e10vk
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
þ ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2007
OR
o TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period
from
to
Commission File Number 1-368-2
Chevron Corporation
(Exact name of registrant as specified in its charter)
|
|
|
|
|
Delaware
|
|
94-0890210
|
|
6001 Bollinger Canyon Road,
San Ramon, California 94583-2324
|
|
|
|
|
|
(State or other jurisdiction of
incorporation or organization)
|
|
(I.R.S. Employer
Identification Number)
|
|
(Address of principal executive offices) (Zip Code)
|
Registrants telephone number, including area code
(925) 842-1000
Securities registered pursuant to Section 12(b) of the Act:
|
|
|
Title of Each Class
|
|
Name of Each Exchange
on Which Registered
|
|
|
|
Common stock, par value $.75 per share
|
|
New York Stock Exchange, Inc.
|
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes þ No o
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
(§ 229.405 of this chapter) is not contained herein,
and will not be contained, to the best of registrants
knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this
Form 10-K
or any amendment to this
Form 10-K. þ
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in
Rule 12b-2
of the Exchange Act. (Check one):
Large accelerated filer
þ Accelerated
filer
o
Non-accelerated filer
o Smaller
reporting company
o
(Do not check if a smaller
reporting company)
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the
Act). Yes o No þ
Aggregate market value of the voting and non-voting common
equity held by non-affiliates computed by reference to the price
at which the common equity was last sold, or the average bid and
asked price of such common equity, as of the last business day
of the registrants most recently completed second fiscal
quarter $179,575,224,370 (As of June 30, 2007)
Number of Shares of Common Stock outstanding as of
February 22, 2008 2,076,680,120
DOCUMENTS INCORPORATED BY REFERENCE
(To The Extent Indicated Herein)
Notice of the 2008 Annual Meeting and 2008 Proxy Statement, to
be filed pursuant to
Rule 14a-6(b)
under the Securities Exchange Act of 1934, in connection with
the companys 2008 Annual Meeting of Stockholders (in
Part III)
CAUTIONARY
STATEMENT RELEVANT TO FORWARD-LOOKING INFORMATION
FOR THE PURPOSE OF SAFE HARBOR PROVISIONS OF THE
PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This Annual Report on
Form 10-K
of Chevron Corporation contains forward-looking statements
relating to Chevrons operations that are based on
managements current expectations, estimates and
projections about the petroleum, chemicals and other
energy-related industries. Words such as
anticipates, expects,
intends, plans, targets,
projects, believes, seeks,
schedules, estimates,
budgets and similar expressions are intended to
identify such forward-looking statements. These statements are
not guarantees of future performance and are subject to certain
risks, uncertainties and other factors, some of which are beyond
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 margins; actions of competitors;
timing of exploration expenses; the competitiveness of alternate
energy sources or product substitutes; technological
developments; the results of operations and financial condition
of equity affiliates; the inability or failure of the
companys joint-venture partners to fund their share of
operations and development activities; the potential failure to
achieve expected net production from existing and future crude
oil and natural gas development projects; potential delays in
the development, construction or
start-up of
planned projects; the potential disruption or interruption of
the companys net production or manufacturing facilities or
delivery/transportation networks due to war, accidents,
political events, civil unrest, severe weather or crude-oil
production quotas that might be imposed by OPEC (Organization of
Petroleum Exporting Countries); the potential liability for
remedial actions under existing or future environmental
regulations and litigation; significant investment or product
changes under existing or future environmental statutes,
regulations and litigation; the potential liability resulting
from pending or future litigation; the companys
acquisition or disposition of assets; gains and losses from
asset dispositions or impairments; government-mandated sales,
divestitures, recapitalizations, changes in fiscal terms or
restrictions on scope of company operations; foreign currency
movements compared with the U.S. dollar; the effects of
changed accounting rules under generally accepted accounting
principles promulgated by rule-setting bodies; and the factors
set forth under the heading Risk Factors on pages 32
and 33 in this report. In addition, such statements could be
affected by general domestic and international economic and
political conditions. Unpredictable or unknown factors not
discussed in this report could also have material adverse
effects on forward-looking statements.
2
PART I
|
|
(a)
|
General
Development of Business
|
Summary
Description of Chevron
Chevron
Corporation,1
a Delaware corporation, manages its investments in subsidiaries
and affiliates and provides administrative, financial,
management and technology support to U.S. and international
subsidiaries that engage in fully integrated petroleum
operations, chemicals operations, mining operations, power
generation and energy services. Exploration and production
(upstream) operations consist of exploring for, developing and
producing crude oil and natural gas and also marketing natural
gas. Refining, marketing and transportation (downstream)
operations relate to refining crude oil into finished petroleum
products; marketing crude oil and the many products derived from
petroleum; and transporting crude oil, natural gas and petroleum
products by pipeline, marine vessel, motor equipment and rail
car. Chemical operations include the manufacture and marketing
of commodity petrochemicals, plastics for industrial uses, and
fuel and lubricant oil additives.
On August 10, 2005, the company acquired Unocal Corporation
(Unocal), an independent oil and gas exploration and production
company. Discussion of the Unocal acquisition is in Note 2
on
page FS-34.
A list of the companys major subsidiaries is presented on
pages E-4
and E-5. As
of December 31, 2007, Chevron had approximately
65,000 employees (including about 6,000 service station
employees). Approximately 31,000, or 48 percent, of the
companys employees were employed in U.S. operations.
Overview
of Petroleum Industry
Petroleum industry operations and profitability are influenced
by many factors, and individual petroleum companies have little
control over some of them. Governmental policies, particularly
in the areas of taxation, energy and the environment have a
significant impact on petroleum activities, regulating how
companies are structured and where and how companies conduct
their operations and formulate their products and, in some
cases, limiting their profits directly. Prices for crude oil and
natural gas, petroleum products and petrochemicals are generally
determined by supply and demand for these commodities. However,
some governments impose price controls on refined products such
as gasoline or diesel fuel. The members of the Organization of
Petroleum Exporting Countries (OPEC) are typically the
worlds swing producers of crude oil, and their production
levels are a major factor in determining worldwide supply.
Demand for crude oil and its products and for natural gas is
largely driven by the conditions of local, national and global
economies, although weather patterns and taxation relative to
other energy sources also play a significant part. Seasonality
is not a primary driver to changes in the companys
quarterly earnings during the year.
Strong competition exists in all sectors of the petroleum and
petrochemical industries in supplying the energy, fuel and
chemical needs of industry and individual consumers. Chevron
competes with fully integrated major global petroleum companies,
as well as independent and national petroleum companies, for the
acquisition of crude oil and natural gas leases and other
properties and for the equipment and labor required to develop
and operate those properties. In its downstream business,
Chevron also competes with fully integrated major petroleum
companies and other independent refining, marketing and
transportation entities in the sale or acquisition of various
goods or services in many national and international markets.
1 Incorporated
in Delaware in 1926 as Standard Oil Company of California, the
company adopted the name Chevron Corporation in 1984 and
ChevronTexaco Corporation in 2001. In 2005, ChevronTexaco
Corporation changed its name to Chevron Corporation. As used in
this report, the term Chevron and such terms as
the company, the corporation,
our, we and us may refer to
Chevron Corporation, one or more of its consolidated
subsidiaries, or all of them taken as a whole, but unless stated
otherwise, it does not include affiliates of
Chevron i.e., those companies accounted for by the
equity method (generally owned 50 percent or less) or
investments accounted for by the cost method. All of these terms
are used for convenience only and are not intended as a precise
description of any of the separate companies, each of which
manages its own affairs.
3
Operating
Environment
Refer to pages FS-2 through FS-8 of this
Form 10-K
in Managements Discussion and Analysis of Financial
Condition and Results of Operations for a discussion of the
companys current business environment and outlook.
Chevron
Strategic Direction
Chevrons 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 has established the following
strategies:
Strategies
for Major Businesses
|
|
|
|
|
Upstream grow profitably in core
areas, build new legacy positions and commercialize the
companys natural gas equity resource base while growing a
high-impact global gas business
|
|
|
|
Downstream improve base-business
returns and selectively grow, with a focus on integrated value
creation
|
The company also continues to invest in renewable-energy
technologies, with an objective of capturing profitable
positions in important renewable sources of energy.
Enabling
Strategies Companywide
|
|
|
|
|
Invest in people to achieve the companys
strategies
|
|
|
|
Leverage technology to deliver superior
performance and growth
|
|
|
|
Build organizational capability to deliver
world-class performance in operational excellence, cost
reduction, capital stewardship and profitable growth
|
|
|
(b)
|
Description
of Business and Properties
|
The upstream, downstream and chemicals activities of the company
and its equity affiliates are widely dispersed geographically,
with operations in North America, South America, Europe, Africa,
the Middle East, Asia and Australasia. Tabulations of segment
sales and other operating revenues, earnings and income taxes
for the three years ending December 31, 2007, and assets as
of the end of 2007 and 2006 for the United States
and the companys international geographic
areas are in Note 8 to the Consolidated
Financial Statements beginning on
page FS-37.
In addition, similar comparative data for the companys
investments in and income from equity affiliates and property,
plant and equipment are in Notes 11 and 12 on pages FS-40
to FS-42.
Capital
and Exploratory Expenditures
Total reported expenditures for 2007 were $20 billion,
including $2.3 billion for Chevrons share of
expenditures by affiliated companies, which did not require cash
outlays by the company. In 2006 and 2005, expenditures were
$16.6 billion and $11.1 billion, respectively,
including the companys share of affiliates
expenditures of $1.9 billion and $1.7 billion in the
corresponding periods. The 2005 amount excludes
$17.3 billion for the acquisition of Unocal.
Of the $20 billion in expenditures for 2007,
78 percent, or $15.5 billion, related to upstream
activities. Approximately the same percentage was also expended
for upstream operations in 2006 and 2005. International upstream
accounted for about 70 percent of the worldwide upstream
investment in each of the three years, reflecting the
companys continuing focus on opportunities that are
available outside the United States.
In 2008, the company estimates capital and exploratory
expenditures will be 15 percent higher at
$22.9 billion, including $2.6 billion of spending by
affiliates. About three-fourths of the total, or
$17.5 billion, is budgeted for exploration and production
activities, with $12.7 billion of that amount outside the
United States.
Refer also to a discussion of the companys capital and
exploratory expenditures on
page FS-12.
Upstream
Exploration and Production
The table on the following page summarizes the net production of
liquids and natural gas for 2007 and 2006 by the company and its
affiliates.
4
Net
Production of Crude Oil and Natural Gas Liquids and Natural
Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Components of Oil-Equivalent
|
|
|
|
|
|
|
Crude Oil & Natural Gas
|
|
|
|
|
|
|
Oil-Equivalent (Thousands
|
|
|
Liquids (Thousands of
|
|
|
Natural Gas (Millions of
|
|
|
|
of Barrels per Day)
|
|
|
Barrels per Day)
|
|
|
Cubic Feet per Day)
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
United States:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
California
|
|
|
221
|
|
|
|
224
|
|
|
|
205
|
|
|
|
207
|
|
|
|
97
|
|
|
|
101
|
|
Gulf of Mexico
|
|
|
214
|
|
|
|
224
|
|
|
|
118
|
|
|
|
114
|
|
|
|
576
|
|
|
|
661
|
|
Texas (Onshore)
|
|
|
153
|
|
|
|
150
|
|
|
|
77
|
|
|
|
79
|
|
|
|
457
|
|
|
|
425
|
|
Other States
|
|
|
155
|
|
|
|
165
|
|
|
|
60
|
|
|
|
62
|
|
|
|
569
|
|
|
|
623
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total United States
|
|
|
743
|
|
|
|
763
|
|
|
|
460
|
|
|
|
462
|
|
|
|
1,699
|
|
|
|
1,810
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Africa:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Angola
|
|
|
179
|
|
|
|
164
|
|
|
|
171
|
|
|
|
156
|
|
|
|
48
|
|
|
|
47
|
|
Nigeria
|
|
|
129
|
|
|
|
144
|
|
|
|
126
|
|
|
|
139
|
|
|
|
15
|
|
|
|
29
|
|
Chad
|
|
|
32
|
|
|
|
35
|
|
|
|
31
|
|
|
|
34
|
|
|
|
4
|
|
|
|
4
|
|
Republic of the Congo
|
|
|
8
|
|
|
|
12
|
|
|
|
7
|
|
|
|
11
|
|
|
|
7
|
|
|
|
8
|
|
Democratic Republic of the Congo
|
|
|
3
|
|
|
|
3
|
|
|
|
3
|
|
|
|
3
|
|
|
|
2
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Africa
|
|
|
351
|
|
|
|
358
|
|
|
|
338
|
|
|
|
343
|
|
|
|
76
|
|
|
|
90
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asia-Pacific:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Thailand
|
|
|
224
|
|
|
|
216
|
|
|
|
71
|
|
|
|
73
|
|
|
|
916
|
|
|
|
856
|
|
Partitioned Neutral Zone
(PNZ)1
|
|
|
112
|
|
|
|
114
|
|
|
|
109
|
|
|
|
111
|
|
|
|
17
|
|
|
|
19
|
|
Australia
|
|
|
100
|
|
|
|
99
|
|
|
|
39
|
|
|
|
39
|
|
|
|
372
|
|
|
|
360
|
|
Kazakhstan
|
|
|
66
|
|
|
|
62
|
|
|
|
41
|
|
|
|
38
|
|
|
|
149
|
|
|
|
143
|
|
Azerbaijan
|
|
|
61
|
|
|
|
47
|
|
|
|
60
|
|
|
|
46
|
|
|
|
5
|
|
|
|
4
|
|
Bangladesh
|
|
|
47
|
|
|
|
21
|
|
|
|
2
|
|
|
|
|
|
|
|
275
|
|
|
|
126
|
|
China
|
|
|
26
|
|
|
|
26
|
|
|
|
22
|
|
|
|
23
|
|
|
|
22
|
|
|
|
18
|
|
Philippines
|
|
|
26
|
|
|
|
24
|
|
|
|
5
|
|
|
|
6
|
|
|
|
126
|
|
|
|
108
|
|
Myanmar
|
|
|
17
|
|
|
|
15
|
|
|
|
|
|
|
|
|
|
|
|
100
|
|
|
|
89
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Asia-Pacific
|
|
|
679
|
|
|
|
624
|
|
|
|
349
|
|
|
|
336
|
|
|
|
1,982
|
|
|
|
1,723
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Indonesia
|
|
|
241
|
|
|
|
248
|
|
|
|
195
|
|
|
|
198
|
|
|
|
277
|
|
|
|
302
|
|
Other International:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United Kingdom
|
|
|
115
|
|
|
|
115
|
|
|
|
78
|
|
|
|
75
|
|
|
|
220
|
|
|
|
242
|
|
Denmark
|
|
|
63
|
|
|
|
68
|
|
|
|
41
|
|
|
|
44
|
|
|
|
132
|
|
|
|
146
|
|
Argentina
|
|
|
47
|
|
|
|
47
|
|
|
|
39
|
|
|
|
38
|
|
|
|
50
|
|
|
|
54
|
|
Canada
|
|
|
36
|
|
|
|
47
|
|
|
|
35
|
|
|
|
46
|
|
|
|
5
|
|
|
|
6
|
|
Colombia
|
|
|
30
|
|
|
|
29
|
|
|
|
|
|
|
|
|
|
|
|
178
|
|
|
|
174
|
|
Trinidad and Tobago
|
|
|
29
|
|
|
|
29
|
|
|
|
|
|
|
|
|
|
|
|
174
|
|
|
|
174
|
|
Norway
|
|
|
6
|
|
|
|
6
|
|
|
|
6
|
|
|
|
6
|
|
|
|
1
|
|
|
|
1
|
|
Netherlands
|
|
|
4
|
|
|
|
4
|
|
|
|
3
|
|
|
|
3
|
|
|
|
5
|
|
|
|
7
|
|
Venezuela2
|
|
|
|
|
|
|
7
|
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Other International
|
|
|
330
|
|
|
|
352
|
|
|
|
202
|
|
|
|
215
|
|
|
|
765
|
|
|
|
825
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total International
|
|
|
1,601
|
|
|
|
1,582
|
|
|
|
1,084
|
|
|
|
1,092
|
|
|
|
3,100
|
|
|
|
2,940
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Consolidated Operations
|
|
|
2,344
|
|
|
|
2,345
|
|
|
|
1,544
|
|
|
|
1,554
|
|
|
|
4,799
|
|
|
|
4,750
|
|
Equity
Affiliates3
|
|
|
248
|
|
|
|
213
|
|
|
|
212
|
|
|
|
178
|
|
|
|
220
|
|
|
|
206
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Including
Affiliates4,5
|
|
|
2,592
|
|
|
|
2,558
|
|
|
|
1,756
|
|
|
|
1,732
|
|
|
|
5,019
|
|
|
|
4,956
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
Located between Saudi Arabia and
Kuwait.
|
2 |
|
Through September 2006, LL-652 was
reported as part of Venezuela consolidated operations. As of
October 2006, LL-652 is reported under Equity Affiliates. See
footnote 3 below.
|
3 |
|
Equity Affiliates represent
Chevrons share of production by affiliates, including
Tengizchevroil (TCO) in Kazakhstan and Hamaca in Venezuela.
Effective October 2006, the company converted its interests in
Boscan and LL-652 operating service agreements in Venezuela to
Empresas Mixtas (i.e., joint stock contractual structures), and
these interests are accounted for as equity affiliates.
LL-652 was
previously reported as part of Venezuela consolidated
operations, and Boscan was included in other produced
volumes. See footnote 5 below.
|
4 |
|
Includes natural gas consumed in
operations of 498 million and 475 million cubic feet
per day in 2007 and 2006, respectively.
|
5 |
|
Does not include other produced
volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Athabasca Oil Sands net
|
|
|
27
|
|
|
|
27
|
|
|
|
27
|
|
|
|
27
|
|
|
|
|
|
|
|
|
|
Boscan Operating Service
Agreement3
|
|
|
|
|
|
|
82
|
|
|
|
|
|
|
|
82
|
|
|
|
|
|
|
|
|
|
5
As shown in the table on page 5, worldwide oil-equivalent
production of 2.59 million barrels per day in 2007 was up
34,000 barrels per day from the prior year. Worldwide
oil-equivalent production including other produced
volumes (refer to footnote 5 to the table on
page 5) was 2.62 million barrels per day, down
about 2 percent from 2006. The decline was mostly
attributable to the change in the Boscan operating service
agreement in Venezuela to a joint-stock company in October 2006.
Refer to the Results of Operations section beginning
on
page FS-6
for a detailed discussion of the factors explaining the
20052007 changes in production for crude oil and natural
gas liquids and natural gas.
The company estimates that its average worldwide oil-equivalent
production in 2008 will be approximately 2.65 million
barrels per day. This estimate is subject to many uncertainties,
including quotas that may be imposed by OPEC, the price effect
on production volumes calculated under cost-recovery and
variable-royalty provisions of certain contracts, changes in
fiscal terms or restrictions on the scope of company operations,
delays in project
start-ups,
and production that may have to be shut in due to weather
conditions, civil unrest, changing geopolitics or other
disruptions to operations. Future production levels also are
affected by the size and number of economic investment
opportunities and, for new large-scale projects, the time lag
between initial exploration and the beginning of production.
Refer to the Review of Ongoing Exploration and Production
Activities in Key Areas, beginning on page 9, for a
discussion of the companys major oil and gas development
projects.
Average
Sales Prices and Production Costs per Unit of
Production
Refer to Table IV on
page FS-66
for data about the companys average sales price per barrel
of crude oil and natural gas liquids and per thousand cubic feet
of natural gas produced and the average production cost per
oil-equivalent barrel for 2007, 2006 and 2005.
Gross and
Net Productive Wells
The following table summarizes gross and net productive wells at
year-end 2007 for the company and its affiliates:
Productive
Oil and Gas
Wells1
at December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive2
|
|
|
Productive2
|
|
|
|
Oil Wells
|
|
|
Gas Wells
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
United States:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
California
|
|
|
25,029
|
|
|
|
23,305
|
|
|
|
176
|
|
|
|
44
|
|
Gulf of Mexico
|
|
|
1,600
|
|
|
|
1,375
|
|
|
|
1,104
|
|
|
|
893
|
|
Other U.S.
|
|
|
23,628
|
|
|
|
8,537
|
|
|
|
10,929
|
|
|
|
5,106
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total United States
|
|
|
50,257
|
|
|
|
33,217
|
|
|
|
12,209
|
|
|
|
6,043
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Africa
|
|
|
2,190
|
|
|
|
748
|
|
|
|
8
|
|
|
|
3
|
|
Asia-Pacific
|
|
|
2,405
|
|
|
|
1,139
|
|
|
|
2,308
|
|
|
|
1,451
|
|
Indonesia
|
|
|
8,150
|
|
|
|
7,991
|
|
|
|
211
|
|
|
|
170
|
|
Other International
|
|
|
1,042
|
|
|
|
660
|
|
|
|
256
|
|
|
|
106
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total International
|
|
|
13,787
|
|
|
|
10,538
|
|
|
|
2,783
|
|
|
|
1,730
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Consolidated Companies
|
|
|
64,044
|
|
|
|
43,755
|
|
|
|
14,992
|
|
|
|
7,773
|
|
Equity in Affiliates
|
|
|
1,072
|
|
|
|
375
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Including Affiliates
|
|
|
65,116
|
|
|
|
44,130
|
|
|
|
14,992
|
|
|
|
7,773
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Multiple completion wells included above:
|
|
|
967
|
|
|
|
587
|
|
|
|
456
|
|
|
|
340
|
|
|
|
|
1 |
|
Includes wells producing or capable
of producing and injection wells temporarily functioning as
producing wells. Wells that produce both oil and gas are
classified as oil wells.
|
2 |
|
Gross wells include the total
number of wells in which the company has an interest. Net wells
include wholly owned wells and the sum of the companys
fractional interests in gross wells.
|
Reserves
Table V, beginning on
page FS-66,
provides a tabulation of the companys proved net oil and
gas reserves, by geographic area, as of each year-end 2004
through 2007, and an accompanying discussion of major changes to
proved reserves by geographic area for the three-year period.
During 2007, the company provided oil and gas reserves estimates
6
for 2006 to the Department of Energy, Energy Information
Administration (EIA), that agree with the 2006 reserve volumes
in Table V. This reporting fulfilled the requirement that such
estimates are to be consistent with, and do not differ more than
5 percent from, the information furnished to the Securities
and Exchange Commission in the companys 2006 Annual Report
on
Form 10-K.
During 2008, the company will file estimates of oil and gas
reserves with the Department of Energy, EIA, consistent with the
2007 reserve data reported in Table V.
The net proved-reserve balances at the end of each of the three
years 2005 through 2007 are shown in the table below:
Net
Proved Reserves at December 31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Liquids* Millions of barrels
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated Companies
|
|
|
4,665
|
|
|
|
5,294
|
|
|
|
5,626
|
|
Affiliated Companies
|
|
|
2,422
|
|
|
|
2,512
|
|
|
|
2,374
|
|
Natural Gas Billions of cubic feet
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated Companies
|
|
|
19,137
|
|
|
|
19,910
|
|
|
|
20,466
|
|
Affiliated Companies
|
|
|
3,003
|
|
|
|
2,974
|
|
|
|
2,968
|
|
Total Oil-Equivalent Millions of barrels
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated Companies
|
|
|
7,855
|
|
|
|
8,612
|
|
|
|
9,037
|
|
Affiliated Companies
|
|
|
2,922
|
|
|
|
3,008
|
|
|
|
2,869
|
|
|
|
|
*
|
|
Crude oil, condensate and natural
gas liquids
|
Acreage
At December 31, 2007, the company owned or had under lease
or similar agreements undeveloped and developed oil and gas
properties located throughout the world. The geographical
distribution of the companys acreage is shown in the
following table.
Acreage1
at December 31, 2007
(Thousands
of Acres)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed and
|
|
|
|
Undeveloped2
|
|
|
Developed2
|
|
|
Undeveloped
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
United States:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
California
|
|
|
139
|
|
|
|
122
|
|
|
|
185
|
|
|
|
178
|
|
|
|
324
|
|
|
|
300
|
|
Gulf of Mexico
|
|
|
2,482
|
|
|
|
1,828
|
|
|
|
1,621
|
|
|
|
1,178
|
|
|
|
4,103
|
|
|
|
3,006
|
|
Other U.S.
|
|
|
3,800
|
|
|
|
3,012
|
|
|
|
5,884
|
|
|
|
2,588
|
|
|
|
9,684
|
|
|
|
5,600
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total United States
|
|
|
6,421
|
|
|
|
4,962
|
|
|
|
7,690
|
|
|
|
3,944
|
|
|
|
14,111
|
|
|
|
8,906
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Africa
|
|
|
17,391
|
|
|
|
7,619
|
|
|
|
2,520
|
|
|
|
922
|
|
|
|
19,911
|
|
|
|
8,541
|
|
Asia-Pacific
|
|
|
52,006
|
|
|
|
23,660
|
|
|
|
5,847
|
|
|
|
2,630
|
|
|
|
57,853
|
|
|
|
26,290
|
|
Indonesia
|
|
|
9,109
|
|
|
|
5,894
|
|
|
|
382
|
|
|
|
340
|
|
|
|
9,491
|
|
|
|
6,234
|
|
Other International
|
|
|
35,688
|
|
|
|
20,022
|
|
|
|
2,397
|
|
|
|
664
|
|
|
|
38,085
|
|
|
|
20,686
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total International
|
|
|
114,194
|
|
|
|
57,195
|
|
|
|
11,146
|
|
|
|
4,556
|
|
|
|
125,340
|
|
|
|
61,751
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Consolidated Companies
|
|
|
120,615
|
|
|
|
62,157
|
|
|
|
18,836
|
|
|
|
8,500
|
|
|
|
139,451
|
|
|
|
70,657
|
|
Equity in Affiliates
|
|
|
647
|
|
|
|
302
|
|
|
|
252
|
|
|
|
103
|
|
|
|
899
|
|
|
|
405
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Including Affiliates
|
|
|
121,262
|
|
|
|
62,459
|
|
|
|
19,088
|
|
|
|
8,603
|
|
|
|
140,350
|
|
|
|
71,062
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
Gross acreage includes the total
number of acres in all tracts in which the company has an
interest. Net acreage includes wholly owned interests and the
sum of the companys fractional interests in gross acreage.
|
2 |
|
Developed acreage is spaced or
assignable to productive wells. Undeveloped acreage is acreage
on which wells have not been drilled or completed to permit
commercial production and that may contain undeveloped proved
reserves. The gross undeveloped acres that will expire in 2008,
2009 and 2010 if production is not established by certain
required dates are 7,770, 10,860 and 4,288, respectively.
|
7
Contract
Obligations
The company sells crude oil and natural gas from its producing
operations under a variety of contractual obligations. Most
contracts generally commit the company to sell quantities based
on production from specified properties, but some natural gas
sales contracts specify delivery of fixed and determinable
quantities.
In the United States, the company is contractually committed to
deliver to third parties and affiliates approximately
456 billion cubic feet of natural gas through 2010. The
company believes it can satisfy these contracts from quantities
available from production of the companys 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
631 billion cubic feet of natural gas from 2008 through
2010 from Argentina, Australia, Canada, Colombia, Denmark and
the Philippines. The sales contracts contain variable pricing
formulas that are generally referenced to the prevailing market
price for crude oil, natural gas or other petroleum products at
the time of delivery and in some cases consider inflation or
other factors. The company believes it can satisfy these
contracts from quantities available from production of the
companys proved developed reserves in Argentina,
Australia, Colombia, Denmark and the Philippines. The company
plans to meet its Canadian contractual delivery commitments of
30 billion cubic feet through third-party purchases.
Development
Activities
Details of the companys development expenditures and costs
of proved property acquisitions for 2007, 2006 and 2005 are
presented in Table I on
page FS-61.
The table below summarizes the companys net interest in
productive and dry development wells completed in each of the
past three years and the status of the companys
development wells drilling at December 31, 2007. A
development well is a well drilled within the proved
area of a crude oil or natural gas reservoir to the depth of a
stratigraphic horizon known to be productive.
