassified amount was not expected to require
the use of working capital in 2007, as the company had
the intent and the ability, as evidenced by committed
credit facilities, to refinance the amounts on a
long-term basis. The company’s practice has been to
maintain commercial paper levels it believes
appropriate and economic.
At year-end 2006, the company had $5 billion in
committed credit facilities with various major banks,
which permitted the refinancing of short-term
obligations on a long-term basis. These facilities
support commercial paper borrowings and can be used for
general corporate purposes. The company’s practice has
been to continually replace expiring commitments with
new commitments on substantially the same terms,
maintaining levels management believes appropriate. Any
borrowings under the facilities would be unsecured
indebtedness at interest rates based on 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, 2006. In addition, the company has three
existing effective “shelf” registration statements on
file with the Securities and Exchange Commission that
together would permit additional registered debt
offerings up to an aggregate $3.8 billion of debt
securities.
In 2004, Chevron entered into $1 billion of
interest rate swap transactions, in which the company
receives a fixed interest rate and pays a floating
rate, based on the notional principal amounts. Under
the terms of the swap agreements, of which $250 million
and $750 million will terminate in September 2007 and
February 2008, respectively, the net
cash settlement will be based on the difference between
fixed interest rates and floating interest rates.
FS-12
Table of Contents
The company has outstanding public bonds issued by
Chevron Corporation Profit Sharing/Savings Plan Trust
Fund, Chevron Canada Funding Company (formerly Chevron
Texaco Capital Company), Texaco Capital Inc. and Union
Oil Company of California. All of these securities are
guaranteed by Chevron Corporation and are rated AA by
Standard and Poor’s Corporation and Aa2 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, and the company’s Canadian commercial paper is
rated R-1 (middle) by Dominion Bond Rating Service. All
of these ratings denote high-quality, investment-grade
securities.
The company’s future debt level is dependent
primarily on results of operations, the
capital-spending
program and cash that may be generated from asset
dispositions. The company believes that it has
substantial borrowing capacity to meet unanticipated
cash requirements and that during periods of low
prices for crude oil and natural gas and narrow
margins for refined products and commodity chemicals,
it has the flexibility to increase borrowings and/or
modify capital-spending plans to continue paying the
common stock dividend and maintain the company’s
high-quality debt ratings.
Common stock repurchase program A $5 billion
stock repurchase program initiated in December 2005
was completed in November 2006. During 2006, about
78.5 million common shares were repurchased under this
program at a total cost of $4.9 billion.
In December 2006, the company authorized the
acquisition of up to an additional $5 billion of its
common shares from time to time at prevailing prices,
as permitted by securities laws and other legal
requirements and subject to market conditions and other
factors. The program is for a period of up to three
years and may be discontinued at any time. Under this
program, the company acquired approximately 1.3 million
shares in the open market for $100 million during
December 2006 and through mid-February 2007 increased
the total shares acquired to 8.2 million at a cost of
$592 million.
Capital and exploratory expenditures Total
reported expenditures for 2006 were $16.6 billion,
including $1.9 billion for the company’s share of
affiliates’ expenditures, which did not require cash
outlays by the company. In 2005 and 2004, expenditures
were $11.1 billion and $8.3 billion, respectively,
including the company’s share of affiliates’
expenditures of $1.7 billion and $1.6 billion in the
cor-
responding periods. The 2005 amount excludes the $17.3 billion acquisition of Unocal Corporation. Of the $16.6 billion in expenditures for 2006,
about three-fourths, or $12.8 billion, related to
upstream activities. Approximately the same percentage
was also expended for upstream operations in 2005 and
2004. International upstream accounted for about 70
percent of the worldwide upstream investment in each of
the three years, reflecting the company’s continuing
focus on opportunities that are available outside the
United States.
In 2007, the company estimates capital and
exploratory expenditures will be 18 percent higher at
$19.6 billion,
including $2.4 billion of
spending by affiliates.
About three-fourths of the
total, or $14.6 billion,
is budgeted for
exploration and production
activities, with $10.6
billion of this amount
outside the United States.
Spending in 2007 is
primarily targeted for
exploratory prospects in
the deepwater Gulf of
Mexico and western Africa
and major development
projects in Angola,
Australia, Brazil,
Kazakhstan, Nigeria, the
deepwater Gulf of Mexico
and an oil sands project
in Canada.
Worldwide downstream
spending in 2007 is
estimated at $3.8
billion, with about $1.6
billion for projects in
the United States.
Capital projects include
upgrades to refineries in
the
United States and South Korea and construction of
liquefied natural gas tankers and gas-to-liquids
facilities in support of associated upstream projects.
Investments in chemicals, technology and other
corporate businesses in 2007 are budgeted at $1.2
billion. Technology investments include projects
related to molecular transformation, unconventional
hydrocarbons, oil and gas reservoir management and development of
second-generation biofuel production.
Capital and Exploratory Expenditures
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Pension Obligations In 2006, the company’s pension
plan contributions totaled approximately $450 million.
Approximately $225 million of the total was contributed
to U.S. plans. In 2007, the company estimates total
contributions will be $500 million. Actual amounts are
dependent upon plan-investment results, changes in
pension obligations, regulatory requirements and other
economic factors. Additional funding may be required if
investment returns are insufficient to offset increases
in plan obligations. Refer also to the discussion of
pension accounting in “Critical Accounting Estimates
and Assumptions,” beginning on page FS-20.