Development
Well Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wells Drilling
|
|
|
Net Wells
Completed1,2
|
|
|
|
at
12/31/073
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
Gross
|
|
|
Net
|
|
|
Prod.
|
|
|
Dry
|
|
|
Prod.
|
|
|
Dry
|
|
|
Prod.
|
|
|
Dry
|
|
|
United States:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
California
|
|
|
5
|
|
|
|
1
|
|
|
|
620
|
|
|
|
|
|
|
|
600
|
|
|
|
|
|
|
|
661
|
|
|
|
|
|
Gulf of Mexico
|
|
|
39
|
|
|
|
18
|
|
|
|
30
|
|
|
|
1
|
|
|
|
34
|
|
|
|
5
|
|
|
|
29
|
|
|
|
3
|
|
Other U.S.
|
|
|
11
|
|
|
|
10
|
|
|
|
225
|
|
|
|
4
|
|
|
|
317
|
|
|
|
6
|
|
|
|
256
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total United States
|
|
|
55
|
|
|
|
29
|
|
|
|
875
|
|
|
|
5
|
|
|
|
951
|
|
|
|
11
|
|
|
|
946
|
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Africa
|
|
|
8
|
|
|
|
3
|
|
|
|
43
|
|
|
|
|
|
|
|
45
|
|
|
|
2
|
|
|
|
38
|
|
|
|
|
|
Asia-Pacific
|
|
|
13
|
|
|
|
4
|
|
|
|
223
|
|
|
|
|
|
|
|
235
|
|
|
|
1
|
|
|
|
150
|
|
|
|
|
|
Indonesia
|
|
|
|
|
|
|
|
|
|
|
374
|
|
|
|
|
|
|
|
258
|
|
|
|
|
|
|
|
107
|
|
|
|
|
|
Other International
|
|
|
4
|
|
|
|
|
|
|
|
52
|
|
|
|
|
|
|
|
43
|
|
|
|
|
|
|
|
79
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total International
|
|
|
25
|
|
|
|
7
|
|
|
|
692
|
|
|
|
|
|
|
|
581
|
|
|
|
3
|
|
|
|
374
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Consolidated Companies
|
|
|
80
|
|
|
|
36
|
|
|
|
1,567
|
|
|
|
5
|
|
|
|
1,532
|
|
|
|
14
|
|
|
|
1,320
|
|
|
|
7
|
|
Equity in Affiliates
|
|
|
|
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
13
|
|
|
|
|
|
|
|
23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Including Affiliates
|
|
|
80
|
|
|
|
36
|
|
|
|
1,570
|
|
|
|
5
|
|
|
|
1,545
|
|
|
|
14
|
|
|
|
1,343
|
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
Indicates the fractional number of
wells completed during the year, regardless of when drilling was
initiated. Completion refers to the installation of permanent
equipment for the production of crude oil or natural gas or, in
the case of a dry well, the reporting of abandonment to the
appropriate agency.
|
2 |
|
Includes completion of wells
beginning August 2005 related to the former Unocal operations.
|
3 |
|
Represents wells in the process of
drilling, including wells for which drilling was not completed
and which were temporarily suspended at the end of 2007. Gross
wells include the total number of wells in which the company has
an interest. Net wells include wholly owned wells and the sum of
the companys fractional interests in gross wells.
|
8
Exploration
Activities
The following table summarizes the companys net interests
in productive and dry exploratory wells completed in each of the
last three years and the number of exploratory wells drilling at
December 31, 2007. Exploratory wells are wells
drilled to find and produce crude oil or natural gas in unproved
areas and include delineation wells, which are wells drilled to
find a new reservoir in a field previously found to be
productive of crude oil or natural gas in another reservoir or
to extend a known reservoir beyond the proved area.
Exploratory
Well Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wells
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling
|
|
|
Net Wells
Completed1,2
|
|
|
|
at
12/31/073
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
Gross
|
|
|
Net
|
|
|
Prod.
|
|
|
Dry
|
|
|
Prod.
|
|
|
Dry
|
|
|
Prod.
|
|
|
Dry
|
|
|
United States:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
California
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf of Mexico
|
|
|
12
|
|
|
|
5
|
|
|
|
4
|
|
|
|
7
|
|
|
|
9
|
|
|
|
8
|
|
|
|
14
|
|
|
|
8
|
|
Other U.S.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
7
|
|
|
|
|
|
|
|
5
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total United States
|
|
|
12
|
|
|
|
5
|
|
|
|
4
|
|
|
|
8
|
|
|
|
16
|
|
|
|
8
|
|
|
|
19
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Africa
|
|
|
35
|
|
|
|
15
|
|
|
|
6
|
|
|
|
2
|
|
|
|
1
|
|
|
|
|
|
|
|
4
|
|
|
|
1
|
|
Asia-Pacific
|
|
|
1
|
|
|
|
1
|
|
|
|
14
|
|
|
|
10
|
|
|
|
18
|
|
|
|
7
|
|
|
|
10
|
|
|
|
|
|
Indonesia
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
5
|
|
|
|
|
|
Other International
|
|
|
3
|
|
|
|
1
|
|
|
|
5
|
|
|
|
2
|
|
|
|
6
|
|
|
|
3
|
|
|
|
7
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total International
|
|
|
39
|
|
|
|
17
|
|
|
|
26
|
|
|
|
14
|
|
|
|
27
|
|
|
|
10
|
|
|
|
26
|
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Consolidated Companies
|
|
|
51
|
|
|
|
22
|
|
|
|
30
|
|
|
|
22
|
|
|
|
43
|
|
|
|
18
|
|
|
|
45
|
|
|
|
19
|
|
Equity in Affiliates
|
|
|
|
|
|
|
|
|
|
|
41
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Including Affiliates
|
|
|
51
|
|
|
|
22
|
|
|
|
71
|
|
|
|
22
|
|
|
|
44
|
|
|
|
18
|
|
|
|
53
|
|
|
|
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
Indicates the fractional number of
wells completed during the year, regardless of when drilling was
initiated. Completion refers to the installation of permanent
equipment for the production of crude oil or natural gas or, in
the case of a dry well, the reporting of abandonment to the
appropriate agency. Some exploratory wells are not drilled with
the intention of producing from the well bore. In such cases,
completion refers to the completion of drilling.
Further categorization of productive or dry is based on the
determination as to whether hydrocarbons in a sufficient
quantity were found to justify completion as a producing well,
whether or not the well is actually going to be completed as a
producer.
|
2 |
|
Includes completion of wells
beginning August 2005 related to the former Unocal operations.
|
3 |
|
Represents wells that are in the
process of drilling but have been neither abandoned nor
completed as of the last day of the year, including wells for
which drilling was not completed and which were temporarily
suspended at the end of 2007. Does not include wells for which
drilling was completed at year-end 2007 and that were reported
as suspended wells in Note 19 beginning on
page FS-47.
Gross wells include the total number of wells in which the
company has an interest. Net wells include wholly owned wells
and the sum of the companys fractional interests in gross
wells.
|
Details of the companys exploration expenditures and costs
of unproved property acquisitions for 2007, 2006 and 2005 are
presented in Table I on
page FS-61.
Review of
Ongoing Exploration and Production Activities in Key
Areas
Chevrons 2007 key upstream activities, some of which are
also discussed in Managements Discussion and Analysis of
Financial Condition and Results of Operations beginning on
page FS-2,
are presented below. The comments include references to
total production and net production,
which are defined under Production in
Exhibit 99.1 on
page E-23.
The discussion that follows references the status of proved
reserves recognition for significant long-lead-time projects not
yet on production and for projects recently placed on
production. Reserves are not discussed for recent discoveries
that have yet to advance to a project stage or for mature areas
of production that do not have individual projects requiring
significant levels of capital or exploratory investment. Amounts
indicated for project costs represent total project costs, not
the companys share of costs for projects that are less
than wholly owned. In addition to the activities discussed,
Chevron was active in other geographic areas, but those
activities are considered less significant.
9
Consolidated
Operations
|
|
|
|
|
Chevron has production and exploration activities in most of the worlds major hydrocarbon basins. The companys upstream strategy is to grow profitably in core areas, build new legacy positions and commercialize the companys natural gas equity resource base while growing a high-impact global gas business. The map on the left indicates Chevrons primary areas of production
and exploration as well as the potential target markets for the companys natural gas resources.
|
Upstream activities in the United States are concentrated in
California, the Gulf of Mexico, Louisiana, Texas, New Mexico,
the Rocky Mountains and Alaska. Average net oil-equivalent
production during 2007 was 743,000 barrels per day,
composed of 460,000 barrels of crude oil and natural gas
liquids and 1.7 billion cubic feet of natural gas. Refer to
Table V beginning on
page FS-66
for a discussion of the net proved reserves and different
hydrocarbon characteristics for the companys major
U.S. producing areas.
|
|
|
|
|
California: The company has significant production
in
the San Joaquin Valley. In 2007, average net
oil-equivalent
production was 221,000 barrels per day, composed of
200,000 barrels of crude oil, 97 million cubic feet of
natural gas and 5,000 barrels of natural gas liquids.
Approximately 80 percent of the
crude-oil
production is considered heavy oil (typically with API gravity
lower than 22 degrees).
|
10
|
|
|
|
|
Gulf of Mexico: Average net oil-equivalent production during 2007 for the companys combined interests in the Gulf of Mexico shelf and deepwater areas, and the onshore fields in the region was 214,000 barrels per day. The daily oil-equivalent production comprised 105,000 barrels of crude oil, 576 million cubic feet of natural gas and 13,000 barrels of natural gas
liquids.
During 2007, Chevron was engaged in various 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 the third quarter 2009. Construction of
|
the spar hull and topsides was completed in 2007; however,
installation of the spar hull was delayed for about one year
when testing revealed a metallurgical problem with the mooring
shackles. Six development wells were drilled in 2007, and
flow-back tests for five of the six were completed during the
year. 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. The total cost for this project is estimated at
$4.7 billion and includes a planned second phase of field
development after
start-up
that involves additional wells and facility upgrades.
|
Also under development is the 75 percent-owned and operated
Blind Faith discovery, in which the company increased its
ownership from 63 percent in July 2007. Three development
wells were drilled, and construction of the topsides and hull
was completed in 2007. The project includes a subsea development
plan, with tieback to a semisubmersible floating production
facility that had an original daily-production design capacity
of 45,000 barrels of crude oil and 45 million cubic
feet of natural gas based on the initial three-well development
program. A fourth development well and associated facility
upgrades are planned to commence in the first half of 2008. The
facility upgrades are planned to increase the daily capacity to
60,000 barrels of crude oil and 60 million cubic feet
of natural gas. Initial daily total production, including the
fourth well, is estimated at 45,000 to 60,000 barrels of
crude oil and 45 million to 60 million cubic feet of
natural gas. Proved undeveloped reserves for the project were
recognized in 2005. Reclassification of the reserves to the
proved developed category is anticipated near the time of
production
start-up in
the second quarter 2008. The estimated production life of the
field is approximately 20 years.
The company is also participating in the ultra-deep Perdido
Regional Development. The project encompasses the installation
of a producing host facility to service multiple fields,
including Chevrons 33 percent-owned Great White,
60 percent-owned Silvertip and 58 percent-owned
Tobago. Chevron has a 38 percent interest in the Perdido
Regional Host. All of these fields and the production facility
are partner-operated. Activities during 2007 included facility
construction and development drilling. First oil is expected in
2010, with the facility capable of handling 130,000 barrels
of oil-equivalent per day. Proved undeveloped reserves related
to the project were first recorded in 2006, and the phased
reclassification of these reserves to the proved developed
category is anticipated near the time of production
start-up.
The project has an expected life of approximately 25 years.
Deepwater exploration activities in 2007 included participation
in 12 exploratory wells six wildcat and six
appraisal. Exploratory work included the following:
|
|
|
|
|
Big Foot 60 percent-owned and operated. A
successful appraisal well was completed in January 2008.
|
|
|
|
Jack 50 percent-owned and operated. A
second appraisal well is scheduled for completion in the second
quarter 2008.
|
|
|
|
Saint Malo 41 percent-owned and
operated. Located near the Jack discovery, a second
appraisal well drilled in 2007 is scheduled for completion by
the end of the first quarter 2008.
|
|
|
|
Tubular Bells 30 percent-owned and nonoperated
working interest. The second appraisal well began drilling in
2007 and is scheduled for completion in the first quarter 2008.
|
|
|
|
Knotty Head 25 percent-owned and nonoperated
working interest. Discovered in 2005, subsurface studies were in
progress in early 2008.
|
|
|
|
Puma 22 percent-owned and nonoperated working
interest. Two appraisal wells were drilled in 2007.
|
11
|
|
|
|
|
West Tonga 21 percent-owned and nonoperated
working interest. A successful discovery well was drilled in
2007.
|
At the end of 2007, the company had not yet recognized proved
reserves for any of the exploration projects discussed above.
Besides the activities connected with the development and
exploration projects in the Gulf of Mexico area, Chevron also
continued the federal, state and local permitting process during
2007 and early 2008 for a proposed natural gas import terminal
at Casotte Landing in Jackson County, Mississippi. In February
2007, the company received approval from the Federal Energy
Regulatory Commission for the proposed terminal. The terminal
would be located adjacent to the companys Pascagoula
Refinery and 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. The decision to
construct a facility will be timed to align with the
companys LNG supply projects.
The company also has contractual rights to 1 billion cubic
feet per day of regasification capacity beginning in 2009 at the
third party-owned Sabine Pass LNG terminal that is expected to
be commissioned in the second quarter 2008. Also in the Sabine
Pass area in Louisiana, the company has a binding agreement to
be one of the anchor shippers in a
3.2 billion-cubic-foot-per-day third party-owned natural
gas pipeline. Chevron will have 1.6 billion cubic feet per
day of capacity in the pipeline, of which 1 billion cubic
feet per day is in a new pipeline and 600 million cubic
feet per day is interconnecting capacity to an existing
pipeline. The new pipeline system will provide access to
Chevrons Sabine and Bridgeline pipelines, which connect to
the Henry Hub. 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 across the
mid-continental United States and Alaska. During 2007 in the
Piceance Basin of northwestern Colorado, the company commenced
development drilling in the basins tight-gas formation.
Facilities to produce 50 million cubic feet of natural gas
per day are expected to start up in 2009. The Piceance project,
in which the company holds a 100 percent operated working
interest, is scalable, and the work is planned to be completed
in multiple phases over the 15- to
20-year
project life. The plans include expanding facilities to a
production capacity of 450 million cubic feet per day. The
total cost for this project is estimated at $7.3 billion.
Also during 2007, Chevron initiated redevelopment programs in
three offshore fields in Alaskas Cook Inlet, where the
company operates 10 offshore platforms and five producing
natural gas fields. The company also owns nonoperated working
interest production and exploratory acreage at the White Hills
prospect on the North Slope of Alaska. During 2007, the
companys production outside California and the Gulf of
Mexico averaged 308,000 net oil-equivalent barrels per day,
composed of 104,000 barrels of crude oil, 1 billion
cubic feet of natural gas and 33,000 barrels of natural gas
liquids.
12
|
|
|
|
|
Angola: Chevron holds company-operated working interests in Blocks 0 and 14 and nonoperated working interests in Block 2 and the Fina Sonangol Texaco (FST) area. In 2007, daily net production was 179,000 barrels of oil-equivalent.
The 39 percent-owned Block 0 and 31 percent-owned Block 14 are off the west coast, north of the Congo River. In
Block 0, the company operates in two areas A and B composed of 21 fields that produced 120,000 barrels per day of net liquids in 2007. The Block 0 concession extends through 2030.
Area A of Block 0 comprises 15 producing fields and averaged daily net production of approximately 65,000 barrels of crude oil and 1,000 barrels of liquefied petroleum
gas (LPG) in 2007. This production includes volumes from the Banzala Field that produced first oil in June 2007. The development of the Mafumeira Field in Area A continued in 2007 and will target the northern portion of the field. Initial booking of proved
|
undeveloped reserves for this development occurred in 2003, and
reclassification of proved undeveloped reserves into the proved
developed category is anticipated near the time of first
production expected in 2009. Maximum total daily production is
expected to be approximately 30,000 barrels of crude oil in
2011.
|
Also in Area A, construction continued during 2007 on the Takula
Gas Processing Platform and on projects for the Cabinda Gas
Plant and the Flare and Relief Modification. These three
projects, called the Area A Gas Management projects, are
scheduled to start up in 2009 and are expected to eliminate the
routine flaring of natural gas by reinjecting excess natural gas
into various reservoirs.
In Area B of Block 0, average daily net production in 2007
from six producing fields was 47,000 barrels of crude oil
and condensate and 7,000 barrels of LPG. Included in this
production were volumes from the Sanha condensate natural gas
utilization and Bomboco crude oil project that was completed in
mid-2007. During 2007, a portion of the proved undeveloped
reserves for this project was reclassified to the proved
developed category.
In Block 14, net production in 2007 from the Benguela,
Belize, Lobito, Tomboco, Kuito and Landana fields averaged
48,000 barrels of liquids per day. During 2007, development
of the Benguela Belize-Lobito Tomboco (BBLT) project continued,
with production of first oil at the Benguela and Tomboco fields.
Further development drilling is expected to continue at all BBLT
fields. Maximum total production for BBLT is estimated at
200,000 barrels of crude oil per day and is scheduled to
occur in late 2008 or early 2009. Proved undeveloped reserves
for Benguela and Belize were initially recognized in 1998 and
for Lobito and Tomboco in 2000. Proved developed reserves for
Belize and Lobito were recognized in 2006 and for Benguela and
Tomboco in 2007. Additional BBLT reserves are expected to be
reclassified to proved developed as project milestones are met.
Development and production rights for these fields expire in
2027.
Another major project in Block 14 is the development of the
Tombua and Landana fields. Construction of facilities continued
in 2007. Production from the Landana North reservoir is
utilizing the BBLT infrastructure. The maximum total daily
production from Tombua and Landana of 100,000 barrels of
crude oil is expected to occur in 2011. 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 and
continued in 2007. Further reclassification is expected between
2009 when the
Tombua-Landana
facilities are completed and 2012 when the drilling program is
scheduled for completion. Development and production rights for
these fields expire in 2028.
As of early 2008, the Negage project in Block 14 was under
evaluation. Front-end engineering and design (FEED) for this
project was expected to begin in late 2008, with the date of
production
start-up yet
to be determined.
13
Three exploration wells were drilled in Block 14 in 2007,
one of which successfully appraised the 2006 Lucapa discovery.
In the Malange Pinda prospect, one well resulted in a crude-oil
discovery, and as of early 2008, evaluation was ongoing for the
third well completed in the first quarter 2007. Appraisal
drilling of the discoveries is expected to continue in 2008.
Chevron also has a 20 percent interest in a
production-sharing contract (PSC) that covers Block 2,
which is adjacent to the northwestern part of Angolas
coast south of the Congo River, and a 16 percent interest
in the onshore FST area. Combined net production from these
properties in 2007 was 3,000 barrels of liquids per day.
Refer also to page 23 for a discussion of affiliate
operations in Angola.
Democratic Republic of the Congo: Chevron has an
18 percent nonoperated working interest in a concession for
offshore properties. Daily net production from seven fields
averaged 3,000 barrels of oil-equivalent in 2007.
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. Net production
from the Republic of the Congo fields averaged
8,000 barrels of oil-equivalent per day in 2007. The
Moho-Bilondo development continued in 2007, with first
production expected in the second half 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 90,000 barrels of crude oil is expected in
2010. Proved undeveloped reserves were initially recognized in
2001. Transfer to the proved developed category is expected near
the time of first production. Chevrons development and
production rights for Moho-Bilondo expire in 2030.
Two exploration wells were drilled in the Moho-Bilondo permit
area during 2007 and were determined to have oil accumulations.
As of early 2008, results continued under evaluation.
Angola-Republic of the Congo Joint Development
Area: Chevron is the operator and holds a
31 percent interest in the Lianzi Development Area
(formerly referenced as the 14K/A-IMI Unitization Zone), located
in a joint development area shared equally between Angola and
Republic of the Congo. In 2006, the development of the Lianzi
area was approved by the committee of representatives from the
two countries, and a conceptual field development plan was also
submitted to this committee. In early 2007, one additional
exploration well was drilled in the Lianzi area, but the results
were considered subcommercial. As of early 2008, development
studies and planning continued for this area.
Chad/Cameroon: Chevron is a nonoperating partner in
a project to develop crude-oil fields in southern Chad and
transport the produced volumes by pipeline to the coast of
Cameroon for export. Chevron has a 25 percent nonoperated
working interest in the producing operations and a
21 percent interest in two affiliates that own the
pipeline. Average daily net production from six fields in 2007
was 32,000 barrels of oil-equivalent, including volumes
from a satellite field development project in the Maikeri Field
that produced first oil in July 2007. In late 2007, a
development application was submitted for another satellite
field, Timbre, in the Doba area. The Chad producing operations
are conducted under a concession agreement that expires in 2030.
Libya: Chevron is the operator and holds a
100 percent interest in the onshore Block 177
exploration license. Evaluation of seismic data was completed in
late 2007, and an exploratory drilling program is scheduled for
2008.
14
|
|
|
|
|
Nigeria: Chevron holds a 40 percent interest in 13 concessions predominantly in the onshore and near-offshore regions of the Niger Delta and varying interests in deepwater offshore blocks. In the Niger Delta, the company operates under a joint-venture arrangement with the Nigerian National Petroleum Corporation (NNPC), which owns a 60 percent interest. In 2007, net oil- equivalent
production from 32 fields averaged 129,000 barrels per day. The daily oil-equivalent rate comprised 126,000 barrels of liquids and 15 million cubic feet of natural gas.
In the Niger Delta, Chevron has a 40 percent operated interest in the South Offshore Water Injection Project (SOWIP), an enhanced crude-oil recovery
project in Oil Mining License (OML) 90 aimed at increasing production through water injection, natural-gas lift and production debottlenecking in the Okan and Delta fields. The upgraded Delta South Water Injection Platform (DSWIP), which is part of SOWIP, began water injection in March 2007 at a total daily rate of 100,000 barrels. The total maximum daily water injection rate
|
is expected to increase to 240,000 barrels in 2009 upon the
laying of water injection pipelines. Crude-oil production at
year-end 2007 was approximately 5,000 barrels per day, and
maximum total production is expected to be 35,000 barrels
per day in 2010. Initial recognition of proved reserves was made
in 2005. Reclassification of additional proved undeveloped
reserves to the developed category is expected to occur after
the evaluation of the water injection performance. The estimated
life of the project is 25 years.
|
During 2007, the company continued development activities of
deepwater offshore projects. The 68 percent-owned and
operated deepwater Agbami project in OML 127 and OML 128 is a
subsea development with wells tied back to a floating
production, storage and offloading (FPSO) vessel, which was
delivered from South Korea in December 2007. Development
drilling and completion operations started in 2006, and subsea
installation of production equipment began in 2007. Maximum
total daily production of 250,000 barrels of crude oil and
natural gas liquids is anticipated within one year after
start-up,
which is expected by the third quarter 2008. The company
initially recognized proved undeveloped reserves for Agbami in
2002. A portion of the proved undeveloped reserves is scheduled
to be reclassified to proved developed in 2008 near production
start-up.
The expected field life is approximately 20 years. The
total cost for this project is estimated at $5.4 billion.
The Aparo Field in OML 132 and OML 140 and the Bonga SW Field in
OML 118 share a common geologic structure and are planned
to be jointly developed. The geologic structure lies
70 miles offshore in 4,300 feet of water. A
pre-unit
agreement was executed between Chevron and the OML 118 partner
group in 2006. Final terms for a unitization agreement are
expected to be completed in mid-2008. In 2007, FEED and
tendering of major contracts continued. Development will likely
involve an FPSO vessel and subsea wells. Partners are expected
to make the final investment decision in the second half 2008,
with production
start-up
projected for 2012. 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 area. The expected production life of
this project is 20 years.
The company holds a 30 percent nonoperated working interest
in the Usan project, located offshore in OML 138 and designed to
utilize an FPSO vessel. The company recognized proved
undeveloped reserves in 2004. Production
start-up is
estimated for late 2011, before which time a portion of proved
undeveloped reserves is 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.
Chevron operates and holds a 95 percent interest in the
Nsiko discovery on OML 140. As of early 2008, subsurface
evaluations and field development planning were ongoing. An
investment decision is contingent on negotiations concerning the
level of Nigerian content in the projects contracts.
The company has a 46 percent nonoperated interest in the
Nnwa Field in OML 129, which contains a discovery that extends
into two adjacent blocks not owned by Chevron. Commerciality is
dependent upon resolution of the Nigerian Deepwater Gas fiscal
regime and collaboration agreements with the adjacent blocks. A
joint study was initiated in 2007 with owners in adjoining block
OML 135 to progress technical and commercial evaluations.
15
Chevron participated in two deepwater exploration wells during
2007. The Uge 2 well, drilled as an appraisal well to the
Uge 1 discovery in Oil Prospecting License (OPL) 214, confirmed
hydrocarbons. The company has a 20 percent nonoperated
working interest in OPL 214. The second well was deemed
noncommercial. Two additional deepwater exploration wells are
planned in 2008.
Chevron also is involved in projects in the Niger Delta region
that support the companys strategic initiative to
commercialize its significant natural gas resource base outside
the United States. Construction is under way on the
Phase 3A expansion of the Escravos Gas Plant (EGP), which
is expected to start up in 2009. Phase 3A scope includes
offshore natural gas gathering and compression infrastructure
and a second gas processing facility, which potentially would
increase processing capacity from 285 million to
680 million cubic feet of natural gas per day and increase
LPG and condensate export capacity from 12,000 to
47,000 barrels per day. EGP Phase 3A is designed to process
natural gas from the Meji, Delta South, Okan and Mefa producing
fields. Proved undeveloped reserves associated with EGP
Phase 3A were recognized in 2002. These reserves are
expected to be reclassified to proved developed as various
project milestones are reached and related projects are
completed. The anticipated life of the project is 25 years.
Chevron holds a 40 percent operated interest in this
project.
Refer also to page 26 for a discussion of the planned
gas-to-liquids facility at Escravos.
Chevron holds a 37 percent interest in the West African Gas
Pipeline, which is designed to supply Nigerian natural gas to
customers in Ghana, Benin and Togo for industrial applications
and power generation. First gas is anticipated to be shipped by
mid-2008, and facility completion, with a capacity of
170 million cubic feet of natural gas per day, is expected
in the second-half 2008. Chevron is the managing sponsor in the
West African Pipeline Company Limited affiliate, which
constructed, owns and operates the
412-mile
pipeline.
In March 2007, Chevron signed a shareholders agreement for
a 19 percent interest in the OKLNG Free Zone Enterprise
(OKLNG) affiliate, which will operate the Olokola LNG project.
OKLNG plans to build a multitrain,
22 million-metric-ton-per-year natural gas liquefaction
facility and marine terminal located in a free trade zone. The
project entered FEED in 2006 and is expected to be implemented
in phases, commencing with two trains having at least
11 million-metric-ton-per-year total capacity.
Approximately 50 percent of the gas supplied to the plant
is expected to be provided from the producing areas associated
with Chevrons joint-venture arrangement with NNPC
(discussed earlier in this section).
Nigeria-São Tomé e Príncipe Joint
Development Zone (JDZ): Chevron holds a 46 percent
operated interest in JDZ Block 1. In 2006, the first
exploration well encountered hydrocarbons. In 2008, technical
studies are planned to determine the need for additional
drilling and evaluate development alternatives.
|
|
|
|
|
Australia: During 2007, the average net oil-equivalent production from Chevrons interests in Australia was 100,000 barrels per day, composed of 39,000 barrels of liquids and 372 million cubic feet of natural gas.
Chevron has a 17 percent nonoperated working interest in the North West Shelf (NWS) Venture offshore Western Australia. Daily net production from
the project during 2007 averaged 29,000 barrels of crude oil and condensate, 369 million cubic feet of natural gas, and 5,000 barrels of LPG. Approximately 75 percent of the natural gas was sold in the form of LNG to major utilities in Japan, South Korea and China, primarily under long-term contracts. The remaining natural gas was sold to the Western Australia domestic
|
market. A fifth LNG train, which is intended to increase export
capacity by more than 4 million metric tons per year, to
more than 16 million, is expected to be commissioned in
late 2008. The Angel natural gas field, where development is
under way, and the North Rankin Redevelopment project will
supply the fifth LNG train.
Start-up of
the fifth train is projected to accelerate production from the
NWS fields. An investment decision by the company and its
partners on the North Rankin Redevelopment project is expected
in late 2008. The end of the NWS Venture concession period is
2034.
|
On Barrow and Thevenard islands off the northwest coast of
Australia, Chevron operates crude oil producing facilities that
had combined net production of 5,000 barrels per day in
2007. Chevrons interests in these operations are
57 percent for Barrow and 51 percent for Thevenard.
16
Also off the northwest coast of Australia, Chevron is the
operator of the Gorgon development and has a 50 percent
ownership interest across most of the Greater Gorgon Area.
Chevron and 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 2007, the company received environmental
regulatory approvals necessary for the development of the
Greater Gorgon LNG project on Barrow Island using a two-train,
10 million-metric-ton-per-year LNG development plan. As of
early 2008, the detailed environmental conditions were
incorporated into the projects updated optimization and
engineering efforts for a three-train,
15 million-metric-ton-per-year LNG configuration, and
activities to secure the necessary government approvals were
under way. Natural gas for the project will be supplied from the
Gorgon and Jansz fields. The Gorgon project has an expected
economic life of at least 40 years.
Elsewhere in the Greater Gorgon Area during 2007, Chevron
participated in four successful appraisal wells two
in the Browse Basin and two in the Carnarvon Basin. Chevron also
participated in two exploration wells in the Carnarvon Basin,
with Lady Nora resulting in a natural gas discovery and Snarf-1
expecting to be completed in 2008. As of early 2008, plans were
also being developed to appraise the 67 percent-owned Clio
and the 50 percent-owned Chandon natural gas discoveries.
Concept studies continued in 2007 on the Wheatstone natural gas
discovery, and a successful appraisal well was drilled late in
the year. Further appraisal wells are planned to be drilled in
the area in 2008.
At the end of 2007, 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. In 2007, the company
signed a nonbinding Heads of Agreement (HOA) with GS Caltex, a
Chevron affiliated company, to supply 250,000 metric tons of LNG
annually from the Gorgon project. Combined with the nonbinding
HOAs signed previously with three utility customers in Japan,
volumes under the four HOAs totaled 4.5 million metric tons
per year. As of early 2008, negotiations were continuing to
finalize binding sales agreements on these HOAs. Purchases by
each of these customers are expected to range from 300,000
metric tons per year to 1.5 million metric tons per year
over 25 years.
|
|
|
|
|
Azerbaijan: Chevron holds a 10 percent nonoperated working interest in the Azerbaijan International Operating Company (AIOC), which produces crude oil in the Caspian Sea from the Azeri-Chirag-Gunashli (ACG) project. Chevron also has a 9 percent interest in the Baku-Tbilisi-Ceyhan (BTC) affiliate, which transports AIOC production by pipeline from Baku, Azerbaijan, through Georgia
to Mediterranean deepwater port facilities in Ceyhan, Turkey. (Refer to Pipelines under Transportation Operations on page 28 for a discussion of the BTC operations.)
In 2007, the companys daily net production from AIOC averaged 61,000 barrels of oil-equivalent. First production from Phase III of ACG development is targeted for the second quarter 2008.
Total crude-oil production from the ACG project is expected to increase to about 940,000 barrels per day by the end of 2008 and to more than 1 million barrels per day in 2009. Proved undeveloped reserves for ACG are expected to be reclassified to proved developed reserves as wells are drilled and completed. The AIOC operations are conducted under a 30-year
PSC that expires in 2024.
|
Kazakhstan: Chevron holds a 20 percent
nonoperated working interest in the Karachaganak project that is
being developed in phases. During 2007, Karachaganak net
oil-equivalent production averaged 66,000 barrels per day,
composed of 41,000 barrels of liquids and 149 million
cubic feet of natural gas. In 2007, access to the Caspian
Pipeline Consortium (CPC) and Atyrau-Samara (Russia) pipelines
allowed Karachaganak sales of approximately 166,000 barrels
per day (31,000 net barrels) of processed liquids at prices
available in world markets. The remaining liquids were sold into
Russian markets. During 2007, work continued on a fourth train
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.
In 2007, the Karachaganak operator signed a
15-year
natural gas sales agreement to deliver up to 1.6 billion
cubic feet per day of sour gas to a Russian-Kazakh joint
venture. Deliveries under the agreement commenced in September
2007. As of early 2008, Phase III development of
Karachaganak continued under evaluation. The project could
increase maximum total production to 335,000 barrels of
liquids per day and 1.7 billion cubic feet of natural gas
per day. Timing for the recognition of Phase III proved
reserves is uncertain and depends on finalizing a viable
Phase III project design.
17
Project
start-up is
anticipated in 2012 or after, depending on achievement of
project milestones. Karachaganak operations are conducted under
a 40-year
PSC that expires in 2038.
Refer also to pages 23 and 24 for a discussion of
Tengizchevroil, a 50 percent-owned affiliate with
operations in Kazakhstan.
Russia: Refer to page 24 for a discussion of
the companys interest in a Russian joint venture.
Bangladesh: Chevron is the operator of three onshore
blocks, with a 98 percent interest in Blocks 12, 13
and 14 and operator of Block 7, in which the company holds
a 43 percent interest. Net oil-equivalent production in
2007 averaged 47,000 barrels per day, composed of
275 million cubic feet of natural gas and
2,000 barrels of liquids. Production from the Bibiyana
Field in Block 12 started in March 2007. The project is
expected to reach maximum total production of 500 million
cubic feet per day by late 2010. The development program
included 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 2007,
additional proved reserves were recognized based on development
wells drilled during the year, and a portion of proved
undeveloped reserves were reclassified to the proved developed
category. Bibiyana operations are conducted under a PSC that
expires in 2034.
|
|
|
|
|
Cambodia: Chevron operates and holds a 55 percent interest in the 1.2 million-acre Block A, located offshore in the Gulf of Thailand. A four-well exploration and appraisal program was completed in 2007. As of early 2008, the results and prospects for further drilling were being evaluated.
Myanmar: Chevron
has a 28 percent nonoperated working interest in a PSC for the production of natural gas from the Yadana and Sein fields offshore in the Andaman Sea. The company also has a 28 percent interest in a pipeline company that transports the natural gas from Yadana to the Myanmar-Thailand border for delivery to power plants in Thailand. Most of the natural gas is purchased by
|
Thailands PTT Public Company Limited (PTT). The
companys average net natural gas production in 2007 was
100 million cubic feet per day, or 17,000 barrels of
oil-equivalent.
|
Thailand: Chevron has operated and nonoperated
working interests in several different offshore blocks. The
companys net oil-equivalent production in 2007 averaged
224,000 barrels per day, composed of 71,000 barrels of
crude oil and condensate and 916 million cubic feet of
natural gas. All of the companys natural gas production is
sold to PTT under long-term sales contracts.
Operated interests are in Pattani and other fields with
ownership interests ranging from 35 percent to
80 percent in Blocks 10 through 13, B12/27, B8/32, 9A,
G4/43 and G4/48. Blocks B8/32 and 9A produce crude oil and
natural gas from six operating areas, and Blocks 10 through
13 and B12/27 produce crude oil, condensate and natural gas from
16 operating areas.
The companys production of natural gas increased beginning
in March 2007 with PTTs commissioning of a third natural
gas pipeline. In October 2007, the leases for Blocks 10
through 13 were extended from 2012 to 2022. In December 2007,
the company signed a natural gas sales agreement that will
increase daily contract quantity of natural gas from these
blocks by 500 million cubic feet, to 1.2 billion, by
2012. In addition, this agreement is expected to enable the
construction of a second central natural gas processing facility
in the Platong area. The 70 percent-owned Platong
Gas II project is designed to add 420 million cubic
feet per day of processing capacity in the first quarter 2011.
The company expects to recognize proved reserves throughout the
projects
12-year life
as the wellhead platforms are installed.
Chevron has a 16 percent nonoperated working interest in
Blocks 14A, 15A, 16A, G9/48 and G8/50, known collectively
as the Arthit Field. First production from Arthit is planned for
the second quarter 2008 and is expected to reach an estimated
maximum total production of 330 million cubic feet of
natural gas per day by the end of 2008. Proved undeveloped
reserves were recorded for the first time in 2006.
Reclassification of proved undeveloped reserves to the proved
developed category is anticipated in 2008, near production
start-up.
The concessions that cover Arthit operations expire in 2040.
18
In G9/48, one exploration well is required to be drilled by the
first quarter 2009. Chevron also holds exploration interests in
a number of blocks that are currently inactive, pending
resolution of border issues between Thailand and Cambodia.
In late 2007, the company was granted the concession rights to
four prospective offshore petroleum blocks in Thailand, which
includes Block G8/50 (discussed earlier in this section).
Chevrons interest in the other three operated blocks,
G4/50, G6/50 and G7/50, ranges from 35 percent to
75 percent.
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 one PSC that
includes Blocks B and 48/95 and a 43 percent interest in
the other PSC that has Block 52/97. Chevron also has a
50 percent operated interest in Block B122 offshore eastern
Vietnam. No production occurred in these PSCs during 2007.
The Vietnam Gas Project is aimed at developing an area in the
two Malay Basin PSCs to supply natural gas to state-owned
PetroVietnam. In the third quarter 2007, PetroVietnam approved
the revised development plan, joint development area and
unitization agreement for the project. The project includes
installation of wellhead and hub platforms, an FPSO vessel,
infield pipelines and a central processing platform. The timing
of first natural gas production is dependent upon the outcome of
commercial negotiations. Maximum total production of
approximately 500 million cubic feet of natural gas per day
is projected within five years of
start-up.
Recognition of initial proved undeveloped reserves would follow
execution of the gas sales agreements and project approval. The
PSC for Blocks B and 48/95 and the PSC for Block 52/97 will
expire in 2022 and 2029, respectively.
In Block 122, a planned seismic program was postponed in
2007 due to issues of territorial claim between Vietnam and
China.
China: Chevron has nonoperated working interests of
33 percent in Blocks 16/08 and 16/19 located in the Pearl
River Delta Mouth Basin, 25 percent in the QHD-32-6 Field
in Bohai Bay and 16 percent in the unitized and producing
BZ 25-1
Field in Bohai Bay Block 11/19. The companys net
oil-equivalent production in China during 2007 averaged
26,000 barrels per day, composed of 22,000 barrels of
crude oil and condensate and 22 million cubic feet of
natural gas.
Joint development of the HZ25-3 and HZ25-1 crude-oil fields in
Block 16/19 commenced in the first quarter 2007. First
production is expected in early 2009, reaching a maximum total
daily production of approximately 14,000 barrels of crude
oil late in the year. 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. In December 2007, the company signed a
30-year PSC
that became effective in February 2008 for the development of
the Chuandongbei natural gas area in the onshore Sichuan Basin.
The aggregate design input capacity of the proposed gas plants
is expected to be 740 million cubic feet of natural gas per
day. The company holds a 49 percent interest in the area.
Partitioned Neutral Zone (PNZ): Chevron holds a
60-year
concession that expires in 2009 to produce crude oil from
onshore properties in PNZ, which is located between Saudi Arabia
and Kuwait. Negotiations to extend the concession period were
ongoing in early 2008. Net production in PNZ for 2007
represented 4 percent of Chevrons net barrels of
oil-equivalent total.
Under the current concession, Chevron has the right to Saudi
Arabias 50 percent interest in the hydrocarbon
resource and pays a royalty and other taxes on volumes produced.
During 2007, average net oil-equivalent production was
112,000 barrels per day, composed of 109,000 barrels
of crude oil and 17 million cubic feet of natural gas. The
second phase of a steamflood pilot project is expected to be
completed in early 2009. This pilot is a unique application of
steam injection into a carbonate reservoir and, if successful,
could significantly increase recoverability of the heavy oil in
place.
Philippines: The company holds a 45 percent
nonoperated working interest in the Malampaya natural gas field
located 50 miles offshore Palawan Island. Net
oil-equivalent production in 2007 averaged 26,000 barrels
per day, composed of 126 million cubic feet of natural gas
and 5,000 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 637 megawatts.
19
|
|
|
|
|
Chevrons operated interests in Indonesia are managed by
several wholly owned subsidiaries, including PT. Chevron Pacific
Indonesia (CPI). CPI holds operated interests of
100 percent in the Rokan and Siak PSCs and 90 percent
in the Mountain Front Kuantan PSC. Other subsidiaries operate
four PSCs in the Kutei Basin, East Kalimantan and one PSC in the
Tarakan Basin, Northeast Kalimantan. These interests range from
80 percent to 100 percent. Chevron also has
nonoperated working interests in a joint venture in South Natuna
Sea Block B and in the NE Madura III block in the East Java
Sea Basin. Chevrons interests in these PSCs range from
25 percent to 40 percent. In January 2008, Chevron
relinquished its 35 percent nonoperated working interest
|
in the Donggala PSC in the Kutei Basin. In West Java, Chevron
wholly owns a power generation company that operates the Darajat
geothermal contract area in Garut, West Java, with a total
capacity of 259 megawatts. This includes the Darajat III
110-megawatt unit that was placed online in July 2007. Chevron
also operates a 95 percent-owned
300-megawatt
cogeneration facility in support of CPIs operation in
North Duri and the wholly owned Salak geothermal field, located
in West Java, with a total capacity of 377 megawatts.
|
The companys net oil-equivalent production in 2007 from
all of its interests in Indonesia averaged 241,000 barrels
per day. The daily oil-equivalent rate comprised
195,000 barrels of crude oil and 277 million cubic
feet of natural gas. The largest producing field is Duri,
located in the Rokan PSC. Duri has been under steamflood
operation since 1985 and is one of the worlds largest
steamflood developments. An expansion area, Area 12, is targeted
for start-up
in late 2008. Maximum total daily production is estimated at
34,000 barrels of crude oil in 2012. Two other areas have
been identified for possible sequential expansions. Proved
undeveloped reserves for North Duri were recognized in previous
years, and reclassification from proved undeveloped to proved
developed is scheduled to occur during various stages of
sequential completion. The Rokan PSC expires in 2021.
A drilling campaign continued through 2007 in South Natuna Sea
Block B, with first oil produced from the Kerisi Field in
December 2007. First production of LPG from the Belanak Field
was achieved in April 2007. Additional development drilling in
the North Belut Field is scheduled to begin in mid-2008, with
first production expected in 2009.
In January 2007, Chevron combined the development of the Gendalo
and Gehem deepwater natural gas fields located in the Kutei
Basin into a single project with one development concept. In
August 2007, the company submitted final development plans to
the government of Indonesia. Approvals are expected during the
first-half 2008. The Bangka natural gas project was under
evaluation in 2007 and will likely be developed in parallel with
Gendalo and Gehem. The development timing is partially dependent
on government approvals, market conditions and the achievement
of key project milestones. The company holds an 80 percent
operated interest in these projects.
As of early 2008, the development concept for the
50 percent-owned and operated Sadewa project in the Kutei
Basin remained under evaluation. Also in the Kutei Basin, the
development of the Seturian Field project continued in 2007,
with first production anticipated in late 2008. The project is
designed to supply natural gas to a state-owned refinery.
20
|
|
e)
|
Other
International Areas
|
|
|
|
|
|
Argentina: Chevron holds an operated interest in 17 concessions and one exploratory block in the Neuquen and Austral basins. Working interests range from 19 percent to 100 percent. Net oil-equivalent production in 2007 averaged 47,000 barrels per day, composed of 39,000 barrels of crude oil and 50 million cubic feet of natural gas. Chevron also holds a 14 percent
interest in the Oleoductos del Valle S.A. pipeline.
In 2007, three exploratory wells were drilled in the Austral Basin, and two were successful.
Brazil: Chevron holds working interests ranging from 20 percent to 52 percent in three deepwater blocks. None of the blocks had production in 2007.
In Block BC-4, located in the Campos Basin, the company is the operator
and has a 52 percent interest in the Frade Field. In 2007, major construction activities included work to convert a crude-oil tanker to an FPSO vessel and the manufacture of subsea systems and flowlines for the project. Subsea installation activities began in early 2008. Proved undeveloped reserves were recorded for
|
the first time in 2005. Partial reclassification of proved
undeveloped reserves to the proved developed category is
anticipated upon production
start-up in
early 2009. Estimated maximum total production of 90,000
oil-equivalent
barrels per day is anticipated in 2011. The concession that
involves the Frade project expires in 2025.
|
The company concentrates its exploration efforts in the Campos
and Santos basins. In the partner-operated Campos Basin Block
BC-20, two areas 38 percent-owned Papa-Terra
and 30 percent-owned Maromba have been retained
for development following the end of the exploration phase of
this block. In 2006, a Papa-Terra field development plan was
submitted to the government, and as of early 2008 this plan was
still under evaluation. In Maromba as of early 2008, a pilot
production system was under consideration, with first oil
projected for 2013. Elsewhere in Campos, the company
relinquished its 30 percent nonoperated working interest in
BM-C-4. In the 20 percent-owned and partner-operated Santos
Basin Block BS-4, development options for the Atlanta and Oliva
fields were under evaluation.
Colombia: The company operates the offshore Chuchupa
and the onshore Ballena and Riohacha natural gas fields as part
of the Guajira Association contract. In exchange, Chevron
receives 43 percent of the production for the remaining
life of each field and a variable production volume from a
fixed-fee Build-Operate-Maintain-Transfer agreement based on
prior Chuchupa capital contributions. Daily net production
averaged 178 million cubic feet of natural gas, or
30,000 barrels of oil-equivalent, in 2007. During the year,
new dehydration facilities were constructed that enabled natural
gas exports to Venezuela beginning in January 2008.
Trinidad and Tobago: The company has a
50 percent nonoperated working interest in four blocks in
the East Coast Marine Area offshore Trinidad, which include the
Dolphin and Dolphin Deep producing natural gas fields and the
Starfish discovery. Net production from Dolphin and Dolphin Deep
in 2007 averaged 174 million cubic feet of natural gas per
day, or 29,000 barrels of oil-equivalent.
In May 2007, a domestic natural gas sales agreement was signed
for the Trinidad Incremental Gas project. The agreement includes
the delivery of 220 million cubic feet per day for
11 years with an option for a four-year extension. Drilling
operations started in late 2007 at the Dolphin platform. First
gas for the project is expected in 2009, ramping up to maximum
total production of 220 million cubic feet of natural gas
per day in early 2010. Reserves were initially booked in 2006.
In 2007, additional proved reserves were recorded, and some
proved undeveloped reserves were reclassified to the proved
developed category. Further reclassifications are expected in
2008, following the drilling of additional development wells.
Chevron also holds a 50 percent operated interest in the
Manatee area of Block 6d. In early 2007, an agreement was
signed by the governments of Venezuela and Trinidad and Tobago
to unitize the Loran Field in Venezuela and the Manatee area.
Negotiations are expected to continue in 2008 to achieve a
field-specific unitization treaty.
Venezuela: Chevron holds interest in two affiliates
located in western Venezuela and one affiliate in the Orinoco
Belt. The company also operates in two exploratory blocks
offshore Plataforma Deltana, with working interests of
60 percent in Block 2 and 100 percent in
Block 3. In Block 2, which includes the Loran natural
gas field, a conceptual offshore development plan was completed
in 2007. In Block 3, Chevron discovered natural gas in 2005
that is in close proximity to Loran. Both Block 3 and Loran
will provide a possible supply source for Venezuelas first
LNG train. Seismic work elsewhere in Block 3 was completed
in 2007. Chevron also has a 100 percent interest in the
Cardon III
21
block, located north of the Maracaibo producing region. Seismic
in this block, which has natural gas potential, was acquired in
2007 and is planned to be processed in 2008. Petróleos de
Venezuela, S.A. (PDVSA) has the option to increase its ownership
in all three company-operated blocks up to 35 percent upon
declaration of commerciality.
Refer also to page 24 for a discussion of affiliate
operations in Venezuela.
Canada: The company has nonoperated working
interests of 27 percent in the Hibernia Field offshore
eastern Canada and 20 percent in the Athabasca Oil Sands
Project (AOSP), a 60 percent operated interest in the Ells
River In Situ Oil Sands Project, a 28 percent
operated interest in the Hebron project and exploration acreage
in the Mackenzie Delta, Beaufort Sea and the Orphan Basin.
Excluding volumes mined at the AOSP, average net oil-equivalent
production during 2007 was 36,000 barrels per day, composed
of 35,000 barrels of crude oil and natural gas liquids and
5 million cubic feet of natural gas. Substantially all of
the production was from the Hibernia Field. At AOSP, bitumen
mined and upgraded to synthetic crude oil averaged
27,000 net barrels per day.
At AOSP, the first phase of an expansion project, with an
estimated total project cost of $10.2 billion, is being
designed to upgrade an additional 100,000 barrels of
bitumen into synthetic crude oil per day. The expansion would
increase total AOSP design capacity to more than
255,000 barrels of bitumen per day in 2010. Preliminary
work is under way to determine the feasibility of additional
expansion projects.
The Ells River project consists of heavy oil leases of more than
85,000 acres. 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. During 2007, a successful appraisal
drilling program involving 66 wells was completed.
Follow-up
appraisal activities are planned in 2008, with a similar number
of wells and a small
2-D and
3-D seismic
program.
The potential development at Hebron stalled in 2006 after
unsuccessful negotiations with the provincial government of
Newfoundland and Labrador. In mid-2007, the Hebron partners
executed a nonbinding memorandum of understanding with the
government that outlined fiscal, equity and local-benefit terms
associated with the Hebron project. Execution of formal
agreements is expected during 2008.
Exploratory activities are expected to continue during 2008 in
the Mackenzie Delta and the Orphan Basin.
|
|
|
|
|
Denmark: Chevron holds a 15 percent nonoperated working interest in the Danish Underground Consortium (DUC), which produces crude oil and natural gas from 15 fields in the Danish North Sea and has a 12 percent interest in each of four exploration licenses. Net oil-equivalent production in 2007 from DUC averaged 63,000 barrels per day, composed of 41,000 barrels of crude
oil and 132 million cubic feet of natural gas.
Faroe Islands: Chevron has a 40 percent interest in five offshore blocks and is the operator. During 2007, the company acquired a 2-D seismic survey over License 008, located near the Rosebank/Lochnagar discovery in the United Kingdom.
Greenland: In October
2007, Chevron was awarded a 29 percent nonoperated working interest in an exploration license in Block 4 offshore West Greenland in the Baffin Basin. The planned four-year work program includes seismic acquisition, and geologic, engineering and environmental studies.
|
Netherlands: Chevron is the operator and holds
interests ranging from 34 percent to 80 percent in
nine blocks in the Dutch sector of the North Sea. The
companys daily net production from eight producing fields
averaged 3,000 barrels of crude oil and 5 million
cubic feet of natural gas. Production
start-up at
the first stage of the A/B Gas Project from Block A12 occurred
in December 2007 at an initial daily total rate of
60 million cubic feet of natural gas. As of early 2008, the
second stage of the project was under evaluation.
Norway: At the 8 percent-owned and
partner-operated Draugen Field, the companys net
production during 2007 was 6,000 barrels of oil-equivalent
per day. In the 40 percent-owned and partner-operated
PL397, seismic survey data was processed in 2007. Acquisition of
additional seismic data is planned for 2008. Exploration
activities are expected to continue in 2008 in various license
areas.
United Kingdom: The companys average net
oil-equivalent production in 2007 from nine offshore fields was
115,000 barrels per day, composed of 78,000 barrels of
crude oil and 220 million cubic feet of natural gas. Most
of the
22
production was from the 85 percent-owned and operated
Captain Field and the 32 percent-owned and jointly-operated
Britannia Field.
As of early 2008, 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. Production
start-up
from these two fields is expected to occur in late 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.
In exploration activities, the Alder discovery west of the
Britannia Field was being evaluated in early 2008 and is 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 2012. The timing of
the initial proved-reserves recognition was also under
evaluation in early 2008. This project has an expected
production life of approximately nine years.
At the Rosebank/Lochnagar discovery west of the Shetland
Islands, an appraisal program consisting of three wells and a
sidetrack was completed in 2007. All four wellbores encountered
hydrocarbons, and an evaluation for commerciality was under way
in early 2008. Evaluation continued of a successful natural gas
production test at the Tormore well that is also in the West of
Shetlands gas trend. During 2007, another successful appraisal
well was drilled in the Clair Phase 2 area.
Equity
Affiliate Operations
Angola: In addition to the exploration and producing
activities in Angola, Chevron participates in the Angola LNG
project, for which the company and partners made a final
investment decision at the end of 2007. The LNG plant will be
designed with a capacity to process 1 billion cubic feet of
natural gas per day and will provide a commercial option for
Angolas natural gas resources. Chevron has a
36 percent interest in the Angola LNG affiliate.
Construction began in early 2008 on the
5.2 million-metric-ton-per-year onshore LNG plant that is
located in the northern part of the country. Plant
start-up is
expected in 2012. At the end of 2007, the company made an
initial booking of proved natural gas reserves for the producing
operations associated with this LNG project. The life of the LNG
plant is estimated to be in excess of 20 years.
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. Chevrons net
oil-equivalent production in 2007 from these fields averaged
176,000 barrels per day, composed of 144,000 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 $7.2 billion, these projects are designed to
increase TCOs crude-oil production capacity to
540,000 barrels per day during the second half of 2008.
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. Wells were drilled, deepened
and/or
completed since 2002 in the Tengiz and Korolev reservoirs to
produce volumes required for the new SGP train. 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, SGI is expected over time
to increase production efficiency and recoverable volumes as the
injected gas maintains higher reservoir pressure and displaces
oil toward producing wells. The company anticipates recognizing
additional proved reserves associated with the SGI expansion in
late 2008. The primary SGI risks include uncertainties about
compressor performance associated with injecting high-pressure
sour gas and subsurface responses to injection.
23
Initial production from the first phase of the SGI/SGP expansion
projects occurred in late 2007. This first phase increased
production capacity by 90,000 barrels per day, to
approximately 400,000, in January 2008.
As of early 2008, essentially all of TCOs production was
being 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. Also in early 2008, CPC was seeking stockholder approval
for an expansion to accommodate increased TCO volumes beginning
in 2009. Expanded rail-car loading and rail-export facilities,
designed to transport most of the incremental SGI/SGP production
prior to the CPC expansion, started operation during 2007. As of
early 2008, other alternatives were also being explored to
increase export capacity.
Venezuela: Chevron has a 30 percent interest in
the Hamaca heavy oil production and upgrading project located in
Venezuelas Orinoco Belt, a 39 percent interest in the
Petroboscan affiliate that operates the Boscan Field, and a
25 percent interest in the Petroindependiente affiliate
that operates the LL-652 Field. The companys average net
oil-equivalent production during 2007 from these affiliates was
72,000 barrels per day, composed of 68,000 barrels of
crude oil and 27 million cubic feet of natural gas.
The Hamaca project has a total design capacity for 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 February
2007, the president of Venezuela issued a decree announcing the
governments intention for PDVSA to increase its ownership
in all Orinoco Heavy Oil Associations effective May 1,
2007, including Chevrons 30 percent-owned Hamaca
project, to a minimum of 60 percent. In December 2007, Chevron
executed a conversion agreement and signed a charter and by-laws
with a PDVSA subsidiary that provided for Chevron to retain its
30 percent interest in the Hamaca project. The new entity,
Petropiar, commenced activities in January 2008.
The Boscan Field is located onshore western Venezuela. A 3-D
seismic program was acquired in 2007 that is expected to guide
future development activities in South Boscan. The
water-injection pressure-maintenance project was expanded to
include four wells converted to injectors in 2007, and four new
injectors are planned to be drilled in 2008 and 2009. The LL-652
Field is located in Lake Maracaibo.
Russia: As of early 2008, Chevron and JSC Gazprom
Neft continued to negotiate the final agreements for exploration
and development activities in two licensed areas in the
Yamal-Nenets region of western Siberia. Once the agreement is
finalized, Chevron is expected to hold a 49 percent
interest in the Northern Taiga Neftegaz LLC affiliate, which
will operate in the licensed areas. Exploration and delineation
activities are planned for 2008 on both licenses.
Sales of
Natural Gas and Natural Gas Liquids
The company sells natural gas and natural gas liquids from its
producing operations under a variety of contractual
arrangements. Outside the United States, substantially all of
the natural gas sales are from the companys producing
interests in Australia, Bangladesh, Kazakhstan, Indonesia, Latin
America, the Philippines, Thailand and the United Kingdom.
Substantially all of the companys natural gas liquids
sales are from company operations in Africa, Australia and
Indonesia. Refer to Selected Operating Data, on
page FS-10
in Managements Discussion and Analysis of Financial
Condition and Results of Operations, for further information on
the companys natural gas and natural gas liquids sales
volumes. Refer also to Contract Obligations on
page 8 for information related to the companys
contractual commitments for the sale of crude oil and natural
gas.