FINANCIAL RATIOS Financial Ratios
Current Ratio – current assets divided by current liabilities. The current ratio in all periods was adversely affected by the fact that Chevron’s inventories are valued on a Last-In-First-Out basis. At year-end 2006, the book value of inventory was lower than replacement costs, based on average acquisition costs during the year, by approximately $6 billion. Interest Coverage Ratio – income before income
tax expense, plus interest and debt expense and
amortization of capitalized interest, divided by before-tax interest
costs. The interest coverage ratio was higher in 2006 compared
with 2005, primarily due to higher before-tax income and lower average
debt balances. The company’s interest coverage ratio was essentially unchanged between 2005 and 2004.
Debt Ratio – total
debt as a percentage of total debt plus equity.
The decrease between 2005 and 2006 was due to lower average debt
levels and an increase in stockholders’ equity. Although total debt was
slightly higher at the end of 2005 than a year earlier due to the assumption of
debt associated with the Unocal acquisition, the debt ratio declined as a result of higher stockholders’
equity
balances for retained earnings and the capital stock that was issued in connection with the Unocal acquisition. GUARANTEES, OFF-BALANCE-SHEET Direct or Indirect Guarantees*
* The amounts exclude indemnifications of
contingencies associated with the sale of the
company’s interest in Equilon and Motiva in 2002, as
discussed in the “Indemnifications” section on page
FS-15.
At December 31, 2006, the company and its subsidiaries provided guarantees, either directly or indirectly, of $296 million for notes and other contractual obligations of affiliated companies and $131 million for third parties, as described by major category below. There are no amounts being carried as liabilities for the company’s obligations under these guarantees. The $296 million in guarantees provided to
affiliates related to borrowings for capital projects.
These guarantees were undertaken to achieve lower
interest rates and generally cover the construction
periods of the capital projects. Included in these
amounts are the company’s guarantees of $214 million
associated with a construction completion guarantee for
the debt financing of the company’s equity interest in
the BTC crude oil pipeline project. Substantially all
of the $296 million guaranteed will expire between 2007
and 2011, with the remaining expiring by the end of
2015. Under the terms of the guarantees, the company
would be required to fulfill the guarantee should an
affiliate be in default of its loan terms, generally
for the full amounts disclosed.
The $131 million in guarantees provided on behalf
of third parties relate to construction loans to
governments of certain of the company’s international
upstream operations. Substantially all of the $131
million in guarantees expire by 2011, with the
remainder expiring by 2015. The company would be
required to perform under the terms of the guarantees
should an entity be in default of its loan or contract
terms, generally for the full amounts disclosed.
At December 31, 2006, Chevron also had
outstanding guarantees for about $120 million of
Equilon debt and leases. Following the February 2002
disposition of its interest in Equilon, the company
received an indemnification from Shell for any claims
arising from the guarantees. The company has
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not recorded a liability for these guarantees. Approximately 50 percent of the amounts guaranteed will expire within the 2007 through 2011 period, with the guarantees of the remaining amounts expiring by 2019. 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 2006, the company paid approximately
$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 relating to Equilon indemnities must be
asserted either as early as February 2007 or no later
than February 2009, and claims relating to Motiva
indemnities must be asserted either as early as
February 2007 or no later than February 2012. Under the
terms of these indemnities, there is no maximum limit
on the amount of potential future payments. The company
has not recorded any liabilities for possible claims
under these indemnities. The company posts no assets as
collateral and has made no payments under the
indemnities.
The amounts payable for the indemnities described
above are to be net of amounts recovered from insurance
carriers and others and net of liabilities recorded by
Equilon or Motiva prior to September 30, 2001, for any
applicable incident.
In the acquisition of Unocal, the company assumed
certain indemnities relating to contingent
environmental liabilities associated with assets that
were sold in 1997. Under the indemnification agreement,
the company’s liability is unlimited until April 2022,
when the liability expires. The acquirer shares in
certain environmental remediation costs up to a maximum
obligation of $200 million, which had not been reached
as of December 31, 2006.
Securitization The company securitizes certain
retail and trade accounts receivable in its downstream
business through the use of qualifying Special Purpose
Entities (SPEs). At December 31, 2006, approximately
$1.2 billion, representing about 7 percent of Chevron’s
total current accounts and notes receivable balance,
were securitized. Chevron’s total estimated financial
exposure under these securitizations at December 31,
2006, was approximately $80 million. These arrangements
have the effect of accelerating Chevron’s collection of
the securitized amounts. In the event that the SPEs
experience major defaults in the collection of
receivables, Chevron believes that it would have no loss exposure
connected with third-party investments in these
securitizations.
Long-Term Unconditional Purchase Obligations and
Commitments, Including Throughput and Take-or-Pay
Agreements The company and its subsidiaries have
certain other contingent liabilities relating to
long-term unconditional purchase obligations and
commitments, including throughput and take-or-pay
agreements, some of which relate to suppliers’
financing arrangements. The agreements typically
provide goods and services, such as pipeline and
storage capacity, drilling rigs, utilities, and
petroleum products, to be used or sold in the ordinary
course of the company’s business. The aggregate
approximate amounts of required payments under these
various commitments are: 2007 – $3.2 billion; 2008 –
$1.7 billion; 2009 – $2.1 billion; 2010 – $1.9
billion; 2011 – $0.9 billion; 2012 and after – $4.1
billion. A portion of these commitments may ultimately
be shared with project partners. Total payments under
the agreements were approximately $3.0 billion in 2006,
$2.1 billion in 2005 and $1.6 billion in 2004.
Minority Interests The company has commitments of
$209 million related to minority interests in
subsidiary companies.
The following table summarizes the company’s
significant contractual obligations:
Contractual Obligations
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