24
Downstream
Refining, Marketing and Transportation
Refining
Operations
At the end of 2007, the companys refining system consisted
of 19 fuel refineries and an asphalt plant. The company operated
nine of these facilities, and 11 were operated by affiliated
companies. The daily refinery inputs for 2005 through 2007 for
the company and affiliate refineries are as follows:
Petroleum
Refineries: Locations, Capacities and Inputs
(Capacities
and inputs in thousands of barrels per day; includes equity
share in affiliates)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operable
|
|
|
Refinery Inputs
|
|
Locations
|
|
Number
|
|
|
Capacity
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Pascagoula
|
|
Mississippi
|
|
|
1
|
|
|
|
330
|
|
|
|
285
|
|
|
|
337
|
|
|
|
263
|
|
El Segundo
|
|
California
|
|
|
1
|
|
|
|
260
|
|
|
|
222
|
|
|
|
258
|
|
|
|
230
|
|
Richmond
|
|
California
|
|
|
1
|
|
|
|
243
|
|
|
|
192
|
|
|
|
224
|
|
|
|
233
|
|
Kapolei
|
|
Hawaii
|
|
|
1
|
|
|
|
54
|
|
|
|
51
|
|
|
|
50
|
|
|
|
50
|
|
Salt Lake City
|
|
Utah
|
|
|
1
|
|
|
|
45
|
|
|
|
42
|
|
|
|
39
|
|
|
|
41
|
|
Other1
|
|
|
|
|
1
|
|
|
|
80
|
|
|
|
20
|
|
|
|
31
|
|
|
|
28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Consolidated Companies United
States
|
|
|
6
|
|
|
|
1,012
|
|
|
|
812
|
|
|
|
939
|
|
|
|
845
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pembroke
|
|
United Kingdom
|
|
|
1
|
|
|
|
210
|
|
|
|
212
|
|
|
|
165
|
|
|
|
186
|
|
Cape
Town2
|
|
South Africa
|
|
|
1
|
|
|
|
110
|
|
|
|
72
|
|
|
|
71
|
|
|
|
61
|
|
Burnaby, B.C.
|
|
Canada
|
|
|
1
|
|
|
|
55
|
|
|
|
49
|
|
|
|
49
|
|
|
|
45
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Consolidated Companies
International
|
|
|
3
|
|
|
|
375
|
|
|
|
333
|
|
|
|
285
|
|
|
|
292
|
|
Affiliates3
|
|
Various Locations
|
|
|
11
|
|
|
|
728
|
|
|
|
688
|
|
|
|
765
|
|
|
|
746
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Including Affiliates
International
|
|
|
14
|
|
|
|
1,103
|
|
|
|
1,021
|
|
|
|
1,050
|
|
|
|
1,038
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Including Affiliates Worldwide
|
|
|
20
|
|
|
|
2,115
|
|
|
|
1,833
|
|
|
|
1,989
|
|
|
|
1,883
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
Asphalt plants in Perth Amboy, New
Jersey, and Portland, Oregon. The Portland plant was sold in
February 2005.
|
2 |
|
Chevron holds 100 percent of
the common stock issued by Chevron South Africa (Pty) Limited,
which owns the Cape Town Refinery. A consortium of South African
partners owns preferred shares ultimately convertible to a
25 percent equity interest in Chevron South Africa (Pty)
Limited. None of the preferred shares had been converted as of
February 2008.
|
3 |
|
Chevron sold its 31 percent
interest in the Nerefco Refinery in the Netherlands in March
2007. This decreased the companys share of operable
capacity by about 124,000 barrels per day.
|
In the first quarter 2008, the company sold its 4 percent
ownership interest in an affiliate that owned a refinery in
Abidjan, Côte dIvoire, decreasing the companys
share of operable capacity by about 2,000 barrels per day.
Average crude oil distillation capacity utilization during 2007
was 86 percent, compared with 90 percent in 2006. This
decrease generally resulted from unplanned downtime to repair
damage resulting from fires in the crude units at the Richmond
and Pascagoula refineries during 2007. This impact was partially
offset by an improvement in capacity utilization at the
Pembroke, U.K., refinery, which had unplanned downtime in 2006.
The crude unit at the Pascagoula Refinery was back in service in
February 2008. Despite the outage at Pascagoula, the company was
able to maintain uninterrupted product supplies to customers
through the use of other feedstocks in its gasoline-producing
facilities at the refinery. At the U.S. fuel refineries,
crude oil distillation capacity utilization averaged
85 percent in 2007, compared with 99 percent in 2006,
and cracking and coking capacity utilization averaged
78 percent and 86 percent in 2007 and 2006,
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 companys fuel refineries in the United States, Europe,
Canada, South Africa and Australia produce low-sulfur fuels. In
2007, Singapore Refining Company, the companys
50 percent-owned affiliate, began an upgrade project at its
290,000-barrel-per-day refinery in Singapore to produce diesel
fuels that meet Euro IV specifications.
In 2007, the company completed modifications at its refineries
in El Segundo, California, to enable the processing of heavier
crude oils into gasoline, diesel and other light products, and
in the United Kingdom to increase the capability to process
Caspian-blend crude oils. In October 2007, the company approved
plans to construct a $500 million Continuous Catalyst
Regeneration unit at the Pascagoula, Mississippi, refinery,
which is expected to increase gasoline production by
10 percent, or 600,000 gallons per day, by mid-2010. Design
and engineering for a project to increase the
25
flexibility to process lower API-gravity crude oils at the
companys Richmond, California, refinery continued in 2007.
Other upgrade projects at the El Segundo Refinery were being
evaluated in early 2008.
In late 2007, GS Caltex, the companys
50 percent-owned affiliate, completed commissioning of new
facilities associated with a $1.5 billion upgrade project
at the 680,000-barrel-per-day Yeosu refining complex in South
Korea. This project is expected to increase the yield of
high-value refined products by 33,000 barrels per day, add
15,000 barrels of new lubricant base oil production and
reduce feedstock costs through an increase in the
refinerys ability to process heavy oil.
Chevron owns 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 refinery is expected to begin operation by year-end
2008, with a crude-oil capacity of 580,000 barrels per day.
Chevron has future rights to increase its equity ownership to
29 percent.
Chevron processes imported and domestic crude oil in its
U.S. refining operations. Imported crude oil accounted for
about 87 percent of Chevrons U.S. refinery
inputs in 2007 and 2006, respectively.
Gas-to-Liquids
Through the Sasol Chevron Global
50-50 Joint
Venture, the company is pursuing gas-to-liquids (GTL)
opportunities in several countries.
In Nigeria, Chevron and the Nigerian National Petroleum
Corporation are developing a 34,000-barrel-per-day GTL facility
at Escravos designed to process natural gas supplied from the
Phase 3A expansion of the Escravos Gas Plant (EGP). As of early
2008, approximately 90 percent of engineering and
procurement activities had been completed. Chevron has a
75 percent interest in the plant, which is expected to be
operational by the end of the decade. Refer also to page 16
for a discussion on the EGP Phase 3A expansion.
26
Marketing
Operations
The company markets petroleum products throughout much of the
world. The principal brands for identifying these products are
Chevron, Texaco and Caltex.
The table below identifies the companys and
affiliates refined products sales volumes, excluding
intercompany sales, for the three years ending December 31,
2007.
Refined
Products Sales
Volumes1
(Thousands
of Barrels per Day)
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
2006
|
|
2005
|
|
United States
|
|
|
|
|
|
|
|
|
|
Gasolines
|
|
|
728
|
|
|
712
|
|
|
709
|
Jet Fuel
|
|
|
271
|
|
|
280
|
|
|
291
|
Gas Oils and Kerosene
|
|
|
221
|
|
|
252
|
|
|
231
|
Residual Fuel Oil
|
|
|
138
|
|
|
128
|
|
|
122
|
Other Petroleum
Products2
|
|
|
99
|
|
|
122
|
|
|
120
|
|
|
|
|
|
|
|
|
|
|
Total United States
|
|
|
1,457
|
|
|
1,494
|
|
|
1,473
|
|
|
|
|
|
|
|
|
|
|
International3
|
|
|
|
|
|
|
|
|
|
Gasolines
|
|
|
581
|
|
|
595
|
|
|
662
|
Jet Fuel
|
|
|
274
|
|
|
266
|
|
|
258
|
Gas Oils and Kerosene
|
|
|
730
|
|
|
776
|
|
|
781
|
Residual Fuel Oil
|
|
|
271
|
|
|
324
|
|
|
404
|
Other Petroleum
Products2
|
|
|
171
|
|
|
166
|
|
|
147
|
|
|
|
|
|
|
|
|
|
|
Total International
|
|
|
2,027
|
|
|
2,127
|
|
|
2,252
|
|
|
|
|
|
|
|
|
|
|
Total
Worldwide3
|
|
|
3,484
|
|
|
3,621
|
|
|
3,725
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
Includes buy/sell arrangements. Refer to Note 13 on
page FS-42.
|
|
|
|
|
|
|
50
|
|
|
|
217
|
|
2
|
|
Principally naphtha, lubricants, asphalt and coke.
|
|
|
|
|
|
|
|
|
|
|
|
|
3
|
|
Includes share of equity affiliates sales:
|
|
|
492
|
|
|
|
492
|
|
|
|
498
|
|
In the United States, the company markets under the Chevron and
Texaco brands. The company supplies directly or through
retailers and marketers approximately 9,700 Chevron- and
Texaco-branded motor vehicle retail outlets, concentrated in the
mid-Atlantic, southern and western states. Approximately 550 of
the outlets are company-owned or -leased stations.
Outside the United States, Chevron supplies directly or through
retailers and marketers approximately 15,400 branded service
stations, including affiliates. In British Columbia, Canada, the
company markets under the Chevron brand. In Europe, the company
markets primarily in the United Kingdom and Ireland under the
Texaco brand. In West Africa, the company operates or leases to
retailers in Benin, Cameroon, Côte dIvoire, 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 companys 50 percent-owned affiliate in
Australia operates using the Caltex, Caltex Woolworths and Ampol
brands.
The company continued the marketing and sale of retail fuels
networks and individual service station sites, focusing on
selected areas outside the United States. In 2007, the company
sold its fuels marketing businesses in Belgium, the Netherlands
and Luxembourg and its retail fuels business in Uruguay. The
company also sold its interest in about 500 individual service
station sites, primarily in the United Kingdom and Latin
America. Since the beginning of 2003, the company has sold its
interests in about 3,300 service station sites. The vast
majority of these sites continue to market company-branded
gasoline through new supply agreements.
The company also manages other marketing businesses globally.
Chevron markets aviation fuel at more than 1,000 airports,
representing a worldwide market share of about 11 percent,
and is a leading marketer of jet fuels in the United States. The
company also markets an extensive line of lubricant and coolant
products under brand names that include Havoline, Delo, Ursa,
Meropa and Taro.
27
Transportation
Operations
Pipelines: Chevron owns and operates an extensive
system of crude oil, refined products, chemicals, natural gas
liquids and natural gas pipelines in the United States. The
company also has direct or indirect interests in other
U.S. and international pipelines. The companys
ownership interests in pipelines are summarized in the following
table.
Pipeline
Mileage at December 31, 2007
|
|
|
|
|
|
|
Net
Mileage1
|
|
United States:
|
|
|
|
|
Crude
Oil2
|
|
|
2,853
|
|
Natural Gas
|
|
|
2,275
|
|
Petroleum
Products3
|
|
|
7,053
|
|
|
|
|
|
|
Total United States
|
|
|
12,181
|
|
International:
|
|
|
|
|
Crude
Oil2
|
|
|
700
|
|
Natural Gas
|
|
|
768
|
|
Petroleum
Products3
|
|
|
426
|
|
|
|
|
|
|
Total International
|
|
|
1,894
|
|
|
|
|
|
|
Worldwide
|
|
|
14,075
|
|
|
|
|
|
|
|
|
|
1
|
|
Partially owned pipelines are included at the companys
equity percentage.
|
2
|
|
Includes gathering lines related to the transportation function.
Excludes gathering lines related to U.S. and international
production activities.
|
3
|
|
Includes refined products, chemicals and natural gas liquids.
|
During 2007, the company led the development of a natural gas
gathering pipeline serving the Piceance Basin in northwest
Colorado; participated in the successful installation of the
55-mile
Amberjack-Tahiti lateral pipeline on the seafloor of the
U.S. Gulf of Mexico; and completed a pipeline running from
the U.S. Gulf of Mexico subsea to the Fourchon Terminal in
southern Louisiana. The company is also leading the expansion of
the West Texas liquefied natural gas pipeline system that is
expected to be operational in late 2008. In addition, the
company continued with its project to expand capacity by about
2 billion cubic feet at its Keystone natural gas storage
facility, which is expected to be completed in 2009.
Chevron has a 15 percent interest in the Caspian Pipeline
Consortium (CPC) affiliate. CPC operates a crude oil export
pipeline from the Tengiz Field in Kazakhstan to the Russian
Black Sea port of Novorossiysk. During 2007, CPC transported an
average of approximately 700,000 barrels of crude oil per
day, including 545,000 barrels per day from Kazakhstan and
155,000 barrels per day from Russia. For information
related to the possible expansion of the CPC pipeline, refer to
page 24.
The company has a 9 percent interest in the
Baku-Tbilisi-Ceyhan (BTC) affiliate, whose pipeline transports
Azerbaijan International Operating Company (AIOC) (owned
10 percent by Chevron) production from Baku, Azerbaijan,
through Georgia to deepwater port facilities in Ceyhan, Turkey.
The BTC pipeline has a crude-oil capacity of 1 million
barrels per day and transports the majority of the AIOC
production. Another crude oil production export route is the
Western Route Export 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 West
African Gas Pipeline, refer to page 16.
28
Tankers: At any given time during 2007, the company
had approximately 80 vessels chartered on a voyage basis,
or for a period of less than one year. Additionally, all tankers
in Chevrons controlled seagoing fleet were utilized during
2007. The following table summarizes cargo transported on the
companys controlled fleet.
Controlled
Tankers at December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Flag
|
|
|
Foreign Flag
|
|
|
|
|
|
|
Cargo Capacity
|
|
|
|
|
|
Cargo Capacity
|
|
|
|
Number
|
|
|
(Millions of Barrels)
|
|
|
Number
|
|
|
(Millions of Barrels)
|
|
|
Owned
|
|
|
3
|
|
|
|
0.8
|
|
|
|
1
|
|
|
|
1.1
|
|
Bareboat Chartered
|
|
|
1
|
|
|
|
0.3
|
|
|
|
19
|
|
|
|
28.1
|
|
Time Chartered*
|
|
|
|
|
|
|
|
|
|
|
24
|
|
|
|
14.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
4
|
|
|
|
1.1
|
|
|
|
44
|
|
|
|
43.5
|
|
Federal law requires that cargo transported between
U.S. ports be carried in ships built and registered in the
United States, owned and operated by U.S. entities, and
manned by U.S. crews. In 2007, the companys
U.S. flag fleet was engaged primarily in transporting
refined products between the Gulf Coast and the East Coast and
from California refineries to terminals on the West Coast and in
Alaska and Hawaii. Three
U.S.-flagged
product tankers, each capable of carrying 300,000 barrels
of cargo, are scheduled for delivery from 2008 through 2010.
The foreign-flagged vessels were engaged primarily in
transporting crude oil from the Middle East, Asia, the Black
Sea, Mexico and West Africa to ports in the United States,
Europe, Australia and Asia. Refined products were also
transported by tanker worldwide. During 2007, the company took
delivery of one new double-hulled tanker, with a total capacity
of 500,000 barrels, and one
U.S.-flagged
product tanker capable of carrying 300,000 barrels of
cargo. The company also returned a
1 million-barrel-capacity
crude tanker at the end of its lease.
In addition to the vessels described above, the company owns a
one-sixth interest in each of seven liquefied natural gas (LNG)
tankers transporting cargoes for the North West Shelf (NWS)
Venture in Australia. The NWS project also has two LNG tankers
under long-term time charter. In 2005, Chevron placed orders for
two company-owned LNG tankers.
The Federal Oil Pollution Act of 1990 requires the phase-out by
year-end 2010 of all single-hull tankers trading to
U.S. ports or transferring cargo in waters within the
U.S. Exclusive Economic Zone. This has raised the demand
for double-hull tankers. At the end of 2007, 100 percent of
the companys owned and bareboat-chartered fleet was
double-hulled.
The company is a member of many oil-spill-response cooperatives
in areas in which it operates around the world.
Chemicals
Chevron Phillips Chemical Company LLC (CPChem) is equally owned
with ConocoPhillips Corporation. At the end of 2007, CPChem
owned or had joint venture interests in 30 manufacturing
facilities and six research and technical centers in Belgium,
China, Puerto Rico, Qatar, Saudi Arabia, Singapore, South Korea
and the United States.
In 2007, CPChem completed construction on the integrated,
world-scale styrene facility in Al Jubail, Saudi Arabia. Jointly
owned with the Saudi Industrial Investment Group (SIIG),
commercial production is expected to commence in mid-2008. The
styrene facility is located adjacent to CPChem and SIIGs
existing aromatics complex in Al Jubail. Also during 2007,
CPChem secured final approval for a third petrochemical project
in Al Jubail. Construction began in early 2008, with expected
completion in 2011. 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 the first half of 2008, commercial
operations are expected to begin for the Americas Styrenics
joint venture between CPChem and Dow Chemical Company that
combines CPChems styrene and polystyrene operations with
Dows polystyrene operations.
CPChem continued construction during 2007 on the
49 percent-owned Q-Chem II project in Mesaieed, Qatar.
The project includes a 350,000-metric-ton-per-year polyethylene
plant and a 345,000-metric-ton-per-year normal alpha olefins
plant each utilizing CPChem proprietary
technology and is located adjacent to the existing
Q-Chem I complex. Q-Chem II also includes a separate joint
venture to develop a 1.3 million-metric-ton-per-year
ethylene cracker at Qatars Ras Laffan Industrial City, in
which Q-Chem II owns 54 percent of the capacity
rights. CPChem and its
29
partners expect to start up the plants in the first half of
2009. Construction also began during 2007 of the
Ryton®
polyphenylene sulfide manufacturing facility in Texas, with
completion scheduled for 2009.
Chevrons Oronite brand lubricant and fuel additives
business is a leading developer, manufacturer and marketer of
performance additives for lubricating oils and fuels. The
company owns and operates facilities in Brazil, France, Japan,
the Netherlands, Singapore and the United States and has equity
interests in facilities in India and Mexico. Oronite provides
additives for lubricating oil in most engine applications, such
as passenger car, heavy-duty diesel, marine, locomotive and
motorcycle engines, and additives for fuels to improve engine
performance and extend engine life. Oronite has completed
construction of the new carboxylate detergent unit in France.
This facility will produce new sulfur-free detergent components
for marine engine applications and low-sulfur components for
automotive engine oil applications. Full commercial production
from this facility is expected to commence early in the second
quarter 2008.
Other
Businesses
Mining
Chevrons
U.S.-based
mining company produces and markets coal, molybdenum, rare earth
minerals and calcined petroleum coke. Sales occur in both
U.S. and international markets.
In 2007, the companys coal mining and marketing
subsidiary, The Pittsburg & Midway Coal Mining Co.
(P&M), changed its name to Chevron Mining Inc.
(CMI) and merged with Molycorp Inc., another Chevron mining
subsidiary, to form a single Chevron mining entity. The company
owns and operates two surface coal mines, McKinley, in New
Mexico, and Kemmerer, in Wyoming, and one underground coal mine,
North River, in Alabama. Sales of coal from CMIs wholly
owned mines were 12 million tons, down about 1 million
tons from 2006.
At year-end 2007, CMI controlled approximately 214 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.
In addition to the coal operations, Chevron owns and operates
the Questa molybdenum mine in New Mexico and the Mountain Pass
rare earth mine in California. At year-end 2007, CMI controlled
approximately 57 million pounds of proven molybdenum
reserves at Questa and 241 million pounds of proven and
probable rare earth reserves at Mountain Pass.
Chevron also owns a 33 percent interest in Sumikin
Molycorp, a manufacturer of neodymium compounds, located in
Japan, and a 50 percent interest in Youngs Creek Mining
Company LLC, a joint venture to develop a coal mine in northern
Wyoming. 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.
Power
Generation
Chevrons power generation business develops and operates
commercial power projects and owns 15 power assets located in
the United States and Asia. The company 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
companys geothermal operations and renewable energy
projects, refer to pages 19 and 20, and the Research and
Technology section below, respectively.
Chevron
Energy Solutions
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
30
projects completed by CES in 2007 include energy efficiency
installations for the state of Colorado government facilities
and a 1.1 megawatt solar system at Californias Fresno
State University.
Research
and Technology
The companys Energy Technology Company (ETC) supports
Chevrons upstream and downstream businesses. ETC provides
technology and competency support in earth sciences; reservoir
and production engineering; drilling and completions; facilities
engineering; health, environment and safety; refining; technical
computing; strategic planning; and organizational capability.
Technology Ventures Company manages investments and projects in
emerging energy technologies and their integration into
Chevrons core businesses. Its activities are managed
through four business units: Venture Capital, Biofuels, Hydrogen
and Emerging Energy.
Information Technology Company integrates computing,
telecommunications, data management, security and network
technology to provide a standardized digital infrastructure for
Chevrons global operations.
During 2007, the company entered into research alliances with
Texas A&M University, with focus on the production and
conversion of crops for biofuels from cellulose, and the
Colorado Center for Biorefining and Biofuel, with focus on
conversion technologies. The company also has research alliances
with the University of California, Davis and the Georgia
Institute of Technology that are focused on converting
cellulosic biomass into transportation fuels.
Chevrons research and development expenses were
$562 million, $468 million and $316 million for
the years 2007, 2006 and 2005, respectively.
Some of the investments the company makes in the areas described
above are in new or unproven technologies and business
processes, and ultimate successes are not certain. Although not
all initiatives may prove to be economically viable, the
companys overall investment in this area is not
significant to the companys consolidated financial
position.
Environmental
Protection
Virtually all aspects of the companys businesses are
subject to various U.S. federal, state and local
environmental, health and safety laws and regulations and to
similar laws and regulations in other countries. These
regulatory requirements continue to change and increase in both
number and complexity and to govern not only the manner in which
the company conducts its operations, but also the products it
sells. Chevron expects more environment-related regulations in
the countries where it has operations. Most of the costs of
complying with the many laws and regulations pertaining to its
operations are embedded in the normal costs of conducting
business.
In 2007, the companys U.S. capitalized environmental
expenditures were approximately $350 million, representing
approximately 5 percent of the companys total
consolidated U.S. capital and exploratory expenditures.
These environmental expenditures include capital outlays to
retrofit existing facilities as well as those associated with
new facilities. The expenditures are predominantly in the
upstream and downstream segments and relate mostly to air- and
water-quality projects and activities at the companys
refineries, oil and gas producing facilities, and marketing
facilities. For 2008, the company estimates U.S. capital
expenditures for environmental control facilities will be
approximately $580 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 companys 2007 environmental
expenditures, remediation provisions and year-end environmental
reserves are contained in Managements Discussion and
Analysis of Financial Condition and Results of Operations on
pages FS-16
and FS-17.
Web Site
Access to SEC Reports
The companys Internet Web site can be found at
www.chevron.com. Information contained on the
companys Internet Web site is not part of this Annual
Report on
Form 10-K.
The companys Annual Reports on
Form 10-K,
Quarterly Reports on
Form 10-Q,
Current Reports on
Form 8-K
and any amendments to these reports filed or furnished pursuant
to Section 13(a) or 15(d) of the Securities Exchange Act of
1934 are available on the companys Web site soon after
such reports are filed with or furnished to the Securities and
Exchange Commission (SEC). The reports are also available at the
SECs Web site, www.sec.gov.
31
Item 1A. Risk
Factors
Chevron is a major fully integrated petroleum company with a
diversified business portfolio, a strong balance sheet, and a
history of generating sufficient cash to fund capital and
exploratory expenditures and to pay dividends. Nevertheless,
some inherent risks could materially impact the companys
financial results of operations or financial condition.
Chevron
is exposed to the effects of changing commodity
prices.
Chevron is primarily in a commodities business with a history of
price volatility. The single largest variable that affects the
companys results of operations is 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 Chevrons business will decline if the company
does not successfully develop resources.
The company is in an extractive business; therefore, if Chevron
is not successful in replacing the crude oil and natural gas it
produces with good prospects for future production, the
companys business will decline. Creating and maintaining
an inventory of projects depends on many factors, including
obtaining and renewing rights to explore, develop and produce
hydrocarbons; drilling success; ability to bring long-lead-time,
capital-intensive projects to completion on budget and schedule;
and efficient and profitable operation of mature properties.
The
companys operations could be disrupted by natural or human
factors.
Chevron operates in both urban areas and remote and sometimes
inhospitable regions. The companys operations and
facilities are therefore subject to disruption from either
natural or human causes, including hurricanes, floods and other
forms of severe weather, war, civil unrest and other political
events, fires, earthquakes, and explosions, any of which could
result in suspension of operations or harm to people or the
natural environment.
Chevrons
business subjects the company to liability risks.
The company produces, transports, refines and markets materials
with potential toxicity, and it purchases, handles and disposes
of other potentially toxic materials in the course of the
companys business. Chevron operations also produce
byproducts, which may be considered pollutants. Any of these
activities could result in liability, either as a result of an
accidental, unlawful discharge or as a result of new conclusions
on the effects of the companys operations on human health
or the environment.
Political
instability could harm Chevrons business.
The companys operations, particularly exploration and
production, can be affected by changing economic, regulatory and
political environments in the various countries in which it
operates. As has occurred in the past, actions could be taken by
governments to increase public ownership of the companys
partially or wholly owned businesses
and/or to
impose additional taxes or royalties.
In certain locations, governments have imposed restrictions,
controls and taxes, and in others, political conditions have
existed that may threaten the safety of employees and the
companys continued presence in those countries. Internal
unrest, acts of violence or strained relations between a
government and the company or other governments may affect the
companys operations. Those developments have, at times,
significantly affected the companys related operations and
results and are carefully considered by management when
evaluating the level of current and future activity in such
countries. At December 31, 2007, 26 percent of the
companys proved reserves were located in Kazakhstan. The
company also has significant interests in Organization of
Petroleum Exporting Countries (OPEC) member
countries including Angola, Indonesia, Nigeria and Venezuela.
Twenty-eight percent of the companys net proved reserves,
including affiliates, were located in OPEC countries at
December 31, 2007.
32
Regulation
of greenhouse gas emissions could increase Chevrons
operational costs and reduce demand for Chevrons
products.
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 companys operations. Although uncertain, these
developments could increase costs or reduce the demand for the
products the company sells. The companys production and
processing operations (e.g., the production of crude oil at
offshore platforms and the processing of natural gas at
liquefied natural gas facilities) typically result in 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 greenhouse gas emissions that may
be regulated.
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 Californias
greenhouse gas emissions at 1990 levels by 2020; directs the Air
Resources Board, the responsible state agency, to determine
certain 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 Air Resources
Board and the California Energy Commission are also in the
process of developing a Low Carbon Fuel Standard for
transportation fuels used in California, as directed by Governor
Arnold Schwarzenegger. The company extracts crude oil and
natural gas, operates refineries, and markets and sells
gasoline, diesel and jet fuel in California. The extent to which
the state and local agencies regulations will affect the
companys California operations was not known as of early
2008.
|
|
Item 1B.
|
Unresolved
Staff Comments
|
None.
The location and character of the companys crude oil,
natural gas and mining properties and its refining, marketing,
transportation and chemicals facilities are described on
page 3 under Item 1. Business. Information required by
the Securities Exchange Act Industry Guide No. 2
(Disclosure of Oil and Gas Operations) is also
contained in Item 1 and in Tables I through VII on pages
FS-61 to FS-74. Note 12, Properties, Plant and
Equipment, to the companys financial statements is
on
page FS-42.
|
|
Item 3.
|
Legal
Proceedings
|
In January 2008, Chevron agreed to pay the state of New York a
$162,500 civil penalty in connection with a February 2006 oil
spill at the companys facility in Perth Amboy, New Jersey.
|
|
Item 4.
|
Submission
of Matters to a Vote of Security Holders
|
None.
33
PART II
Item 5. Market
for the Registrants Common Equity, Related Stockholder
Matters and Issuer Purchases of Equity Securities
The information on Chevrons common stock market prices,
dividends, principal exchanges on which the stock is traded and
number of stockholders of record is contained in the Quarterly
Results and Stock Market Data tabulations, on
page FS-24.
CHEVRON
CORPORATION
ISSUER
PURCHASES OF EQUITY SECURITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maximum
|
|
|
|
|
|
|
|
|
|
Total Number of
|
|
|
Number of Shares
|
|
|
|
Total Number
|
|
|
Average
|
|
|
Shares Purchased as
|
|
|
that May Yet be
|
|
|
|
of Shares
|
|
|
Price Paid
|
|
|
Part of Publicly
|
|
|
Purchased Under
|
|
Period
|
|
Purchased(1)(2)
|
|
|
per Share
|
|
|
Announced Program
|
|
|
the Program
|
|
|
Oct. 1 Oct. 31, 2007
|
|
|
4,225,293
|
|
|
|
92.09
|
|
|
|
4,038,000
|
|
|
|
|
|
Nov. 1 Nov. 30, 2007
|
|
|
10,455,696
|
|
|
|
86.46
|
|
|
|
10,200,000
|
|
|
|
|
|
Dec. 1 Dec. 31, 2007
|
|
|
8,375,829
|
|
|
|
90.82
|
|
|
|
8,221,763
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Oct. 1 Dec. 31, 2007
|
|
|
23,056,818
|
|
|
|
89.08
|
|
|
|
22,459,763
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Includes 42,494 common shares repurchased during the three-month
period ended December 31, 2007, from company employees for
required personal income tax withholdings on the exercise of the
stock options issued to management and employees under the
companys broad-based employee stock options, long-term
incentive plans and former Texaco Inc. stock option plans. Also
includes 554,561 shares delivered or attested to in
satisfaction of the exercise price by holders of certain former
Texaco Inc. employee stock options exercised during the
three-month period ended December 31, 2007.
|
|
(2)
|
In September 2007, the company authorized stock repurchases of
up to $15 billion that may be made from time to time at
prevailing prices as permitted by securities laws and other
requirements and subject to market conditions and other factors.
The program will occur over a period of up to three years and
may be discontinued at any time. As of December 31, 2007,
23,530,209 shares had been acquired under this program for
$2.1 billion.
|
Item 6. Selected
Financial Data
The selected financial data for years 2003 through 2007 are
presented on
page FS-60.
Item 7. Managements
Discussion and Analysis of Financial Condition and Results of
Operation
The index to Managements Discussion and Analysis,
Consolidated Financial Statements and Supplementary Data is
presented on
page FS-1.
Item 7A. Quantitative
and Qualitative Disclosures About Market Risk
The companys discussion of interest rate, foreign currency
and commodity price market risk is contained in
Managements Discussion and Analysis of Financial Condition
and Results of Operations Financial and
Derivative Instruments, beginning on
page FS-14
and in Note 7 to the Consolidated Financial Statements,
Financial and Derivative Instruments, beginning on
page FS-36.
Item 8. Financial
Statements and Supplementary Data
The index to Managements Discussion and Analysis,
Consolidated Financial Statements and Supplementary Data is
presented on
page FS-1.
34
Item 9. Changes
in and Disagreements With Accountants on Accounting and
Financial Disclosure
None.
Item 9A. Controls
and Procedures
(a) Evaluation of Disclosure Controls
and Procedures
Chevron Corporations Chief Executive Officer and Chief
Financial Officer, after evaluating the effectiveness of the
companys 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, 2007, have concluded that
as of December 31, 2007, the companys 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 companys periodic filings under the
Exchange Act would be made known to them by others within those
entities.
(b) Managements Report on
Internal Control Over Financial Reporting
The companys management is responsible for establishing
and maintaining adequate internal control over financial
reporting, as such term is defined in Exchange Act
Rules 13a-15(f).
The companys management, including the Chief Executive
Officer and Chief Financial Officer, conducted an evaluation of
the effectiveness of the companys internal control over
financial reporting based on the Internal Control
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on the results
of this evaluation, the companys management concluded that
internal control over financial reporting was effective as of
December 31, 2007.
The effectiveness of the companys internal control over
financial reporting as of December 31, 2007, has been
audited by PricewaterhouseCoopers LLP, an independent registered
public accounting firm, as stated in its report included on
page FS-26.
(c) Changes in Internal Control Over
Financial Reporting
During the quarter ended December 31, 2007, there were no
changes in the companys internal control over financial
reporting that have materially affected, or are reasonably
likely to materially affect, the companys internal control
over financial reporting.
Item 9B. Other
Information
None.
35
PART III
|
|
Item 10.
|
Directors,
Executive Officers and Corporate Governance
|
Executive
Officers of the Registrant at February 28, 2008
The Executive Officers of the Corporation consist of the
Chairman of the Board, the Vice Chairman of the Board, and such
other officers of the Corporation who are members of the
Executive Committee.
|
|
|
|
|
|
|
Name and Age
|
|
Current and Prior Positions (up to five years)
|
|
Current Areas of Responsibility
|
|
D.J. OReilly
|
|
61
|
|
Chairman of the Board and Chief Executive Officer (since 2000)
|
|
Chief Executive Officer
|
P.J. Robertson
|
|
61
|
|
Vice Chairman of the Board (since 2002) President of Chevron
Overseas
Petroleum Inc. (2000 to 2002)
|
|
Policy, Government and Public Affairs; Human Resources
|
J.E. Bethancourt
|
|
56
|
|
Executive Vice President (since 2003) Vice President of Human
Resources
(2001 to 2003)
|
|
Technology; Chemicals; Mining; Health, Environment and Safety
|
G.L. Kirkland
|
|
57
|
|
Executive Vice President (since 2005) President of Chevron
Overseas
Petroleum Inc. (2002 to 2004)
President of Chevron U.S.A. Production Company (2000
to 2002)
|
|
Worldwide Exploration and Production Activities and Global Gas
Activities, including Natural Gas Trading
|
J.S. Watson
|
|
51
|
|
Executive Vice President (since 2008) Vice President and
President of Chevron
International Exploration and Production Company
(2005 through 2007)
Vice President and Chief Financial
Officer (2000 through 2004)
|
|
Business Development; Mergers and Acquisitions; Strategic
Planning; Project Resources Company
|
M.K. Wirth
|
|
47
|
|
Executive Vice President (since 2006) President of Global Supply
and Trading
(2004 to 2006)
President of Marketing, Asia, Middle East and Africa
Marketing
Business Unit (2001 to 2004)
|
|
Global Refining, Marketing, Lubricants, and Supply and Trading,
excluding Natural Gas Trading
|
S.J. Crowe
|
|
60
|
|
Vice President and Chief Financial
Officer (since 2005)
Vice President and Comptroller
(from 2000 through 2004)
|
|
Finance
|
C.A. James
|
|
53
|
|
Vice President and General Counsel
(since 2002)
|
|
Law
|
The information on Directors appearing under the heading
Election of Directors Nominees for
Directors in the Notice of the 2008 Annual Meeting of
Stockholders and 2008 Proxy Statement, to be filed pursuant to
Rule 14a-6(b)
under the Securities Exchange Act of 1934 (the Exchange
Act), in connection with the companys 2008 Annual
Meeting of Stockholders (the 2008 Proxy Statement),
is incorporated by reference in this Annual Report on
Form 10-K.
The information contained under the heading Stock
Ownership Information Section 16(a) Beneficial
Ownership Reporting Compliance in the 2008 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 2008 Proxy Statement is incorporated by reference in this
Annual Report on
Form 10-K.
The information contained under the heading Board
Operations Board Committee Membership and
Functions in the 2008 Proxy Statement is incorporated by
reference in this Annual Report on
Form 10-K.
There were no changes to the process by which stockholders may
recommend nominees to the Board of Directors during the last
fiscal year.
36
Item 11. Executive
Compensation
The information appearing under the headings Executive
Compensation and Directors Compensation
in the 2008 Proxy Statement is incorporated herein by reference
in this Annual Report on
Form 10-K.
The information contained under the heading Board
Operations Board Committee Membership and
Functions in the 2008 Proxy Statement is incorporated by
reference in this Annual Report on
Form 10-K.
The information appearing under the heading Management
Compensation Committee Report in the 2008 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 2008 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.
Item 12. Security
Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
The information appearing under the heading Stock
Ownership Information Security Ownership of Certain
Beneficial Owners and Management in the 2008 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 2008 Proxy Statement
is incorporated by reference in this Annual Report on
Form 10-K.
Item 13. Certain
Relationships and Related Transactions, and Director
Independence
The information appearing under the heading Board
Operations Transactions With Related Persons
in the 2008 Proxy Statement is incorporated by reference in this
Annual Report on
Form 10-K.
Item 14. Principal
Accounting Fees and Services
The information appearing under the heading Ratification
of Independent Registered Public Accounting Firm in the
2008 Proxy Statement is incorporated by reference in this Annual
Report on
Form 10-K.
37
PART IV
|
|
Item 15.
|
Exhibits,
Financial Statement Schedules
|
(a) The following documents are filed as part of this
report:
(1) Financial
Statements:
|
|
|
|
|
Page(s)
|
|
Report of Independent Registered Public Accounting
Firm PricewaterhouseCoopers LLP
|
|
FS-26
|
Consolidated Statement of Income for the three years ended
December 31, 2007
|
|
FS-27
|
Consolidated Statement of Comprehensive Income for the three
years ended December 31, 2007
|
|
FS-28
|
Consolidated Balance Sheet at December 31, 2007 and 2006
|
|
FS-29
|
Consolidated Statement of Cash Flows for the three years ended
December 31, 2007
|
|
FS-30
|
Consolidated Statement of Stockholders Equity for the
three years ended December 31, 2007
|
|
FS-31
|
Notes to the Consolidated Financial Statements
|
|
FS-32 to FS-58
|
(2) Financial
Statement Schedules:
|
|
|
|
|
We have included, on page 39, Schedule II
Valuation and Qualifying Accounts.
|
(3) Exhibits:
|
|
|
|
|
The Exhibit Index on pages
E-1 and
E-2 lists
the exhibits that are filed as part of this report.
|
38
SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
Millions of Dollars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Employee Termination Benefits:
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1
|
|
$
|
28
|
|
|
$
|
91
|
|
|
$
|
137
|
|
Additions (deductions) charged (credited) to expense
|
|
|
106
|
|
|
|
(21
|
)
|
|
|
(21
|
)
|
Additions related to Unocal acquisition
|
|
|
|
|
|
|
|
|
|
|
106
|
|
Payments
|
|
|
(17
|
)
|
|
|
(42
|
)
|
|
|
(131
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31
|
|
$
|
117
|
|
|
$
|
28
|
|
|
$
|
91
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for Doubtful Accounts:
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1
|
|
$
|
217
|
|
|
$
|
198
|
|
|
$
|
219
|
|
Additions charged to expense
|
|
|
29
|
|
|
|
61
|
|
|
|
3
|
|
Additions related to Unocal acquisition
|
|
|
|
|
|
|
|
|
|
|
6
|
|
Bad debt write-offs
|
|
|
(46
|
)
|
|
|
(42
|
)
|
|
|
(30
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31
|
|
$
|
200
|
|
|
$
|
217
|
|
|
$
|
198
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred Income Tax Valuation Allowance:*
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1
|
|
$
|
4,391
|
|
|
$
|
3,249
|
|
|
$
|
1,661
|
|
Additions charged to deferred income tax expense
|
|
|
1,894
|
|
|
|
1,700
|
|
|
|
1,593
|
|
Additions related to Unocal acquisition
|
|
|
|
|
|
|
|
|
|
|
400
|
|
Deductions credited to goodwill
|
|
|
|
|
|
|
(77
|
)
|
|
|
(60
|
)
|
Deductions credited to deferred income tax expense
|
|
|
(336
|
)
|
|
|
(481
|
)
|
|
|
(345
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31
|
|
$
|
5,949
|
|
|
$
|
4,391
|
|
|
$
|
3,249
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
See also Note 15 to the
Consolidated Financial Statements beginning on
page FS-43.
|
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized, on the 28th day of February,
2008.
Chevron Corporation
David J. OReilly, Chairman of the Board
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the Registrant and in the capacities indicated on
the 28th day of February, 2008.
|
|
|
Principal Executive Officers
|
|
|
(and Directors)
|
|
Directors
|
|
/s/David J.
OReilly
David J. OReilly, Chairman of the
Board and Chief Executive Officer
|
|
Samuel H. Armacost*
Samuel H. Armacost
|
|
|
|
/s/Peter J.
Robertson
Peter J. Robertson, Vice Chairman of the Board
|
|
Linnet F. Deily*
Linnet F. Deily
|
|
|
|
|
|
Robert E. Denham*
Robert E. Denham
|
|
|
|
|
|
Robert J. Eaton*
Robert J. Eaton
|
|
|
|
Principal Financial Officer
|
|
Sam Ginn*
Sam Ginn
|
/s/Stephen J. Crowe
Stephen J. Crowe, Vice President and Chief Financial
Officer
|
|
Franklyn G.
Jenifer*
Franklyn G. Jenifer
|
|
|
|
Principal Accounting Officer
|
|
|
/s/Mark A. Humphrey
Mark A. Humphrey, Vice President and Comptroller
|
|
Sam Nunn*
Sam Nunn
|
|
|
|
|
|
Donald B. Rice*
Donald B. Rice
|
|
|
|
*By: /s/Lydia I.
Beebe
Lydia I. Beebe,
Attorney-in-Fact
|
|
Kevin W. Sharer*
Kevin W. Sharer
|
|
|
Charles R.
Shoemate*
Charles R. Shoemate
|
|
|
|
|
|
Ronald D. Sugar*
Ronald D. Sugar
|
|
|
|
|
|
Carl Ware*
Carl Ware
|
40
(This Page
Intentionally Left Blank)
INDEX TO MANAGEMENTS DISCUSSION AND ANALYSIS,
CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
FS-1
|
Managements Discussion and Analysis of
Financial Condition and Results of Operations |
Key Financial Results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars, except per-share amounts |
|
2007 |
|
|
|
2006 |
|
|
2005 |
|
|
|
|
|
Net Income |
|
$ |
18,688 |
|
|
|
$ |
17,138 |
|
|
$ |
14,099 |
|
Per Share Amounts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Basic |
|
$ |
8.83 |
|
|
|
$ |
7.84 |
|
|
$ |
6.58 |
|
Diluted |
|
$ |
8.77 |
|
|
|
$ |
7.80 |
|
|
$ |
6.54 |
|
Dividends |
|
$ |
2.26 |
|
|
|
$ |
2.01 |
|
|
$ |
1.75 |
|
Sales and Other
Operating Revenues |
|
$ |
214,091 |
|
|
|
$ |
204,892 |
|
|
$ |
193,641 |
|
Return on: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Capital Employed |
|
|
23.1 |
% |
|
|
|
22.6 |
% |
|
|
21.9 |
% |
Average Stockholders Equity |
|
|
25.6 |
% |
|
|
|
26.0 |
% |
|
|
26.1 |
% |
|
|
|
|
Income by Major Operating Area
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2007 |
|
|
|
2006 |
|
|
2005 |
|
|
|
|
|
Upstream Exploration and Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
4,532 |
|
|
|
$ |
4,270 |
|
|
$ |
4,168 |
|
International |
|
|
10,284 |
|
|
|
|
8,872 |
|
|
|
7,556 |
|
|
|
|
|
Total Upstream |
|
|
14,816 |
|
|
|
|
13,142 |
|
|
|
11,724 |
|
|
|
|
|
Downstream Refining, Marketing and Transportation |
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
966 |
|
|
|
|
1,938 |
|
|
|
980 |
|
International |
|
|
2,536 |
|
|
|
|
2,035 |
|
|
|
1,786 |
|
|
|
|
|
Total Downstream |
|
|
3,502 |
|
|
|
|
3,973 |
|
|
|
2,766 |
|
|
|
|
|
Chemicals |
|
|
396 |
|
|
|
|
539 |
|
|
|
298 |
|
All Other |
|
|
(26 |
) |
|
|
|
(516 |
) |
|
|
(689 |
) |
|
|
|
|
Net Income* |
|
$ |
18,688 |
|
|
|
$ |
17,138 |
|
|
$ |
14,099 |
|
|
|
|
|
*Includes Foreign Currency Effects: |
|
|
$ (352) |
|
|
|
|
$ (219) |
|
|
|
$ (61) |
|
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,
2007.
Business Environment and Outlook
Chevron is a global energy company with significant business activities in the following
countries: Angola, Argentina, Australia, Azerbaijan, Bangladesh, Brazil, Cambodia, Canada, Chad,
China, Colombia, Democratic Republic of the Congo, Denmark, France, India, Indonesia, Kazakhstan,
Myanmar, the Netherlands, Nigeria, Norway, the Partitioned Neutral Zone between Saudi Arabia and
Kuwait, the Philippines, Qatar, Republic of the Congo, Singapore, South Africa, South Korea,
Thailand, Trinidad and Tobago, the United Kingdom, the United States, Venezuela and Vietnam.
Current and future earnings of the company depend largely on the profitability of its upstream
(exploration and production) and downstream (refining, marketing and transportation) business
segments. The single biggest factor that affects the results of operations for both segments is
movement in the price of crude oil. In the downstream business, crude oil is the largest cost
component of refined products.
The overall trend in earnings is typically less affected by results from the companys chemicals
business and other activities and 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 continue to experience 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 companys operating expenses and capital expenditures, particularly for the
upstream business. The companys operations, especially upstream, can also be affected by changing
economic, regulatory and political environments in the various countries in which it operates,
including the United States. Civil unrest, acts of violence or strained relations between a
government and the company or other governments may impact the companys operations or investments.
Those developments have at times significantly affected the companys operations and results and
are carefully considered by management when evaluating the level of current and future activity in
such countries.
To sustain its long-term competitive position in the upstream business, the company must
develop and replenish an inventory of projects that offer adequate financial returns for the
investment required. Identifying promising areas for exploration, acquiring the necessary rights to
explore for and to produce crude oil and natural gas, drilling successfully, and handling the many
technical and operational details in a safe and cost-effective manner are all important factors in
this effort. Projects often require long lead times and large capital commitments. 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 companys current
operations or future prospects.
The company also continually evaluates opportunities to dispose of assets that are not
expected to provide sufficient long-term value, or to acquire assets or operations complementary to
its asset base to help augment the companys growth. Asset sales during 2007 included the companys
31 percent ownership interest in a refinery and related assets in the Netherlands; fuels marketing
businesses in Belgium, Luxembourg, the Netherlands and Uruguay; and the investment in common stock
of Dynegy Inc. 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 companys major business areas are as follows:
FS-2
Upstream Earnings for the upstream segment are closely aligned with industry price levels for
crude oil and natural gas. Crude oil and natural gas prices are subject to external factors over
which the company has no control, including product demand connected with global economic
conditions, industry inventory levels, production quotas imposed by the Organization of Petroleum
Exporting Countries (OPEC), weather-related damage and disruptions, competing fuel prices, and
regional supply interruptions or fears thereof that
may be caused by military conflicts, civil unrest or political uncertainty. Moreover, any of these
factors could also inhibit the companys production capacity in an affected region. The company
monitors developments closely in the countries in which it operates and holds investments, and
attempts to manage risks in operating its facilities and business.
Price levels for capital and exploratory costs and operating expenses associated with the
efficient production of crude oil and natural gas can also be subject to external factors beyond
the companys control. External factors include not only the general level of inflation but also
prices charged by the industrys material- and service-providers, which can be affected by the
volatility of the industrys own supply and demand conditions for such materials and services. The
oil and gas industry worldwide has experienced significant price increases for these items since
2005, and future price increases may continue to exceed the general level of inflation. Capital and
exploratory expenditures and operating expenses also can be affected by damages to production
facilities caused by severe weather or civil unrest.
Industry price levels for crude oil increased during 2007. The spot price for West Texas
Intermediate (WTI) crude oil, a benchmark crude oil, averaged $72 per barrel in 2007, up
approximately $6 per barrel from the 2006 average price. The rise in crude oil prices was
attributed primarily to 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. As of mid-February 2008, the WTI price was about $93 per barrel.
As in 2006, a wide differential in prices existed in 2007 between high-quality (i.e.,
high-gravity, low sulfur) crude oils
and those of lower quality (i.e., low-gravity, 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 crude oil has remained high, as the demand for light products, which can be
more easily manufactured by refineries from high-quality crude oil, has been strong worldwide.
Chevron produces or shares in the production of heavy crude oil in California, Chad,
Indonesia, the Partitioned Neutral Zone between Saudi Arabia and Kuwait, Venezuela and certain
fields in Angola, China and the United Kingdom North Sea. (Refer to
page FS-l0 for the
companys 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 in many regional markets are
more closely aligned with supply and demand conditions in those markets. In the United States
during 2007, benchmark prices at Henry Hub averaged about $7 per thousand cubic feet (MCF),
compared with about $6.50 in 2006. As of mid-February 2008, the Henry Hub price was about $8
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. U.S. natural gas prices are also typically higher during the winter period
when demand for heating is greatest.
Certain other regions of the world in which the company operates have different supply, demand
and regulatory circumstances, typically resulting in significantly lower average sales prices for
the companys production of natural gas. (Refer to page FS-l0 for the companys average natural gas
prices for the U.S. and international regions.) Additionally, excess-supply conditions that exist
in certain parts of the world cannot easily serve to mitigate the relatively high-
FS-3
|
Managements
Discussion and Analysis of
Financial Condition and Results of Operations |
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 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
companys ability to find or acquire and efficiently produce crude oil and natural gas, changes in
fiscal terms of contracts, changes in tax rates on income, and the cost of goods and services.
Chevrons worldwide net oil-equivalent production in 2007, including volumes produced from oil
sands, averaged 2.62 million barrels per day, a decline of about 48,000 barrels per day from 2006,
due mainly to the effect of a conversion of operating service agreements in Venezuela to
joint-stock companies. (Refer to the table Selected Operating
Data on page FS-l0 for a listing of
production volumes for each of the three years ending December 31, 2007.) The company estimates
that oil-equivalent production in 2008 will average approximately 2.65 million barrels per day.
This estimate is subject to many uncertainties, including quotas that may be imposed by OPEC, the
price effect on production volumes calculated under cost-recovery and variable-royalty provisions
of certain contracts, changes in fiscal terms or restrictions on the scope of company operations,
delays in project start-ups, weather conditions that may shut in production, civil unrest, changing
geopolitics or other disruptions to operations. Future production levels also are affected by the
size and number of economic investment opportunities and, for new large-scale projects, the time
lag between initial exploration and the beginning of production. Most of Chevrons upstream
investment is currently being made outside the United States. Investments in upstream projects
generally are made well in advance of the start of the associated crude oil and natural gas
production.
Approximately 28 percent of the companys net oil-equivalent production in 2007 occurred in
the OPEC-member countries of Angola, Indonesia, Nigeria and Venezuela and in the Partitioned
Neutral Zone between Saudi Arabia and Kuwait. OPEC quotas did not significantly affect Chevrons production level in 2007.
The impact of OPEC quotas on the companys production in 2008 is
uncertain.
In October 2006, Chevrons Boscan and LL-652 operating service agreements in Venezuela were
converted to Empresas Mixtas (i.e., joint-stock companies), with Petróleos de Venezuela, S.A.
(PDVSA) as majority shareholder. From that time, Chevron reported its equity share of the Boscan
and LL-652 production, which was approximately 85,000 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 companys results of operations, consolidated
financial position or liquidity.
In February 2007, the president of Venezuela issued a decree announcing the governments
intention for PDVSA to take over operational control of all Orinoco Heavy Oil Associations
effective May 1, 2007, and to increase its ownership in all such Associations to a minimum of 60
percent. The decree included Chevrons 30 percent-owned Hamaca project. In April 2007, Chevron
signed a memorandum of understanding (MOU) with PDVSA that summarized the ongoing discussions to
transfer control of Hamaca operations in accordance with the February decree. As provided in the
MOU, a PDVSA-controlled transitory operational committee, on which Chevron had representation,
assumed responsibility for daily operations on May 1, 2007. The MOU stipulated that terms of
existing contracts were to remain in place during the transition period. In December 2007, Chevron
executed a conversion agreement and signed a charter and by-laws with a PDVSA subsidiary that
provided for Chevron to retain its 30 percent interest in the Hamaca project. The new entity,
Petropiar, commenced activities in January 2008. The conversion agreement did not have a material
effect on Chevrons results of operations, consolidated financial position or liquidity.
Refer to pages FS-6 through FS-7 for additional discussion of the companys upstream
operations.
Downstream Earnings for the downstream segment are closely tied to margins on the refining and
marketing of products that include gasoline, diesel, jet fuel, lubricants, fuel oil and feedstocks
for chemical manufacturing. Industry margins are sometimes volatile and can be affected by the
global and regional supply-and-demand balance for refined products and by changes in the price of
crude oil used for refinery feedstock. Industry margins can also be influenced by refined-product
inventory levels, geopolitical events, refinery maintenance programs and disruptions at refineries
resulting from unplanned outages that may be due to severe weather, fires or other operational
events.
Other factors affecting profitability for downstream operations include the reliability and
efficiency of the companys refining and marketing network, the effectiveness of the crude-oil and
FS-4
product-supply functions and the economic returns on invested capital.
Profitability can also be affected by the volatility of tanker charter rates for the companys
shipping operations, which are driven by the industrys demand for crude oil and product
tankers. Other factors beyond the companys control include the general level of inflation and
energy costs to operate the companys refinery and distribution network.
The companys most significant marketing areas are the West Coast of North America, the
U.S. Gulf Coast, Latin America, Asia, sub-Saharan Africa and the United Kingdom. Chevron
operates or has ownership interests in refineries in each of these areas except Latin America. For
the industry, refined-product margins were generally higher in 2007 than in 2006. For the company,
U.S. refined-product margins during 2007 were negatively affected by planned and unplanned downtime
at its three largest U.S. refineries.
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 page FS-7 through FS-8 for additional discussion of the companys downstream
operations.
Chemicals Earnings in the petrochemicals business are closely tied to global chemical demand,
industry inventory levels and plant capacity utilization. Feedstock and fuel costs, which tend to
follow crude oil and natural gas price movements, also influence earnings in this segment.
Refer to page FS-8 for additional discussion of chemicals earnings.
Operating Developments
Key operating developments and other events during 2007 and early 2008 included the
following:
Upstream
Angola Discovered crude oil at the 31 percent-owned and operated Malange-1 well in offshore
Block 14. Additional drilling and geologic and engineering studies are planned to appraise the
discovery. The company and partners also made the final investment decision to construct a
liquefied natural gas (LNG) plant that will be owned 36 percent by Chevron. The plant will be
designed
with a capacity to process 1 billion cubic feet of natural gas per day and produce 5.2 million
metric tons a year of LNG and related gas liquids products.
Australia Received federal and state environmental approvals for development of the 50
percent-owned and operated Gorgon LNG project located off the northwest coast. The approvals
represented a significant milestone towards the development of the companys natural gas resources
offshore Australia.
Bangladesh Began production at the 98 percent-owned Bibiyana natural gas field. The fields
total production is expected to increase to a maximum of 500 million cubic feet per day by 2010.
China Signed a 30-year production-sharing contract with China National Petroleum Corporation
to assume operatorship and hold a 49 percent interest in the development of the Chuandongbei
natural gas area in central China. Design input capacity of the proposed gas plants is expected to
be 740 million cubic feet of natural gas per day.
Indonesia Began commercial operation of the 1l0-megawatt Darajat III geothermal power plant in
Garut, West Java. The plant increased Darajats total capacity to 259 megawatts.
Kazakhstan Initiated production from the first phase of the Sour Gas Injection and Second
Generation Plant expansion projects at the 50 percent-owned Tengiz Field. This phase increased
production capacity by 90,000 barrels of crude oil per day to approximately 400,000. Full facility
expansion is expected to occur during the second-half 2008, increasing production capacity to
540,000 barrels per day.
Republic of the Congo Confirmed two crude oil discoveries in the offshore Moho-Bilondo permit.
Evaluation and development studies were undertaken to appraise the discoveries, in which Chevron
holds a 32 percent nonoperated working interest.
Thailand Signed an agreement to increase sales of natural gas from company-operated Blocks 10,
11, 12 and 13 in the Gulf of Thailand to PTT Public Company Limited. Chevron has ownership
interests ranging from 60 percent to 80 percent in the blocks, which received 10-year
production-period extensions to 2022. The company was also granted the concession rights for a
six-year period to four prospective offshore petroleum blocks, three of which it will operate.
Trinidad and Tobago Signed an agreement to sell natural gas to the National Gas Company of
Trinidad and Tobago for 11 years with an option for a four-year extension. The gas is expected to
be sourced from Chevrons 50 percent-owned East Coast Marine Area.
United States Announced that first production from the Tahiti project in the deepwater Gulf of
Mexico is expected by the third quarter 2009. The start-up is approximately one year later than
originally planned due to metallurgical problems with the mooring shackles for the floating
production facility.
Downstream
Benelux Countries Sold the companys 31 percent interest in the Nerefco Refinery and
related assets in the Netherlands, and the companys fuels marketing businesses in Belgium,
Luxembourg and the Netherlands, resulting in gains totaling $960 million.
FS-5
|
Managements
Discussion and Analysis of
Financial Condition and Results of Operations |
South
Korea Completed construction and commissioned
new facilities associated with a $1.5
billion upgrade at the 50 percent-owned GS Caltex Yeosu Refinery, enabling the refinery to process
heavier and higher-sulfur crude oils and increase the production of gasoline, diesel and other
light products.
United States Approved plans at the companys refinery in Pascagoula, Mississippi, for the
construction of a Continuous Catalyst Regeneration unit, which is expected to increase gasoline
production by 10 percent, or 600,000 gallons per day, by mid-2010. At the refinery in El Segundo,
California, modifications were completed to enable the processing of heavier crude oils into light
transportation fuels and other refined products.
Other
Common Stock Dividends Increased the companys quarterly common stock dividend by 11.5
percent in April to $0.58 per share, marking the 20th consecutive year the company has increased its
annual dividend payment.
Common Stock Repurchase Program Approved a program in September to acquire up to $15 billion
of the companys common stock over a period of up to three years, which followed three stock
repurchase programs of $5 billion each that were completed in 2005, 2006 and September 2007.
Dynegy Sold the companys common stock investment in Dynegy Inc., resulting in a gain of $680
million.
Results of Operations
Major Operating Areas The following section presents the results of operations for the
companys business segments upstream, downstream and chemicals as well as for all other,
which includes mining, power generation businesses, the various companies and departments that are
managed at the corporate level, and the companys investment in Dynegy prior to its sale in May
2007. Income is also presented for the U.S. and international geographic areas of the upstream and
downstream business segments. (Refer to Note 8, beginning on page FS-37, for a discussion of the
companys 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 Exploration and Production
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2007 |
|
|
|
2006 |
|
|
2005 |
|
|
|
|
Income |
|
$ |
4,532 |
|
|
|
$ |
4,270 |
|
|
$ |
4,168 |
|
|
|
|
U.S.
upstream income of $4.5 billion in 2007 increased approximately $260 million from
2006. Results in 2007 benefited approximately $700 million from higher prices for crude oil and
natural gas liquids. This benefit to income was partially offset by the
effects of a decline in
oil-equivalent production and an increase in depreciation, operating and exploration expenses.
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, exploration and
depreciation expenses. Included in the operating expense increases were costs associated with the
carryover effects of hurricanes in the Gulf of Mexico in 2005.
The companys average realization for crude oil and natural gas liquids in 2007 was $63.16 per
barrel, compared with $56.66 in 2006 and $46.97 in 2005. The average natural gas realization was
$6.12 per thousand cubic feet in 2007, compared with $6.29 and $7.43 in 2006 and 2005,
respectively.
Net oil-equivalent production in 2007 averaged 743,000 barrels per day, down 2.6 percent from
2006 and up 2 percent from 2005, which included only five months of production from the Unocal
properties acquired in August of that year. The net liquids component of oil-equivalent production
for 2007 averaged 460,000 barrels a day, which was essentially flat compared with 2006, and an
increase of 1 percent from 2005. Net natural gas production averaged 1.7 billion cubic feet per day
in 2007, down 6 percent from 2006 and up 4 percent from 2005.
FS-6
Refer to the Selected Operating Data table, on page FS-10, for the three-year comparative
production volumes in the United States.
International Upstream - Exploration and Production
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2007 |
|
|
|
2006 |
|
|
2005 |
|
|
|
|
Income* |
|
$ |
10,284 |
|
|
|
$ |
8,872 |
|
|
$ |
7,556 |
|
|
|
|
*Includes Foreign Currency Effects: |
|
|
$ (417) |
|
|
|
|
$ (371) |
|
|
|
$ 14 |
International upstream income of $10.3 billion in 2007 increased $1.4 billion from 2006.
Earnings in 2007 benefited approximately $1.6 billion from higher prices, primarily for crude oil,
and $300 million from increased liftings. Non-recurring income tax items also benefited earnings
between periods. These benefits to income were partially offset by the impact of higher operating
and depreciation expenses.
Income in 2006 of approximately $8.9 billion increased $1.3 billion from 2005. Earnings in
2006 benefited approximately $3 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.
The companys average realization for crude oil and natural gas liquids in 2007 was $65.01 per
barrel, compared with $57.65 in 2006 and $47.59 in 2005. The average natural gas realization was
$3.90 per thousand cubic feet in 2007, compared with $3.73 and $3.19 in 2006 and 2005,
respectively.
Net oil-equivalent production of 1.88 million barrels per day in 2007 declined about 2 percent
from 2006 and increased 5 percent from 2005. The volumes for each year included production from oil
sands in Canada and an operating service agreement in Venezuela until its conversion to a
joint-stock company in October 2006. The decline between 2006 and 2007 was associated with the
impact of this contract conversion in Venezuela and the price effects on production volumes
calculated under production-sharing agreements. Partially offsetting the decline was increased
production in Bangladesh, Angola and Azerbaijan. The increase from 2005 was due to that year having
included only five months of production from the former Unocal properties.
The net liquids component of oil-equivalent production was 1.3 million barrels per day in
2007, a decrease of approximately 4 percent from 2006 and 3 percent from 2005. Net natural gas
production of 3.3 billion cubic feet per day in 2007 was up 5.5 percent and 28 percent from 2006
and 2005, respectively.
Refer to the Selected Operating Data table, on page FS-10, for the three-year comparative of
international production volumes.
US. Downstream - Refining, Marketing and Transportation
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2007 |
|
|
|
2006 |
|
|
2005 |
|
|
|
|
Income |
|
$ |
966 |
|
|
|
$ |
1,938 |
|
|
$ |
980 |
|
|
|
|
U.S. downstream earnings of $966 million in 2007 declined nearly $1 billion from 2006 and
were essentially the same as 2005. The decline in 2007 from 2006 was associated mainly with weaker
refined-product margins due to the effects of higher crude oil prices and the negative impacts of
higher planned and unplanned downtime on refinery production volumes at the companys three major
refineries. Operating expenses were also higher in 2007. The improvement in 2006 earnings from 2005
was primarily associated with higher average refined-product margins in 2006 and the adverse effect
of downtime in 2005 at refining, marketing and pipeline operations that was caused by hurricanes in
the Gulf of Mexico.
Sales volumes of refined products were 1.46 million barrels per day in 2007, a decrease of 3
percent and 1 percent from 2006 and 2005, respectively. The reported sales volume for 2007 was on a
different basis than 2006 and 2005 due to a change in accounting rules that became effective April
1, 2006, for certain purchase and sale (buy/sell) contracts with the same counterparty. Excluding
the impact of this accounting standard, refined-product sales in 2007 decreased 1 percent from 2006
and increased about 5 percent from 2005. Branded gasoline sales volumes of 629,000 barrels per day
in 2007 increased about 2 percent from 2006 and 6 percent from 2005, largely due to growth of the
Texaco brand.
Refer
to the Selected Operating Data table on page FS-l0 for a three-year comparative of
sales volumes of gasoline and other refined products and refinery-input volumes. Refer also to Note
13, Accounting for Buy/Sell Contracts, on page FS-42 for a discussion of the accounting for purchase and sale contracts with the same
counterparty.
FS-7
|
Managements
Discussion and Analysis of
Financial Condition and Results of Operations |
International Downstream Refining, Marketing and Transportation
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2007 |
|
|
|
2006 |
|
|
2005 |
|
|
|
|
Income* |
|
$ |
2,536 |
|
|
|
$ |
2,035 |
|
|
$ |
1,786 |
|
|
|
|
*Includes Foreign Currency Effects: |
|
|
$ 62 |
|
|
|
|
$ 98 |
|
|
|
$(24 |
) |
International downstream income of $2.5 billion in 2007 increased about $500 million from
2006 and $750 million from 2005. Results for 2007 included gains of approximately $1 billion on the
sale of assets, including an interest in a refinery and marketing
assets in the Benelux region of
Europe. Margins on the sale of refined products in 2007 were up slightly from the prior year.
Operating expenses were higher, and earnings from the companys shipping operations were lower. The
increase in earnings in 2006 compared with 2005 was associated mainly with the benefit of higher
refined-product sales margins in the Asia-Pacific area and Canada and improved results from
crude-oil and refined-product trading activities.
Refined-product sales volumes were 2.03 million barrels per day in 2007, about 5 percent and
10 percent lower than 2006 and 2005, respectively, due largely to the impact of asset sales and the
accounting-standard change for buy/sell contracts. Excluding the accounting change, sales decreased
about 4 percent and 5 percent from 2006 and 2005, respectively.
Refer to the Selected Operating Data table on page FS-10 for a three-year comparative of
sales volumes of gasoline and other refined products and refinery-input volumes. Refer also to Note
13, Accounting for Buy/Sell Contracts, on page FS-42 for a discussion of the accounting for
purchase and sale contracts with the same counterparty.
Chemicals
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2007 |
|
|
|
2006 |
|
|
2005 |
|
|
|
|
Income* |
|
$ |
396 |
|
|
|
$ |
539 |
|
|
$ |
298 |
|
|
|
|
*Includes Foreign Currency Effects: |
|
|
$ (3) |
|
|
|
|
$ (8) |
|
|
|
$ |
The chemicals segment includes the companys Oronite subsidiary and the 50 percent-owned
Chevron Phillips Chemical
Company LLC (CPChem). In 2007, earnings were $396 million, compared with $539 million and $298 million in 2006 and 2005, respectively. Between 2006 and 2007, the benefit of
improved margins on sales of lubricants and fuel additives by Oronite was more than offset by the
effect of lower margins on the sale of commodity chemicals by CPChem. In 2006, earnings of $539
million increased about $240 million from 2005 due to higher margins for commodity chemicals at
CPChem and for fuel and lubricant additives at
Oronite.
All Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2007 |
|
|
|
2006 |
|
|
2005 |
|
|
|
|
Net Charges* |
|
$ |
(26 |
) |
|
|
$ |
(516 |
) |
|
$ |
(689 |
) |
|
|
|
|
*Includes Foreign Currency Effects: |
|
|
$ 6 |
|
|
|
|
$ 62 |
|
|
|
(51 |
) |
All Other includes mining operations, power
generation businesses, worldwide cash management and debt
financing activities, corporate administrative functions,
insurance operations, real estate activities, alternative
fuels and technology companies, and the companys interest in
Dynegy prior to its sale in May 2007.
Net charges of $26 million in 2007 decreased $490 million
from 2006. Results in 2007 included a $680 million gain on the
sale of the companys investment in Dynegy common stock and a
loss of approximately $175 million associated with the early
redemption of Texaco Capital Inc. bonds. Excluding these items
and the effects of foreign currency, net charges decreased
about $40 million between periods.
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,
primarily due to higher interest income and lower interest
expense in 2006.
FS-8
Consolidated Statement of Income
Comparative amounts for certain income statement
categories are shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2007 |
|
|
|
2006 |
|
|
2005 |
|
|
|
|
|
|
Sales and other operating revenues |
|
$ |
214,091 |
|
|
|
$ |
204,892 |
|
|
$ |
193,641 |
|
|
|
|
|
|
Sales and other operating revenues in 2007 increased over 2006 due primarily to higher
prices for crude oil, natural gas, natural gas liquids and refined products, partially offset by
lower sales volumes. The increase in 2006 from 2005 was primarily due to higher prices for refined
products. The higher revenues in 2006 were net of an impact from a change in the accounting for
buy/sell contracts, as described in Note 13 on page FS-42.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2007 |
|
|
|
2006 |
|
|
2005 |
|
|
|
|
|
|
Income from equity affiliates |
|
$ |
4,144 |
|
|
|
$ |
4,255 |
|
|
$ |
3,731 |
|
|
|
|
|
|
Lower income from equity affiliates in 2007 was mainly due to a decline in earnings from
CPChem, Dynegy (sold in May 2007) and downstream affiliates in the Asia-Pacific area. Partially
offsetting these declines were improved results for Tengizchevroil (TCO) and income for a full year
from Petroboscan, which was converted from an operating service agreement to a joint-stock company
in October 2006. The increase between 2005 and 2006 was primarily due to improved results for TCO
and CPChem. Refer to Note 11, beginning on page FS-40, for a discussion of Chevrons investment in
affiliated companies.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2007 |
|
|
|
2006 |
|
|
2005 |
|
|
|
|
|
|
Other income |
|
$ |
2,669 |
|
|
|
$ |
971 |
|
|
$ |
828 |
|
|
|
|
|
|
Other income of nearly $2.7 billion in 2007 included the net of gains totaling $1.7
billion from the sale of downstream assets in the Benelux countries and the companys investment in
Dynegy and a loss of approximately $245 million on the early redemption of Texaco debt. Interest
income was approximately $600 million, $600 million and $400 million in 2007, 2006 and 2005,
respectively. Foreign currency losses were $352 million, $260 million and $60 million in the
corresponding years.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2007 |
|
|
|
2006 |
|
|
2005 |
|
|
|
|
|
|
Purchased crude oil and products |
|
$ |
133,309 |
|
|
|
$ |
128,151 |
|
|
$ |
127,968 |
|
|
|
|
|
|
Crude oil and product purchases in 2007 increased from 2006 due to higher prices for crude
oil, natural gas, natural gas liquids and refined products. 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 the full year 2006 vs. five months in 2005. The increase was mitigated
by the effect of the accounting change in April 2006 for buy/sell contracts.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2007 |
|
|
|
2006 |
|
|
2005 |
|
|
|
|
|
|
Operating, selling, general and
administrative expenses |
|
$ |
22,858 |
|
|
|
$ |
19,717 |
|
|
$ |
17,019 |
|
|
|
|
|
|
Operating, selling, general and administrative expenses in 2007 increased 16 percent from
a year earlier. Expenses were higher in a number of categories, with the largest increases recorded
for the cost of employee payroll and contract labor. Total expenses increased in 2006 from 2005 due
mainly to the inclusion of former-Unocal expenses for the full year 2006. Besides this effect,
expenses were higher in 2006 for labor, transportation, and uninsured costs associated with the
hurricanes in 2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2007 |
|
|
|
2006 |
|
|
2005 |
|
|
|
|
|
|
Exploration expense |
|
$ |
1,323 |
|
|
|
$ |
1,364 |
|
|
$ |
743 |
|
|
|
|
|
|
Exploration expenses in 2007 declined from 2006 mainly due to lower amounts for well
write-offs and geological and geophysical costs for operations outside the United States. Expenses
increased in 2006 from 2005 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
Unocal-related amounts for the full year 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2007 |
|
|
|
2006 |
|
|
2005 |
|
|
|
|
|
|
Depreciation, depletion and
amortization |
|
$ |
8,708 |
|
|
|
$ |
7,506 |
|
|
$ |
5,913 |
|
|
|
|
|
|
Depreciation, depletion and amortization expenses increased from 2005 through 2007,
reflecting an increase in charges related to asset write-downs and higher depreciation rates for
certain crude oil and natural gas producing fields worldwide and the inclusion of Unocal-related
amounts beginning in August 2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2007 |
|
|
|
2006 |
|
|
2005 |
|
|
|
|
|
|
Taxes other than on income |
|
$ |
22,266 |
|
|
|
$ |
20,883 |
|
|
$ |
20,782 |
|
|
|
|
|
|
Taxes other than on income increased in 2007 from a year earlier due to higher duties in
the companys U.K. downstream operations. 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 companys European downstream operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2007 |
|
|
|
2006 |
|
|
2005 |
|
|
|
|
|
|
Interest and debt expense |
|
$ |
166 |
|
|
|
$ |
451 |
|
|
$ |
482 |
|
|
|
|
|
|
Interest and debt expense in 2007 decreased from 2006 primarily due to lower average debt
balances and higher amounts of interest capitalized. The decrease in 2006 vs. 2005 was mainly 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.
FS-9
|
Managements
Discussion and Analysis of
Financial Condition and Results of Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2007 |
|
|
|
2006 |
|
|
2005 |
|
|
|
|
|
|
Income tax expense |
|
$ |
13,479 |
|
|
|
$ |
14,838 |
|
|
$ |
11,098 |
|
|
|
|
|
|
Effective income tax rates were 42 percent in 2007, 46 percent in 2006 and 44 percent in
2005. Rates were lower in 2007 compared with the prior year due mainly to the impact of
nonrecurring items, including asset sales in 2007 and the absence of 2006 charges related to a
tax-law change that increased tax rates on upstream operations in the U.K. North Sea and the
settlement of a tax claim in Venezuela. The higher tax rate in 2006 compared with 2005 also
reflected these nonrecurring charges in 2006. Refer also to the discussion of income taxes in Note
15 beginning on page FS-43.
Selected Operating Data1,2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
|
2006 |
|
|
2005 |
|
|
|
|
|
|
U.S. Upstream3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Crude Oil and Natural Gas Liquids Production (MBPD) |
|
|
460 |
|
|
|
|
462 |
|
|
|
455 |
|
Net Natural Gas Production (MMCFPD)4 |
|
|
1,699 |
|
|
|
|
1,810 |
|
|
|
1,634 |
|
Net Oil-Equivalent Production (MBOEPD) |
|
|
743 |
|
|
|
|
763 |
|
|
|
727 |
|
Sales of Natural Gas (MMCFPD) |
|
|
7,624 |
|
|
|
|
7,051 |
|
|
|
5,449 |
|
Sales of Natural Gas Liquids (MBPD) |
|
|
160 |
|
|
|
|
124 |
|
|
|
151 |
|
Revenues From Net Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
Liquids ($/Bbl) |
|
$ |
63.16 |
|
|
|
$ |
56.66 |
|
|
$ |
46.97 |
|
Natural Gas ($/MCF) |
|
$ |
6.12 |
|
|
|
$ |
6.29 |
|
|
$ |
7.43 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International Upstream3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Crude Oil and Natural Gas
Liquids Production (MBPD) |
|
|
1,296 |
|
|
|
|
1,270 |
|
|
|
1,214 |
|
Net Natural Gas Production (MMCFPD)4 |
|
|
3,320 |
|
|
|
|
3,146 |
|
|
|
2,599 |
|
Net Oil-Equivalent Production (MBOEPD)5 |
|
|
1,876 |
|
|
|
|
1,904 |
|
|
|
1,790 |
|
Sales Natural Gas (MMCFPD) |
|
|
3,792 |
|
|
|
|
3,478 |
|
|
|
2,450 |
|
Sales Natural Gas Liquids (MBPD) |
|
|
118 |
|
|
|
|
102 |
|
|
|
120 |
|
Revenues From Liftings |
|
|
|
|
|
|
|
|
|
|
|
|
|
Liquids ($/Bbl) |
|
$ |
65.01 |
|
|
|
$ |
57.65 |
|
|
$ |
47.59 |
|
Natural Gas ($/MCF) |
|
$ |
3.90 |
|
|
|
$ |
3.73 |
|
|
$ |
3.19 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. and International Upstream3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Oil-Equivalent Production Including
Other Produced Volumes (MBOEPD)4,5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
743 |
|
|
|
|
763 |
|
|
|
727 |
|
International |
|
|
1,876 |
|
|
|
|
1,904 |
|
|
|
1,790 |
|
|
|
|
|
|
|
|
Total |
|
|
2,619 |
|
|
|
|
2,667 |
|
|
|
2,517 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Downstream
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline Sales (MBPD)6 |
|
|
728 |
|
|
|
|
712 |
|
|
|
709 |
|
Other Refined Product Sales (MBPD) |
|
|
729 |
|
|
|
|
782 |
|
|
|
764 |
|
|
|
|
|
|
|
|
Total (MBPD)7 |
|
|
1,457 |
|
|
|
|
1,494 |
|
|
|
1,473 |
|
Refinery Input (MBPD) |
|
|
812 |
|
|
|
|
939 |
|
|
|
845 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International Downstream |
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline Sales (MBPD)6 |
|
|
581 |
|
|
|
|
595 |
|
|
|
662 |
|
Other Refined Product Sales (MBPD) |
|
|
1,446 |
|
|
|
|
1,532 |
|
|
|
1,590 |
|
|
|
|
|
|
|
|
Total (MBPD)7,8 |
|
|
2,027 |
|
|
|
|
2,127 |
|
|
|
2,252 |
|
Refinery Input (MBPD) |
|
|
1,021 |
|
|
|
|
1,050 |
|
|
|
1,038 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 Includes equity in affiliates. |
2 MBPD = Thousands of barrels per day; MMCFPD = Millions of cubic feet per day; |
MBOEPD = Thousands of barrels of oil equivalents per day; Bbl = Barrel; |
MCF = Thousands of cubic feet. Oil-equivalent gas (OEG) conversion ratio is 6,000 cubic feet |
of gas = 1 barrel of oil. |
3 Includes net production beginning August 2005, for properties associated with acquisition |
of Unocal. |
4 Includes natural gas consumed in operations (MMCFPD): |
United States |
|
|
65 |
|
|
|
56 |
|
|
|
48 |
|
International |
|
|
433 |
|
|
|
419 |
|
|
|
356 |
|
5 Includes other produced volumes (MBPD): |
Athabasca Oil Sands Net |
|
|
27 |
|
|
|
27 |
|
|
|
32 |
|
Boscan Operating Service Agreement |
|
|
|
|
|
|
82 |
|
|
|
111 |
|
|
|
|
|
|
|
|
27 |
|
|
|
109 |
|
|
|
143 |
|
6 Includes branded and unbranded gasoline. |
7 Includes volumes for buy/sell contracts (MBPD): |
United States |
|
|
|
|
|
|
26 |
|
|
|
88 |
|
International |
|
|
|
|
|
|
24 |
|
|
|
129 |
|
|
8 Includes sales of affiliates (MBPD): |
|
|
492 |
|
|
|
492 |
|
|
|
498 |
|
FS-10
Liquidity and Capital Resources
Cash, cash equivalents and marketable securities Total balances were $8.1 billion
and $11.4 billion at December 31, 2007 and 2006, respectively. Cash provided by operating
activities in 2007 was $25.0 billion, compared with $24.3 billion in 2006 and $20.1 billion in
2005.
Cash provided by operating activities was net of contributions to employee pension plans of
$300 million, $400 million and $1.0 billion in 2007, 2006 and 2005, respectively. Cash provided by
investing activities included proceeds from asset sales of $3.3 billion in 2007, $1.0 billion in
2006 and $2.7 billion in 2005.
Cash provided by operating activities and asset sales during 2007 was sufficient to fund the
companys $17.7 billion capital and exploratory program, pay $4.8 billion of dividends to
stockholders and repay approximately $3.7 billion of debt.
Restricted cash of $799 million associated with capital-investment projects at the companys
Pascagoula, Mississippi, refinery and Angola liquefied natural gas project was invested in
short-term marketable securities and reclassified from cash equivalents to a long-term asset on the
Consolidated Balance Sheet.
Dividends The company paid dividends of approximately $4.8 billion in 2007, $4.4
billion in 2006 and $3.8 billion in 2005. In April 2007, the company increased its quarterly common
stock dividend by 11.5 percent to 58 cents per share.
Debt,
capital lease and minority interest obligations Total debt and capital lease
balances were $7.2 billion at December 31, 2007, down from $9.8 billion at year-end 2006. The
company also had minority interest obligations of $204 million, down from $209 million at December
31, 2006.
The $2.6 billion reduction in total debt and capital lease obligations during 2007 included
the early redemption and maturity of individual debt issues. In February, $144 million of Texaco
Capital Inc. bonds matured. In the second and fourth quarters, the company redeemed approximately
$809 million and $65 million, respectively of Texaco Capital Inc.
debt and recognized an after-tax
loss of approximately $175 million. In August, $2 billion of Chevron Canada Funding Company bonds
matured. In December, the company issued a $650 million tax exempt Mississippi Gulf Opportunity
Zone bond to fund an upgrade project at the companys refinery in Pascagoula, Mississippi.
Commercial paper balances at the end of 2007 declined approximately
$450 million from $3.5 billion
at year-end 2006. In February 2008, $750 million of Chevron Canada Funding Company bonds matured.
The companys debt and capital lease obligations due within one year, consisting primarily of
commercial paper and the current portion of long-term debt, totaled $5.5 billion at December 31,
2007, down from $6.6 billion at year-end 2006. Of these amounts, $4.4 billion and $4.5 billion were
reclassified to long-term at the end of each period, respectively. At year-end 2007, settlement of
these obligations was not expected to require the use of working capital within one year, as the
company had the intent and the ability, as evidenced by committed credit facilities, to refinance
them on a long-term basis.
At year-end 2007, the company had $5 billion in committed credit facilities with various major
banks, which permit the refinancing of short-term obligations on a long-term basis. These
facilities support commercial paper borrowing and also can be used for general corporate purposes.
The companys practice has been to continually replace expiring commitments with new commitments on
substantially the same terms, maintaining levels management believes appropriate. Any borrowings
under the facilities would be unsecured indebtedness at interest rates based on London Interbank
Offered Rate or an average of base lending rates published by specified banks and on terms
reflecting the companys strong credit rating. No borrowings were outstanding under these
facilities at December 31, 2007.
In March 2007, the company filed with the Securities and Exchange Commission (SEC) an
automatic registration statement that expires in March 2010. This registration statement is for an
unspecified amount of non-convertible debt securities issued or guaranteed by the company. At the
same time, the company withdrew three shelf registration statements on file with the SEC that
permitted the issuance of up to $3.8 billion of debt securities.
At December 31, 2007, the company had outstanding public bonds issued by Chevron Corporation
Profit Sharing/Savings Plan Trust Fund, Chevron Canada Funding Company (formerly ChevronTexaco
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 Poors Corporation and Aal
by Moodys Investors Service. The rating by Moodys reflects an upgrade in December from Aa2. The
companys U.S. commercial paper is rated A-l+ by Standard and Poors and P-1 by Moodys. All of
these ratings denote high-quality, investment-grade securities.
The companys future debt level is dependent primarily on results of operations, the
capital-spending program and cash that may be generated from asset dispositions. The company
believes that it has substantial borrowing capacity to meet unanticipated cash
FS-11
|
Managements
Discussion and Analysis of
Financial Condition and Results of Operations |
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 companys high-quality debt ratings.
Common stock repurchase program A $5 billion stock repurchase program initiated in
December 2006 was completed in September 2007. During 2007, about 61.5 million common shares were
acquired under this program at a total cost of $4.9 billion. Upon completion of this program, the
company authorized the acquisition of up to $15 billion of additional common shares from time to
time at prevailing prices, as permitted by securities laws and other legal requirements and subject
to market conditions and other factors. The program is for a period of up to three years and may be
discontinued at any time. As of December 31, 2007, 23.5 million shares had been acquired under the new
program for $2.1 billion. Purchases through mid-February 2008 increased the total shares acquired
to 34.2 million at a cost of approximately $3.0 billion.
Capital and exploratory expenditures Total reported expenditures for 2007 were $20 billion,
including $2.3 billion for the companys share of affiliates expenditures, which did not require
cash outlays by the company. In 2006 and 2005, expenditures were $16.6 billion and $11.1 billion,
respectively, including the companys share of affiliates expenditures of $1.9 billion and $1.7
billion in the corresponding periods. The 2005 amount excludes $17.3 billion for the acquisition of
Unocal Corporation.
Of the $20 billion in expenditures for 2007, about three-fourths, or $15.5 billion, related to
upstream activities. Approximately the same percentage was also expended for upstream operations in
2006 and 2005. International upstream accounted for about 70 percent of the worldwide upstream
investment in each of the three years, reflecting the companys continuing focus on opportunities
that are available outside the United States.
In 2008, the company estimates capital and exploratory expenditures will be 15 percent higher
at $22.9 billion, including $2.6 billion of spending by affiliates. About three-fourths of the
total, or $17.5 billion, is budgeted for exploration and production activities, with $12.7 billion
of this amount outside the United States. Spending in 2008 is primarily targeted for exploratory
prospects in the deepwater Gulf of Mexico and western Africa and major development projects in
Angola, Australia, Brazil, Indonesia, Kazakhstan, Nigeria, Thailand, the deepwater Gulf of Mexico,
the Piceance Basin in Colorado and an oil sands project in Canada.
Worldwide downstream spending in 2008 is estimated at $4.1 billion, with about $2.3 billion
for projects in the United States. Capital projects include upgrades to refineries in the United
States and South Korea and construction of gas-to-liquids facilities in support of associated
upstream projects.
Investments in chemicals, technology and other corporate businesses in 2008 are budgeted at
$1.3 billion. Technology investments include projects related to unconventional hydrocarbons
technologies, oil and gas reservoir management and gas-fired and renewable power generation.
Capital and Exploratory Expenditures
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
|
2006 |
|
|
|
2005 |
|
Millions of dollars |
|
U.S. |
|
|
Int'l. |
|
|
Total |
|
|
|
U.S. |
|
|
Int'l. |
|
|
Total |
|
|
|
U.S. |
|
|
Int'l. |
|
|
Total |
|
|
|
|
|
|
|
|
|
Upstream Exploration and Production |
|
$ |
4,558 |
|
|
$ |
10,980 |
|
|
$ |
15,538 |
|
|
|
$ |
4,123 |
|
|
$ |
8,696 |
|
|
$ |
12,819 |
|
|
|
$ |
2,450 |
|
|
$ |
5,939 |
|
|
$ |
8,389 |
|
Downstream Refining, Marketing and
Transportation |
|
|
1,576 |
|
|
|
1,867 |
|
|
|
3,443 |
|
|
|
|
1,176 |
|
|
|
1,999 |
|
|
|
3,175 |
|
|
|
|
818 |
|
|
|
1,332 |
|
|
|
2,150 |
|
Chemicals |
|
|
218 |
|
|
|
53 |
|
|
|
271 |
|
|
|
|
146 |
|
|
|
54 |
|
|
|
200 |
|
|
|
|
108 |
|
|
|
43 |
|
|
|
151 |
|
All Other |
|
|
768 |
|
|
|
6 |
|
|
|
774 |
|
|
|
|
403 |
|
|
|
14 |
|
|
|
417 |
|
|
|
|
329 |
|
|
|
44 |
|
|
|
373 |
|
|
|
|
|
|
|
|
|
Total |
|
$ |
7,120 |
|
|
$ |
12,906 |
|
|
$ |
20,026 |
|
|
|
$ |
5,848 |
|
|
$ |
10,763 |
|
|
$ |
16,611 |
|
|
|
$ |
3,705 |
|
|
$ |
7,358 |
|
|
$ |
11,063 |
|
|
|
|
|
|
|
|
|
Total, Excluding Equity in Affiliates |
|
$ |
6,900 |
|
|
$ |
10,790 |
|
|
$ |
17,690 |
|
|
|
$ |
5,642 |
|
|
$ |
9,050 |
|
|
$ |
14,692 |
|
|
|
$ |
3,522 |
|
|
$ |
5,860 |
|
|
$ |
9,382 |
|
|
|
|
|
|
|
|
|
FS-12
Pension Obligations In 2007, the companys pension plan contributions were $317 million
(approximately $78 million to the U.S. plans). The company estimates contributions in 2008
will be approximately $500 million. Actual contribution amounts are dependent upon plan-investment
results, changes in pension obligations, regulatory requirements and other economic factors.
Additional funding may be required if investment returns are insufficient to offset increases in
plan obligations. Refer also to the discussion of pension accounting in Critical Accounting
Estimates and Assumptions, beginning on page FS-18.
Financial Ratios
Financial Ratios
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31 |
|
|
|
2007 |
|
|
|
2006 |
|
|
2005 |
|
|
|
|
|
|
Current Ratio |
|
|
1.2 |
|
|
|
|
1.3 |
|
|
|
1.4 |
|
Interest Coverage Ratio |
|
|
69.2 |
|
|
|
|
53.5 |
|
|
|
47.5 |
|
Total Debt/Total Debt-Plus-Equity |
|
|
8.6 |
% |
|
|
|
12.5 |
% |
|
|
17.0 |
% |
|
|
|
|
|
Current Ratio current assets divided by current liabilities. The current ratio in all
periods was adversely affected by the fact that Chevrons inventories are valued on a
Last-In-First-Out basis. At year-end 2007, the book value of inventory was lower than replacement
costs, based on average acquisition costs during the year, by approximately $7 billion.
Interest Coverage Ratio income before income tax expense, plus interest and debt expense and
amortization of capitalized interest, divided by before-tax interest costs. The companys
interest coverage ratio was higher between 2007 and 2006 and between 2006 and 2005, primarily
due to higher before-tax income and lower average debt balances in each of the subsequent years.
Debt Ratio total debt as a percentage of total debt plus equity. The progressive decrease
between 2005 and 2007, was due to lower average debt levels and higher stockholders equity
balances.
Guarantees, Off-Balance-Sheet Arrangements and Contractual Obligations, and Other Contingencies
Direct Guarantee
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
Commitment Expiration by Period |
|
|
|
Total |
|
|
2008 |
|
|
2009- 2011 |
|
|
2012 |
|
|
After 2012 |
|
|
|
Guarantee of non-consolidated affiliate or
joint-venture obligation |
|
$ |
613 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
38 |
|
|
$ |
575 |
|
|
|
The companys guarantee of approximately $600 million is associated with certain payments
under a terminal use agreement entered into by a company affiliate. The terminal is expected to be
operational by 2012. Over the approximate 16-year term of the guarantee, the maximum guarantee
amount will reduce over time as certain fees are paid by the affiliate. There are numerous
cross-indemnity agreements with the affiliate and the other partners to permit recovery of any
amounts paid under the guarantee. Chevron carries no liability for its obligation under this
guarantee.
Indemnifications The company provided certain indemnities of contingent liabilities of Equilon
and Motiva to Shell and Saudi Refining, Inc., in connection with the February 2002 sale of the
companys interests in those investments. The company would be required to perform if the
indemnified liabilities become actual losses. Were that to occur, the company could be required to
make future payments up to $300 million. Through the end of 2007, the company had paid $48 million
under these indemnities and continues to be obligated for possible additional indemnification
payments in the future.
The company has also provided indemnities relating to contingent environmental liabilities
related to assets originally contributed by Texaco to the Equilon and Motiva joint ventures and
environmental conditions that existed prior to the formation of Equilon and Motiva or that occurred
during the period of Texacos ownership interest in the joint ventures. In general, the
environmental conditions or events that are subject to these indemnities must have arisen prior to
December 2001. Claims must be asserted no later than February 2009 for Equilon indemnities and no
later than February 2012 for Motiva indemnities. Under the terms of these indemnities, there is no
maximum limit on the amount of potential future payments. 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 companys liability is unlimited until April 2022, when the indemnification expires.
The acquirer shares in certain environmental remediation costs up to a maximum
FS-13
|
Managements
Discussion and Analysis of
Financial Condition and Results of Operations |
obligation of $200 million, which had not been reached
as of December 31, 2007.
Securitization During 2007, the company completed the sale of its U.S. proprietary consumer
credit card business and related receivables. This transaction included terminating the qualifying
Special Purpose Entity (SPE) that was used to securitize associated retail accounts receivable.
Through the use of another qualifying SPE, the company had $675 million of securitized trade
accounts receivable related to its downstream business as of
December 31, 2007. This arrangement has
the effect of accelerating Chevrons collection of the securitized amounts. Chevrons total
estimated financial exposure under this securitization at
December 31, 2007, was $65 million. In the
event that the SPE experiences major defaults in the collection of receivables, Chevron believes
that it would have no additional loss exposure connected with third-party investments in this
securitization.
Minority Interests The company has commitments of $204 million related to minority interests
in subsidiary companies.
Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and
Take-or-Pay Agreements The company and its subsidiaries have certain other contingent liabilities
relating to long-term unconditional purchase obligations and commitments, including throughput and
take-or-pay agreements, some of which relate to suppliers financing arrangements. The agreements
typically provide goods and services, such as pipeline and storage capacity, drilling rigs,
utilities, and petroleum products, to be used or sold in the ordinary course of the companys
business. The aggregate approximate amounts of required payments under these various commitments
are: 2008 $4.7 billion; 2009 $3.3 billion; 2010 $3.3 billion; 2011 $1.9 billion; 2012
$1.3 billion; 2013 and after $4.9 billion. A portion of these commitments may ultimately be
shared with project partners. Total payments under the agreements were approximately $3.7 billion
in 2007, $3.0 billion in 2006 and $2.1 billion in 2005.
The following table summarizes the companys significant contractual obligations:
Contractual Obligations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
Payments Due by Period |
|
|
|
|
|
|
|
|
|
|
|
2009- |
|
|
|
|
|
|
After |
|
|
|
Total |
|
|
2008 |
|
|
2011 |
|
|
2012 |
|
|
2012 |
|
|
|
On Balance Sheet:1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-Term Debt2 |
|
$ |
1,162 |
|
|
$ |
1,162 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Long-Term Debt2 |
|
|
5,664 |
|
|
|
|
|
|
|
4,926 |
|
|
|
33 |
|
|
|
705 |
|
Noncancelable Capital
Lease Obligations |
|
|
406 |
|
|
|
|
|
|
|
193 |
|
|
|
61 |
|
|
|
152 |
|
Interest |
|
|
3,950 |
|
|
|
360 |
|
|
|
899 |
|
|
|
292 |
|
|
|
2,399 |
|
Off-Balance-Sheet: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncancelable Operating
Lease Obligations |
|
|
3,167 |
|
|
|
513 |
|
|
|
1,255 |
|
|
|
293 |
|
|
|
1,106 |
|
Throughput and
Take-or-Pay Agreements |
|
|
13,118 |
|
|
|
3,699 |
|
|
|
4,783 |
|
|
|
618 |
|
|
|
4,018 |
|
Other Unconditional
Purchase Obligations3 |
|
|
6,300 |
|
|
|
988 |
|
|
|
3,779 |
|
|
|
653 |
|
|
|
880 |
|
|
|
1 |
|
Does not include amounts related to the companys income tax liabilities associated with
uncertain tax positions. The company is unable to make reasonable estimates for the periods in
which these liabilities may become due. The company does not expect settlement of such
liabilities will have a material effect on its results of operations, consolidated financial
position or liquidity in any single period. |
|
2 |
|
$4.4. billion of short-term debt that the company expects to refinance is included in long-term
debt. The repayment schedule above reflects the projected repayment of the entire amounts in the
2009-2011 period. |
|
3 |
|
Does not include obligations to purchase the companys share of natural gas liquids and
regasified natural gas associated with operations of the 36.4 percent-owned Angola LNG
affiliate. The LNG plant is expected to commence operations in 2012 and is designed to produce
5.2 million metric tons of liquefied natural gas and related natural gas liquids per year.
Volumes and prices associated with these purchase obligations are neither fixed nor
determinable. |
Financial and Derivative Instruments
No material change in market risk occurred between 2006 and 2007 for the financial and
derivative instruments discussed below. The hypothetical variances used in this section were
selected for illustrative purposes only and do not represent the companys estimation of market
changes. The actual impact of future market changes could differ materially due to factors
discussed elsewhere in this report, including those set forth under the heading Risk Factors in
Part 1, Item 1A, of the companys 2007 Annual Report
on Form 10-K.
Commodity Derivative Instruments Chevron is exposed to market risks related to the price
volatility of crude oil, refined products, natural gas, natural gas liquids, liquefied natural gas
and refinery feedstocks.
The company uses derivative commodity instruments to manage these exposures on a portion of
its activity, including firm commitments and anticipated transactions for the purchase, sale and
storage of crude oil, refined products, natural gas, natural gas liquids and feedstock for company
refineries. The company also uses derivative commodity instruments for limited trading purposes.
The results of this activity were not material to the companys financial position, net income or
cash flows in 2007.
FS-14
The companys market exposure positions are monitored and managed on a daily basis by an
internal Risk Control group to ensure compliance with the companys risk management policies that
have been approved by the Audit Committee of the companys Board of Directors.
The derivative instruments used in the companys risk management and trading activities
consist mainly of futures, options, and swap contracts traded on the NYMEX (New York Mercantile
Exchange) and on electronic platforms of ICE (Inter-Continental Exchange) and GLOBEX (Chicago
Mercantile Exchange). In addition, crude oil, natural gas and refined product swap contracts and
option contracts are entered into principally with major financial institutions and other oil and
gas companies in the over-the-counter markets.
Virtually all derivatives beyond those designated as normal purchase and normal sale contracts
are recorded at fair value on the Consolidated Balance Sheet with resulting gains and losses
reflected in income. Fair values are derived principally from published market quotes and other
independent third-party quotes.
Effective with 2007 year-end reporting, the company changed the model used to quantify
information about market risk for its commodity derivatives from a sensitivity analysis approach
to Value-at-Risk (VaR). The major reason for the change is that VaR allows estimation of a
portfolios aggregate market risk exposure and takes into account correlations between trading
assets. Therefore, it reflects risk reduction due to diversification or hedging activities. Most of
the companys market positions are time and commodity spreads, and the company believes that VaR is
a more accurate tool to measure this type of exposure than the sensitivity analysis model. The
company fully developed and tested its VaR model during 2007.
VaR is the maximum loss not to be exceeded within a given probability or confidence level over
a given period of time. The companys VaR model uses the Monte Carlo simulation method that
involves generating hypothetical scenarios from the specified probability distribution and
constructing a full distribution of a potential portfolios values.
The VaR model utilizes an exponentially-weighted moving average for computing historical
volatilities and correlations, a 95 percent confidence level, and one-day holding period. That is,
the companys 95 percent, one-day VaR corresponds to the unrealized loss in portfolio value that
would not be exceeded on average more than one in every 20 trading days, if the portfolio were held
constant for one day.
The one-day holding period is based on the assumption that market-risk positions can be
liquidated or hedged within one day. For hedging and risk management, the company uses conventional
exchange-traded instruments such as futures and options, as well as non-exchange-traded swaps, most
of which can be liquidated or hedged effectively within one day. The table below presents 95
percent/one-day VaR for each of the companys primary risk exposures in the area of commodity
derivative instruments at December 31, 2007:
|
|
|
|
|
Millions of dollars |
|
2007 |
|
|
Crude Oil |
|
$ |
29 |
|
Natural Gas |
|
|
3 |
|
Refined Products |
|
|
23 |
|
|
Sensitivity analysis for the companys open commodity derivative instruments at December
31, 2007, and December 31, 2006, based on a hypothetical 10 percent increase in commodity prices, is
provided in the following table:
Incremental Increase (Decrease) in Fair Value of Open Commodity
Derivative Contracts Assuming a Hypothetical Increase in
Year-End Commodity Prices of 10 Percent
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2007 |
|
|
|
2006 |
|
|
|
|
|
Crude Oil |
|
$ |
(113 |
) |
|
|
$ |
4 |
|
Natural Gas |
|
|
14 |
|
|
|
|
10 |
|
Refined Products |
|
|
(96 |
) |
|
|
|
(30 |
) |
|
|
|
|
The same hypothetical decrease in prices of these commodities would result in
approximately the same opposite effects on the fair values of the contracts. The hypothetical
effect on these contracts was estimated by calculating the fair value of the contracts as the
difference between the hypothetical and current market prices multiplied by the contract amounts.
The change in the amounts between years in the table above for crude oil and refined products
is associated with an increase in commodity prices, volumes hedged and the use of longer-term
contracts.
Foreign Currency The company enters into forward exchange contracts, generally with terms of
180 days or less, to manage some of its foreign currency exposures. These exposures include revenue
and anticipated purchase transactions, including foreign currency capital expenditures and lease
commitments, forecasted to occur within 180 days. The forward exchange contracts are recorded at
fair value on the balance sheet with resulting gains and losses reflected in income.
The aggregate effect of a hypothetical 10 percent increase in the value of the U.S. dollar at
year-end 2007 would be a reduction in the fair value of the foreign exchange contracts of
approximately $75 million. The effect would be the opposite for a hypothetical 10 percent decrease
in the value of the U.S. dollar at year-end 2007.
Interest Rates The company enters into interest rate swaps as part of its overall strategy to
manage the interest rate risk on its debt. Under the terms of the swaps, net cash settlements are
based on the difference between fixed-rate and floating-rate interest amounts calculated by
reference to agreed notional principal amounts. Interest rate swaps related to a portion of the
companys fixed-rate debt are accounted for as fair value hedges. Interest rate swaps related to
floating-rate debt are recorded at fair value on the balance sheet with resulting gains and losses
reflected in income. At year-end 2007, the company had no interest-rate swaps on floating-rate
debt. At year-end 2007, the weighted average maturity of receive fixed interest rate swaps was
less than one year. A hypothetical increase or decrease of 10 basis points in fixed interest rates
would have a de minimis impact on the fair value of the receive fixed swaps.
Transactions With Related Parties
Chevron enters into a number of business arrangements with related parties, principally
its equity affiliates. These arrangements include long-term supply or offtake agreements. Long-term
purchase agreements are in place with the companys refining affiliate
FS-15
|
Managements Discussion and Analysis of
Financial Condition and Results of Operations |
in Thailand. Refer to page FS-5 for further discussion. Management
believes the foregoing agreements and others have been negotiated on terms consistent with those
that would have been negotiated with an unrelated party.
Litigation and Other Contingencies
MTBE Chevron and many other companies in the petroleum industry have used methyl tertiary
butyl ether (MTBE) as a gasoline additive. The company is a party to 88 lawsuits and claims, the
majority of which involve numerous other petroleum marketers and refiners, related to the use of
MTBE in certain oxygenated gasolines and the alleged seepages of MTBE into groundwater. Chevron has
agreed in principle to a tentative settlement of 60 pending lawsuits and claims. The terms of this
agreement, which must be approved by a number of parties, including the court, are confidential and
not material to the companys results of operations, liquidity or financial position.
Resolution of remaining lawsuits and claims may ultimately require the company to correct or
ameliorate the alleged effects on the environment of prior release of MTBE by the company or other
parties. Additional lawsuits and claims related to the use of MTBE, including personal-injury
claims, may be filed in the future. The tentative settlement of the referenced 60 lawsuits did not
set any precedents related to standards of liability to be used to judge the merits of the claims,
corrective measures required or monetary damages to be assessed for the remaining lawsuits and
claims or future lawsuits and claims. As a result, the companys ultimate exposure related to
pending lawsuits and claims is not currently determinable, but could be material to net income in
any one period. The company no longer uses MTBE in the manufacture of gasoline in the United States.
RFG Patent Fourteen purported class actions were brought by consumers of reformulated gasoline
(RFG) alleging that Unocal misled the California Air Resources Board into adopting standards for
composition of RFG that overlapped with Unocals undisclosed and pending patents. Eleven lawsuits
were consolidated in U.S. District Court for the Central District of California, where a class
action has been certified, and three were consolidated in a state court action. Unocal is alleged
to have monopolized, conspired and engaged in unfair methods of competition, resulting in injury to
consumers of RFG. Plaintiffs in both consolidated actions seek unspecified actual and punitive
damages, attorneys fees, and interest on behalf of an alleged class of consumers who
purchased
summertime RFG in California from January 1995 through August 2005. The parties have reached a
tentative agreement to resolve all of the above matters in an amount that is not material to the
companys results of operations, liquidity or financial position. The terms of this agreement are
confidential, and subject to further negotiation and approval, including by the courts.
Environmental The company is subject to loss contingencies pursuant to environmental laws and
regulations that in the future may require the company to take action to correct or ameliorate the
effects on the environment of prior release of chemicals or petroleum substances, including MTBE,
by the company or other parties. Such contingencies may exist for various sites, including, but not
limited to, federal Superfund sites and analogous sites under state laws, refineries, crude oil
fields,
service stations, terminals, land development areas, and mining operations, whether
operating, closed or divested. These future costs are not fully determinable due to such factors as
the unknown magnitude of possible contamination, the unknown timing and extent of the corrective
actions that may be required, the determination of the companys liability in proportion to other
responsible parties, and the extent to which such costs are recoverable from third parties.
Although the company has provided for known environmental obligations that are probable and
reasonably estimable, the amount of additional future costs may
be material to results of
operations in the period in which they are recognized.
The company does not expect these costs will
have a material effect on its consolidated financial position or liquidity. Also, the company does
not believe its obligations to make such expenditures have had, or will have, any significant
impact on the companys competitive position relative to other U.S. or international petroleum or
chemical companies.
FS-16
The following table displays the annual changes to the companys before-tax environmental
remediation reserves, including those for federal Superfund sites and analogous sites under state
laws.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of dollars |
|
2007 |
|
|
|
2006 |
|
|
2005 |
|
|
|
|
|
Balance at January 1 |
|
$ |
1,441 |
|
|
|
$ |
1,469 |
|
|
$ |
1,047 |
|
Net Additions |
|
|
562 |
|
|
|
|
366 |
|
|
|
731 |
|
Expenditures |
|
|
(464 |
) |
|
|
|
(394 |
) |
|
|
(309 |
) |
|
|
|
|
Balance
at December 31 |
|
$ |
1,539 |
|
|
|
$ |
1,441 |
|
|
$ |
1,469 |
|
|
|
|
|
Included in the $1,539 million year-end 2007 reserve balance were remediation activities
of 240 sites for which the company had been identified as a potentially responsible party or
otherwise involved in the remediation by the U.S. Environmental Protection Agency (EPA) or other
regulatory agencies under the provisions of the federal Superfund law or analogous state laws. The
companys remediation reserve for these sites at year-end 2007 was $123 million. The federal
Superfund law and analogous state laws provide for joint and several liability for all responsible
parties. Any future actions by the EPA or other regulatory agencies to require Chevron to assume
other potentially responsible parties costs at designated hazardous waste sites are not expected
to have a material effect on the companys consolidated financial position or liquidity.
Of
the remaining year-end 2007 environmental reserves balance of $1,416 million, $864 million
related to approximately 2,000 sites for the companys U.S. downstream operations, including
refineries and other plants, marketing locations (i.e., service stations and terminals) and
pipelines. The remaining $552 million was associated with various sites in international
downstream ($146 million), upstream ($267 million), chemicals ($105 million) and other ($34
million). Liabilities at all sites, whether operating, closed or divested, were primarily
associated with the companys plans and activities to remediate soil or groundwater contamination
or both. These and other activities include one or more of the following: site assessment; soil
excavation; offsite disposal of contaminants; onsite containment, remediation and/or extraction of
petroleum hydrocarbon liquid and vapor from soil; groundwater extraction and treatment; and
monitoring of the natural attenuation of the contaminants.
The company manages environmental liabilities under specific sets of regulatory requirements,
which in the United States include the Resource Conservation and Recovery Act and various state or
local regulations. No single remediation site at year-end 2007 had a recorded liability that was
material to the companys financial position, results of operations or liquidity.
It is likely that the company will continue to incur additional liabilities, beyond those
recorded, for environmental remediation relating to past operations. These future costs are not
fully determinable due to such factors as the unknown magnitude of possible contamination, the
unknown timing and extent of the corrective actions that may be required, the determination of the
companys liability in proportion to other responsible parties, and the extent to which such costs
are recoverable from third parties.
The company accounts for asset retirement obligations in accordance with Financial Accounting
Standards Board Statement (FASB) No. 143, Accounting for Asset Retirement Obligations (FAS 143).
Under FAS 143, the fair value of a liability for an asset retirement obligation is recorded when
there is a legal obligation associated with the retirement of long-lived assets and the liability
can be reasonably estimated. The liability balance of approximately $8.3 billion for asset
retirement obligations at year-end 2007 related primarily to upstream and mining properties.
For the companys other ongoing operating assets, such as refineries and chemicals facilities,
no provisions are made for exit or cleanup costs that may be required when such assets reach the
end of their useful lives unless a decision to sell or otherwise abandon the facility has been
made, as the indeterminate settlement dates for the asset retirements prevent estimation of the
fair value of the asset retirement obligation.
Refer
also to Note 23, beginning on page FS-57, related to FAS 143 and the companys adoption in 2005 of
FASB Interpretation No. (FIN) 47, Accounting for Conditional Asset Retirement Obligations An
Interpretation of FASB Statement No. 143
(FIN 47), and the discussion of Environmental Matters on page FS-18.
Income Taxes The company calculates its income tax expense and liabilities quarterly. These
liabilities generally are subject to audit and are not finalized with the individual taxing
authorities until several years after the end of the annual period for which income taxes have been
calculated. Refer to Note 15 beginning on page FS-43 for a discussion of the periods for which tax
returns have been audited for the companys major tax jurisdictions and a discussion for all tax
jurisdictions of the differences between the amount of tax benefits recognized in the financial
statements and the amount taken or expected to be taken in a tax return. The company does not
expect settlement of income tax liabilities associated with uncertain tax positions will have a
material effect on its results of operations, consolidated financial position or liquidity.
Suspended Wells The company suspends the costs of exploratory wells pending a final
determination of the commercial potential of the related crude oil and natural gas fields. The
ultimate disposition of these well costs is dependent on the results of future drilling activity or
development decisions or both. At December 31, 2007, the company had approximately $1.7 billion of
suspended exploratory wells included in properties, plant and equipment, an increase of $421
million from 2006 and an increase of $551 million from 2005.
The future trend of the companys exploration expenses can be affected by amounts associated
with well write-offs, including wells that had been previously suspended pending determination as
to whether the well had found reserves that could be classified as proved. The effect on
exploration expenses in future periods of the $1.7 billion of suspended wells at year-end 2007 is
uncertain pending future activities, including normal project evaluation and additional drilling.
Refer to Note 19, beginning on page FS-47, for additional discussion of suspended wells.
FS-17
|
Managements Discussion and Analysis of
Financial Condition and Results of Operations |
Equity Redetermination For oil and gas producing operations, ownership agreements may
provide for periodic reassessments of equity interests in estimated crude oil and natural gas
reserves. These activities, individually or together, may result in gains or losses that could be
material to earnings in any given period. One such equity redetermination process has been under
way since 1996 for Chevrons interests in four producing zones at the Naval Petroleum Reserve at
Elk Hills, California, for the time when the remaining interests in these zones were owned by the
U.S. Department of Energy. A wide range remains for a possible net settlement amount for
the four zones. For this range of settlement, Chevron estimates its maximum possible net before-tax
liability at approximately $200 million, and the possible maximum net amount that could be owed to
Chevron is estimated at about $150 million. The timing of the settlement and the exact amount
within this range of estimates are uncertain.
Other Contingencies Chevron receives claims from and submits claims to customers; trading
partners; U.S. federal, state and local regulatory bodies; governments; contractors;
insurers; and suppliers. The amounts of these claims, individually and in the aggregate, may be
significant and take lengthy periods to resolve.
The company and its affiliates also continue to review and analyze their operations and may
close, abandon, sell, exchange, acquire or restructure assets to achieve operational or strategic
benefits and to improve competitiveness and profitability. These activities, individually or
together, may result in gains or losses in future periods.
Environmental Matters
Virtually all aspects of the businesses in which the company engages are subject to various
federal, state and local environmental, health and safety laws and regulations. These regulatory
requirements continue to increase in both number and complexity over time and govern not only the
manner in which the company conducts its operations, but also the products it sells. Most of the
costs of complying with laws and regulations pertaining to company operations and products are
embedded in the normal costs of doing business.
Accidental leaks and spills requiring cleanup may occur in the ordinary course of business. In
addition to the costs for environmental protection associated with its ongoing operations and
products, the company may incur expenses for corrective actions at various owned and previously
owned facilities and at third-party-owned waste-disposal sites used by the company. An obligation
may arise when operations are closed or sold or at non-Chevron sites where company products have
been handled or disposed of. Most of the expenditures to fulfill these obligations relate to
facilities and sites where past operations followed practices and procedures that were considered
acceptable at the time but now require investigative or remedial work or both to meet current
standards.
Using definitions and guidelines established by the American Petroleum Institute, Chevron
estimated its worldwide environmental spending in 2007 at approximately $2.7 billion for its
consolidated companies. Included in these expenditures were approximately $900 million of
environmental capital expenditures and $1.8 billion of costs associated with the prevention,
control, abatement or elimination of hazardous substances and pollutants from operating, closed or
divested sites and the abandonment and restoration of sites.
For 2008, total worldwide environmental capital expenditures are estimated at $1.9 billion.
These capital costs are in addition to the ongoing costs of complying with environmental
regulations and the costs to remediate previously contaminated sites.
It is not possible to predict with certainty the amount of additional investments in new or
existing facilities or amounts of incremental operating costs to be incurred in the future to:
prevent, control, reduce or eliminate releases of hazardous materials into the environment; comply
with existing and new environmental laws or regulations; or remediate and restore areas damaged by
prior releases of hazardous materials. Although these costs may be significant to the results of
operations in any single period, the company does not expect them to have a material effect on the
companys liquidity or financial position.
Critical Accounting Estimates and Assumptions
Management makes many estimates and assumptions in the application of generally accepted
accounting principles (GAAP) that may have a material impact on the companys consolidated
financial statements and related disclosures and on the comparability of such information over
different reporting periods. All such estimates and assumptions affect reported amounts of assets,
liabilities, revenues and expenses, as well as disclosures of contingent assets and liabilities.
Estimates and assumptions are based on managements experience and other information available
prior to the issuance of the financial statements. Materially different results can occur as
circumstances change and additional information becomes known.
The discussion in this section of critical accounting estimates or assumptions is according
to the disclosure guidelines of the Securities and Exchange Commission (SEC), wherein:
|
1. |
|
the nature of the estimates or assumptions is material due to the levels of subjectivity
and judgment necessary to account for highly uncertain matters or the susceptibility of such
matters to change; and |
|
2. |
|
the impact of the estimates and assumptions on the companys financial condition or
operating performance is material. |
FS-18
Besides those meeting these critical criteria, the company makes many other accounting
estimates and assumptions in preparing its financial statements and related disclosures. Although
not associated with highly uncertain matters, these estimates and assumptions are also subject to
revision as circumstances warrant, and materially different results may sometimes occur.
For example, the recording of deferred tax assets requires an assessment under the accounting
rules that the future realization of the associated tax benefits be more likely than not. Another
example is the estimation of crude oil and natural gas reserves under SEC rules that require ...
geological and engineering data (that) demonstrate with reasonable certainty (reserves) to be
recoverable in future years from known reservoirs under existing economic and operating conditions,
i.e., prices and costs as of the date the estimate is made. Refer to Table V, Reserve Quantity
Information, beginning on page FS-66, for the changes in these estimates for the three years
ending December 31, 2007, and to Table VII, Changes in the Standardized Measure of Discounted
Future Net Cash Flows From Proved Reserves on page FS-74 for estimates of proved-reserve values
for each of the three years ending December 31, 2007, which were based on year-end prices at the
time. Note 1 to the Consolidated Financial Statements, beginning on page FS-32, includes a
description of the successful efforts method of accounting for oil and gas exploration and
production activities. The estimates of crude oil and natural gas reserves are important to the
timing of expense recognition for costs incurred.
The discussion of the critical accounting policy for Impairment of Properties, Plant and
Equipment and Investments in Affiliates, beginning on page FS-20, includes reference to conditions
under which downward revisions of proved-reserve quantities could result in impairments of oil and
gas properties. This commentary should be read in conjunction with disclosures elsewhere in this
discussion and in the Notes to the Consolidated Financial Statements related to estimates,
uncertainties, contingencies and new accounting standards. Significant accounting policies are
discussed in Note 1 to the Consolidated Financial Statements, beginning on page FS-32. The
development and selection of accounting estimates and assumptions, including those deemed
critical, and the associated disclosures in this discussion have been discussed by management
with the Audit Committee of the Board of Directors.
The areas of accounting and the associated critical estimates and assumptions made by the
company are as follows:
Pension and Other Postretirement Benefit Plans The determination of pension plan obligations
and expense is based on a number of actuarial assumptions. Two critical assumptions are the
expected long-term rate of return on plan assets and the discount rate applied to pension plan
obligations. For other postretirement benefit (OPEB) plans, which provide for certain health care
and life insurance benefits for qualifying retired employees and which are not funded, critical
assumptions in determining OPEB obligations and expense are the discount rate and the assumed
health care cost-trend rates.
Note 20, beginning on page FS-48, includes information on the funded status of the companys
pension and OPEB
plans at the end of 2007 and 2006, the components of pension and OPEB expense for
the three years ending December 31, 2007, and the underlying assumptions for those periods.
Pension and OPEB expense is recorded on the Consolidated Statement of Income in Operating
expenses or Selling, general and administrative expenses and applies to all business segments.
The year-end 2007 and 2006 funded status, measured as the difference between plan assets and
obligations, of each of the companys pension and OPEB plans is recognized on the Consolidated
Balance Sheet. The funded status of overfunded pension plans is recorded as a long-term asset in
Deferred charges and other assets. The funded status of underfunded or unfunded pension and OPEB
plans is recorded in Accrued liabilities or Reserves for employee benefit plans. Amounts yet to
be recognized as components of pension or OPEB expense are recorded in Accumulated other
comprehensive income.
To estimate the long-term rate of return on pension assets, the company uses
a process that incorporates actual historical asset-class returns and an assessment of expected
future performance and takes into consideration external actuarial advice and asset-class factors.
Asset allocations are periodically updated using pension plan asset/liability studies, and the
determination of the companys estimates of long-term rates of return are consistent with these
studies. The expected long-term rate of return on U.S. pension plan assets, which account for 67
percent of the companys pension plan assets, has remained at 7.8 percent since 2002. For the 10
years ending December 31, 2007, actual asset returns averaged 8.7 percent for this plan.
The year-end market-related value of assets of the major U.S. pension plan used in the
determination of pension expense was based on the market value in the preceding three months, as
opposed to the maximum allowable period of five years under U.S. accounting rules. Management
considers the three-month period long enough to minimize the effects of distortions from day-to-day
market volatility and still be contemporaneous to the end of the year. For other plans, market
value of assets as of the measurement date is used in calculating the pension expense.
The discount rate assumptions used to determine U.S. and international pension and
postretirement benefit plan obligations and expense reflect the prevailing rates available on
high-quality fixed-income debt instruments. At December 31, 2007, the company selected a 6.3
percent discount rate for the major U.S. pension and postretirement plans. This rate was selected
based on a cash flow analysis that matched estimated future benefit payments to the Citigroup
Pension Discount Yield Curve as of year-end 2007. The discount rates at the end of 2006 and 2005
were 5.8 percent and 5.5 percent, respectively.
An increase in the expected long-term return on plan assets or the discount rate would reduce
pension plan expense, and vice versa. Total pension expense for 2007 was $620 million. As an
indication of the sensitivity of pension expense to the long-term rate of return assumption, a 1
percent increase in the expected rate of return on assets of the companys primary U.S. pension
plan would have reduced total pension plan expense for 2007 by approximately $70
FS-19
|
Managements Discussion and Analysis of
Financial Condition and Results of Operations |
million. A 1 percent increase in the discount rate for this same plan, which accounted for
about 60 percent of the companywide pension obligation, would have reduced total pension plan
expense for 2007 by approximately $155 million.
An increase in the discount rate would decrease the pension obligation, thus changing the
funded status of a plan recorded on the Consolidated Balance Sheet. The total pension liability on
the Consolidated Balance Sheet at December 31, 2007, for underfunded plans was approximately $1.7
billion. As an indication of the sensitivity of pension liabilities to the discount rate
assumption, a 0.25 percent increase in the discount rate applied to the companys primary U.S.
pension plan would have reduced the plan obligation by approximately $250 million, which would have
increased the plans over-funded status from approximately $160 million to $410 million. Other
plans would be less underfunded as discount rates increase. The actual rates of return on plan
assets and discount rates may vary significantly from estimates because of unanticipated changes in
the worlds financial markets.
In 2007, the companys pension plan contributions were $317 million (including $78 million to
the U.S. plans). In 2008, the company estimates contributions will be approximately $500 million.
Actual contribution amounts are dependent upon plan-investment results, changes in pension
obligations, regulatory requirements and other economic factors. Additional funding may be required
if investment returns are insufficient to offset increases in plan obligations.
For the companys OPEB plans, expense for 2007 was $233 million and the total liability, which
reflected the underfunded status of the plans at the end of 2007, was $2.9 billion.
As an indication of discount rate sensitivity to the determination of OPEB expense in 2007, a
1 percent increase in the discount rate for the companys primary U.S. OPEB plan, which accounted
for about 75 percent of the companywide OPEB expense, would have decreased OPEB expense by
approximately $20 million. A 0.25 percent increase in the discount rate for the same plan, which
accounted for about 87 percent of the companywide OPEB liabilities, would have decreased total OPEB
liabilities at the end of 2007 by approximately $60 million.
For the main U.S. postretirement medical plan, the annual increase to company contributions is
limited to 4 percent per year. The cap becomes effective in the year of retirement for
pre-Medicare-eligible employees retiring on or after January 1, 2005. The cap was effective as
of January 1, 2005, for pre-Medicare-eligible employees retiring before that date and all
Medicare-eligible retirees. For active employees and retirees under age 65 whose claims experiences
are combined for rating purposes, the assumed health care cost-trend rates start with 8 percent in
2008 and gradually drop to 5 percent for 2014 and beyond. As an indication of the health care
cost-trend rate sensitivity to the determination of
OPEB expense in 2007, a 1 percent increase in
the rates for the main U.S. OPEB plan, which accounted for about 87 percent of the companywide OPEB
liabilities, would have increased OPEB expense $8 million.
Differences between the various assumptions used to determine expense and the funded status of
each plan and actual experience are not included in benefit plan costs in the year the difference
occurs. Instead, the differences are included in actuarial gain/loss and unamortized amounts have
been reflected in Accumulated other comprehensive loss on the Consolidated Balance Sheet. Refer
to Note 20, beginning on page FS-48, for information on the $3.3 billion of before-tax actuarial
losses recorded by the company as of December 31, 2007; a description of the method used to amortize
those costs; and an estimate of the costs to be recognized in expense during 2008.
Impairment
of Properties, Plant and Equipment and Investments in Affiliates The company
assesses its properties, plant and equipment (PP&E) for possible impairment whenever events or
changes in circumstances indicate that the carrying value of the assets may not be recoverable.
Such indicators include changes in the companys business plans, changes in commodity prices and,
for crude oil and natural gas properties, significant downward revisions of estimated
proved-reserve quantities. If the carrying value of an asset exceeds the future undiscounted cash
flows expected from the asset, an impairment charge is recorded for the excess of carrying value of
the asset over its estimated fair value.
Determination as to whether and how much an asset is impaired involves management estimates on
highly uncertain matters such as future commodity prices, the effects of inflation and technology
improvements on operating expenses, production profiles, and the outlook for global or regional
market supply and demand conditions for crude oil, natural gas, commodity chemicals and refined
products. However, the impairment reviews and calculations are based on assumptions that are
consistent with the companys business plans and long-term investment decisions.
No
major individual impairments of PP&E were recorded for the three years ending December 31,
2007. An estimate as to the sensitivity to earnings for these periods if other assumptions had been
used in impairment reviews and impairment calculations is not practicable, given the broad range of
the companys PP&E and the number of assumptions involved in the estimates. That is, favorable
changes to some assumptions might have avoided the need to impair any assets in these periods,
whereas unfavorable changes might have caused an additional unknown number of other assets to
become impaired.
Investments in common stock of affiliates that are accounted for under the equity method, as
well as investments in other securities of these equity investees, are reviewed for impairment when
the
FS-20
fair value of the investment falls below the companys carrying value. When such a decline is
deemed to be other than temporary, an impairment charge is recorded to the income statement for the
difference between the investments carrying value and its estimated fair value at the time. In
making the determination as to whether a decline is other than temporary, the company considers
such factors as the duration and extent of the decline, the investees financial performance, and
the companys ability and intention to retain its investment for a period that will be sufficient
to allow for any anticipated recovery in the investments market value. Differing assumptions could
affect whether an investment is impaired in any period or the amount of the impairment and are not
subject to sensitivity analysis.
From time to time, the company performs impairment reviews and determines that no write-down
in the carrying value of an asset or asset group is required. For example, when significant
downward revisions to crude oil and natural gas reserves are made for any single field or
concession, an impairment review is performed to determine if the carrying value of the asset
remains recoverable. Also, if the expectation of sale of a particular asset or asset group in any
period has been deemed more likely than not, an impairment review is performed, and if the
estimated net proceeds exceed the carrying value of the asset or asset group, no impairment charge
is required. Such calculations are reviewed each period until the asset or asset group is disposed
of. Assets that are not impaired on a held-and-used basis could possibly become impaired if a
decision is made to sell such assets. That is, the assets would be impaired if they are classified
as held-for-sale and the estimated proceeds from the sale, less costs to sell, are less than the
assets associated carrying values.
Business
Combinations Purchase-Price Allocation Accounting for business combinations
requires the allocation of the companys purchase price to the various assets and liabilities of
the acquired business at their respective fair values. The company uses all available information
to make these fair value determinations, and for major acquisitions, may hire an independent
appraisal firm to assist in making fair value estimates. In some instances, assumptions with
respect to the timing and amount of future revenues and expenses associated with an asset might
have to be used in determining its fair value. Actual timing and amount of net cash flows from
revenues and expenses related to that asset over time may differ materially from those initial
estimates, and if the timing is delayed significantly or if the net cash flows decline
significantly, the asset could become impaired.
Goodwill Goodwill resulting from a business combination is not subject to amortization. As
required by FASB Statement No. 142, Goodwill and Other Intangible Assets, the company tests such
goodwill at the reporting unit level for impairment on an annual basis and between annual tests if
an event occurs or circumstances change that would more likely than not reduce the fair value of a
reporting unit below its carrying amount.
Contingent Losses Management also makes judgments and estimates in recording liabilities for
claims, litigation, tax matters and environmental remediation. Actual costs can frequently vary
from estimates for a variety of reasons. For example, the costs
from settlement of claims and
litigation can vary from estimates based on differing interpretations of laws, opinions on
culpability and assessments on the amount of damages. Similarly, liabilities for environmental
remediation are subject to change because of changes in laws, regulations and their interpretation,
the determination of additional information on the extent and nature of site contamination, and
improvements in technology.
Under the accounting rules, a liability is generally recorded for these types of contingencies
if management determines the loss to be both probable and estimable. The company generally records
these losses as Operating expenses or Selling, general and administrative expenses on the
Consolidated Statement of Income. An exception to this handling is for income tax matters, for
which benefits are recognized only if management determines the tax position is more likely than
not (i.e. likelihood greater than 50 percent) to be allowed by the tax jurisdiction. For
additional discussion of income tax uncertainties, refer to Note 15
beginning on page FS-43. Refer
also to the business segment discussions elsewhere in this section for the effect on earnings from
losses associated with certain litigation, and environmental remediation and tax matters for the
three years ended December 31, 2007.
An estimate as to the sensitivity to earnings for these periods if other assumptions had been
used in recording these liabilities is not practicable because of the number of contingencies that
must be assessed, the number of underlying assumptions and the wide range of reasonably possible
outcomes, both in terms of the probability of loss and the estimates of such loss.
New Accounting Standards
FASB Statement No. 157, Fair Value Measurements (FAS 157) In September 2006, the FASB issued FAS 157, which became effective for the company on
January 1, 2008. This standard defines fair value,
establishes a framework for measuring fair value and expands disclosures about fair value
measurements. FAS 157 does not require any new fair value measurements but applies to assets and
liabilities that are required to be recorded at fair value under other accounting standards. The
implementation of FAS 157 did not have a material effect on the companys results of operations or
consolidated financial position.
FASB
Staff Position FAS No. 157-1, Application of FASB Statement No. 157
to FASB Statement No. 13 and Its Related Interpretive Accounting Pronouncements That Address Leasing Transactions (FSP
157-1) In February 2008, the FASB issued FSP 157-1, which became effective for the company on
January 1, 2008. This FSP excludes FASB Statement No. 13, Accounting for Leases, and its related
interpretive accounting pronouncements from the provisions of FAS 157. Implementation of this
standard did not have a material effect on the companys results of operations or consolidated
financial position.
FASB
Staff Position FAS No. 157-2, Effective Date of FASB Statement No. 157 (FSP 157-2) In
February 2008, the FASB issued FSP 157-2, which delays the companys January
1, 2008, effective date of FAS 157 for all nonfinancial assets and nonfinancial
FS-21
|
Managements Discussion and Analysis of
Financial Condition and Results of Operations |
liabilities, except those recognized or disclosed at fair value in the financial
statements on a recurring basis (at least annually), until January 1, 2009. Implementation of this
standard did not have a material effect on the companys results of operations or consolidated
financial position.
FASB Statement No. 159, The Fair Value Option for Financial Assets and Financial
Liabilities Including an amendment of FASB Statement No. 115 (FAS 159) In
February 2007, the FASB issued FAS 159, which became effective for the company on January 1, 2008.
This standard permits companies to choose to measure many financial instruments and certain other
items at fair value and report unrealized gains and losses in earnings. Such accounting is optional
and is generally to be applied instrument by instrument. The implementation of FAS 159 did not have
a material effect on the companys results of operations or consolidated financial position.
FASB Statement No. 141 (revised 2007), Business Combinations (FAS 141-R) In December
2007, the FASB issued FAS 141-R, which will become effective for business combination transactions
having an acquisition date on or after January 1, 2009. This standard requires the acquiring entity
in a business combination to recognize the assets acquired, the liabilities assumed, and any
noncontrolling interest in the acquiree at the acquisition date to be measured at their respective
fair values. The Statement requires acquisition-related costs, as well as restructuring costs the
acquirer expects to incur for
which it is not obligated at acquisition date, to be recorded against
income rather than included in purchase-price determination. It also requires recognition of
contingent arrangements at their acquisition-date fair values, with subsequent changes in fair
value generally reflected in income.
FASB Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements, an
amendment of ARB No. 51 (FAS 160) The FASB issued FAS 160 in December 2007, which will
become effective for the company January 1, 2009, with retroactive adoption of the Statements
presentation and disclosure requirements for existing minority interests. This standard will
require ownership interests in subsidiaries held by parties other than the parent to be presented
within the equity section of the consolidated statement of financial position but separate from the
parents equity. It will also require the amount of consolidated net income attributable to the
parent and the noncontrolling interest to be clearly identified and presented on the face of the
consolidated income statement. Certain changes in a parents ownership interest are to be accounted
for as equity transactions and when a subsidiary is deconsolidated, any noncontrolling equity
investment in the former subsidiary is to be initially measured at fair value. The company does not
anticipate the implementation of FAS 160 will significantly change the presentation of its
consolidated income statement or consolidated balance sheet.
FS-22
THIS
PAGE INTENTIONALLY LEFT BLANK
FS-23
Quarterly
Results and Stock Market Data
Unaudited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
|
2006 |
|
Millions of dollars, except per-share amounts |
|
4th Q |
|
|
3rd Q |
|
|
2nd Q |
|
|
1st Q |
|
|
|
4th Q |
|
|
3rd Q |
|
|
2nd Q |
|
|
1st Q |
|
|
|
|
|
Revenues and Other Income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales and other operating revenues1,2 |
|
$ |
59,900 |
|
|
$ |
53,545 |
|
|
$ |
54,344 |
|
|
$ |
46,302 |
|
|
|
$ |
46,238 |
|
|
$ |
52,977 |
|
|
$ |
52,153 |
|
|
$ |
53,524 |
|
Income from equity affiliates |
|
|
1,153 |
|
|
|
1,160 |
|
|
|
894 |
|
|
|
937 |
|
|
|
|
1,079 |
|
|
|
1,080 |
|
|
|
1,113 |
|
|
|
983 |
|
Other income |
|
|
357 |
|
|
|
468 |
|
|
|
856 |
|
|
|
988 |
|
|
|
|
429 |
|
|
|
155 |
|
|
|
270 |
|
|
|
117 |
|
|
|
|
|
Total Revenues and Other Income |
|
|
61,410 |
|
|
|
55,173 |
|
|
|
56,094 |
|
|
|
48,227 |
|
|
|
|
47,746 |
|
|
|
54,212 |
|
|
|
53,536 |
|
|
|
54,624 |
|
|
|
|
|
Costs and Other Deductions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased crude oil and products2 |
|
|
38,056 |
|
|
|
33,988 |
|
|
|
33,138 |
|
|
|
28,127 |
|
|
|
|
27,658 |
|
|
|
32,076 |
|
|
|
32,747 |
|
|
|
35,670 |
|
Operating expenses |
|
|
4,798 |
|
|
|
4,397 |
|
|
|
4,124 |
|
|
|
3,613 |
|
|
|
|
4,092 |
|
|
|
3,650 |
|
|
|
3,835 |
|
|
|
3,047 |
|
Selling, general and administrative expenses |
|
|
1,833 |
|
|
|
1,446 |
|
|
|
1,516 |
|
|
|
1,131 |
|
|
|
|
1,203 |
|
|
|
1,428 |
|
|
|
1,207 |
|
|
|
1,255 |
|
Exploration expenses |
|
|
449 |
|
|
|
295 |
|
|
|
273 |
|
|
|
306 |
|
|
|
|
547 |
|
|
|
284 |
|
|
|
265 |
|
|
|
268 |
|
Depreciation, depletion and amortization |
|
|
2,094 |
|
|
|
2,495 |
|
|
|
2,156 |
|
|
|
1,963 |
|
|
|
|
1,988 |
|
|
|
1,923 |
|
|
|
1,807 |
|
|
|
1,788 |
|
Taxes other than on income1 |
|
|
5,560 |
|
|
|
5,538 |
|
|
|
5,743 |
|
|
|
5,425 |
|
|
|
|
5,533 |
|
|
|
5,403 |
|
|
|
5,153 |
|
|
|
4,794 |
|
Interest and debt expense |
|
|
7 |
|
|
|
22 |
|
|
|
63 |
|
|
|
74 |
|
|
|
|
92 |
|
|
|
104 |
|
|
|
121 |
|
|
|
134 |
|
Minority interests |
|
|
35 |
|
|
|
25 |
|
|
|
19 |
|
|
|
28 |
|
|
|
|
2 |
|
|
|
20 |
|
|
|
22 |
|
|
|
26 |
|
|
|
|
|
Total Costs and Other Deductions |
|
|
52,832 |
|
|
|
48,206 |
|
|
|
47,032 |
|
|
|
40,667 |
|
|
|
|
41,115 |
|
|
|
44,888 |
|
|
|
45,157 |
|
|
|
46,982 |
|
|
|
|
|
Income Before Income Tax Expense |
|
|
8,578 |
|
|
|
6,967 |
|
|
|
9,062 |
|
|
|
7,560 |
|
|
|
|
6,631 |
|
|
|
9,324 |
|
|
|
8,379 |
|
|
|
7,642 |
|
Income Tax Expense |
|
|
3,703 |
|
|
|
3,249 |
|
|
|
3,682 |
|
|
|
2,845 |
|
|
|
|
2,859 |
|
|
|
4,307 |
|
|
|
4,026 |
|
|
|
3,646 |
|
|
|
|
|
Net Income |
|
$ |
4,875 |
|
|
$ |
3,718 |
|
|
$ |
5,380 |
|
|
$ |
4,715 |
|
|
|
$ |
3,772 |
|
|
$ |
5,017 |
|
|
$ |
4,353 |
|
|
$ |
3,996 |
|
|
|
|
|
Per-Share
of Common Stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
2.34 |
|
|
$ |
1.77 |
|
|
$ |
2.52 |
|
|
$ |
2.20 |
|
|
|
$ |
1.75 |
|
|
$ |
2.30 |
|
|
$ |
1.98 |
|
|
$ |
1.81 |
|
Diluted |
|
$ |
2.32 |
|
|
$ |
1.75 |
|
|
$ |
2.52 |
|
|
$ |
2.18 |
|
|
|
$ |
1.74 |
|
|
$ |
2.29 |
|
|
$ |
1.97 |
|
|
$ |
1.80 |
|
|
|
|
|
Dividends |
|
$ |
0.58 |
|
|
$ |
0.58 |
|
|
$ |
0.58 |
|
|
$ |
0.52 |
|
|
|
$ |
0.52 |
|
|
$ |
0.52 |
|
|
$ |
0.52 |
|
|
$ |
0.45 |
|
Common Stock Price Range High3 |
|
$ |
94.86 |
|
|
$ |
94.84 |
|
|
$ |
84.24 |
|
|
$ |
74.95 |
|
|
|
$ |
75.97 |
|
|
$ |
67.85 |
|
|
$ |
62.88 |
|
|
$ |
62.21 |
|
Low3 |
|
$ |
83.79 |
|
|
$ |
80.76 |
|
|
$ |
74.83 |
|
|
$ |
66.43 |
|
|
|
$ |
62.94 |
|
|
$ |
60.88 |
|
|
$ |
56.78 |
|
|
$ |
54.08 |
|
|
|
|
|
|
1 Includes excise, value-added and similar
taxes: |
|
|
$2,548 |
|
|
|
$2,550 |
|
|
|
$2,609 |
|
|
|
$2,414 |
|
|
|
|
$2,498 |
|
|
|
$2,522 |
|
|
|
$2,416 |
|
|
|
$2,115 |
|
2 Includes amounts for buy/sell contracts: |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$6,725 |
|
3 End of day price. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The companys common stock is listed on the New York Stock Exchange (trading symbol: CVX). As
of February 22, 2008, stockholders of record numbered
approximately 214,000. There are no
restrictions on the companys ability to pay dividends.
FS-24
Managements Responsibility for Financial Statements
To the Stockholders of Chevron Corporation
Management of Chevron is responsible for preparing the accompanying Consolidated Financial
Statements and the related information appearing in this report. The statements were prepared in
accordance with accounting principles generally accepted in the United States of America and fairly
represent the transactions and financial position of the company. The financial statements include
amounts that are based on managements best estimates and judgment.
As stated in its report included herein, the independent registered public accounting firm of
PricewaterhouseCoopers LLP has audited the companys consolidated financial statements in
accordance with the standards of the Public Company Accounting Oversight Board (United States).
The Board of Directors of Chevron has an Audit Committee composed of directors who are not
officers or employees of the company. The Audit Committee meets regularly with members of
management, the internal auditors and the independent registered public accounting firm to review
accounting, internal control, auditing and financial reporting matters. Both the internal auditors
and the independent registered public accounting firm have free and direct access to the Audit
Committee without the presence of management.
Managements Report on Internal Control Over Financial Reporting
The companys management is responsible for establishing and maintaining adequate internal
control over financial reporting, as such term is defined in Exchange Act Rule 13a15(f). The
companys management, including the Chief Executive Officer and Chief Financial Officer, conducted
an evaluation of the effectiveness of the companys internal control over financial reporting based
on the Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations
of the Treadway Commission. Based on the results of this evaluation, the companys management
concluded that internal control over financial reporting was effective as of December 31, 2007.
The effectiveness of the companys internal control over financial reporting as of December
31, 2007, has been audited by PricewaterhouseCoopers LLP, an independent registered public
accounting firm, as stated in its report included herein.
|
|
|
|
|
|
|
|
|
|
David J. OReilly |
|
Stephen J. Crowe |
|
Mark A. Humphrey |
Chairman of the Board |
|
Vice President |
|
Vice President |
and Chief Executive Officer |
|
and Chief Financial Officer |
|
and Comptroller |
|
February 28,
2008 |
|
|
|
|
FS-25
Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of Chevron Corporation:
In our opinion, the accompanying consolidated balance sheets and the related consolidated
statements of income, comprehensive income, shareholders equity and cash flows present fairly, in
all material respects, the financial position of Chevron Corporation and its subsidiaries at
December 31, 2007, and December 31, 2006, and the results of their operations and their cash flows
for each of the three years in the period ended December 31, 2007, in conformity with accounting
principles generally accepted in the United States of America. In addition, in our opinion, the
financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in
all material respects, the information set forth therein when read in conjunction with the related
consolidated financial statements. Also, in our opinion, the Company maintained, in all material
respects, effective internal control over financial reporting as of December 31, 2007, based on
criteria established in Internal Control Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO). The Companys management is responsible
for these financial statements and financial statement schedule; for maintaining effective internal
control over financial reporting and for its assessment of the effectiveness of internal control
over financial reporting, included in the accompanying Managements Report on Internal Controls
Over Financial Reporting. Our responsibility is to express opinions on these financial statements,
on the financial statement schedule, and on the Companys internal control over financial reporting
based on our integrated audits. We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those standards require that we plan and
perform the audits to obtain reasonable assurance about whether the financial statements are free
of material misstatements and whether effective internal control over financial reporting was
maintained in all material respects. Our audits of the financial statements included examining, on
a test basis, evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. Our audit of internal control over
financial reporting included obtaining an understanding of internal control over financial
reporting, assessing the risk that a material weakness exists, and testing and evaluating the
design and operating effectiveness of internal control, based on the assessed risk. Our audits also
included performing such other procedures as we considered necessary in
the circumstances. We believe that our audits provide a reasonable basis for our opinions.
As discussed
in Note 13 to the Consolidated Financial Statements, the Company changed its method of accounting
for buy/sell contracts on April 1, 2006.
As discussed in Note 15 to the Consolidated Financial Statements, the Company changed its
method of accounting for uncertain income tax positions on January 1, 2007.
As discussed in Note 20 to the Consolidated Financial Statements, the Company changed its
method of accounting for defined benefit pension and other postretirement plans on December 31,
2006.
A companys internal control over financial reporting is a process designed to provide
reasonable assurance regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally accepted accounting
principles. A companys internal control over financial reporting includes those policies and
procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately
and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide
reasonable assurance that transactions are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and
directors of the company; and (iii) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the companys assets that could have
a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent
or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
subject to the risk that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate.
/s/PricewaterhouseCoopers LLP
San Francisco, California
February 28, 2008
FS-26
Consolidated
Statement of Income
Millions
of dollars, except per-share amounts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31 |
|
|
|
2007 |
|
|
|
2006 |
|
|
2005 |
|
|
|
|
|
|
Revenues and Other Income |
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales and other operating revenues1,2 |
|
$ |
214,091 |
|
|
|
$ |
204,892 |
|
|
$ |
193,641 |
|
Income from equity affiliates |
|
|
4,144 |
|
|
|
|
4,255 |
|
|
|
3,731 |
|
Other income |
|
|
2,669 |
|
|
|
|
971 |
|
|
|
828 |
|
|
|
|
|
|
Total Revenues and Other Income |
|
|
220,904 |
|
|
|
|
210,118 |
|
|
|
198,200 |
|
|
|
|
|
|
Costs and Other Deductions |
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased crude oil and products2 |
|
|
133,309 |
|
|
|
|
128,151 |
|
|
|
127,968 |
|
Operating expenses |
|
|
16,932 |
|
|
|
|
14,624 |
|
|
|
12,191 |
|
Selling, general and administrative expenses |
|
|
5,926 |
|
|
|
|
5,093 |
|
|
|
4,828 |
|
Exploration expenses |
|
|
1,323 |
|
|
|
|
1,364 |
|
|
|
743 |
|
Depreciation, depletion and amortization |
|
|
8,708 |
|
|
|
|
7,506 |
|
|
|
5,913 |
|
Taxes other than on income1 |
|
|
22,266 |
|
|
|
|
20,883 |
|
|
|
20,782 |
|
Interest and debt expense |
|
|
166 |
|
|
|
|
451 |
|
|
|
482 |
|
Minority interests |
|
|
107 |
|
|
|
|
70 |
|
|
|
96 |
|
|
|
|
|
|
Total Costs and Other Deductions |
|
|
188,737 |
|
|
|
|
178,142 |
|
|
|
173,003 |
|
|
|
|
|
|
Income Before Income Tax Expense |
|
|
32,167 |
|
|
|
|
31,976 |
|
|
|
25,197 |
|
Income Tax Expense |
|
|
13,479 |
|
|
|
|
14,838 |
|
|
|
11,098 |
|
|
|
|
|
|
Net Income |
|
$ |
18,688 |
|
|
|
$ |
17,138 |
|
|
$ |
14,099 |
|
|
|
|
|
|
Per-Share of Common Stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
8.83 |
|
|
|
$ |
7.84 |
|
|
$ |
6.58 |
|
Diluted |
|
$ |
8.77 |
|
|
|
$ |
7.80 |
|
|
$ |
6.54 |
|
|
|
|
|
|
1 Includes excise, value-added and similar taxes. |
|
$ |
10,121 |
|
|
|
$ |
9,551 |
|
|
$ |
8,719 |
|
2 Includes amounts in revenues for buy/sell contracts; associated costs are in Purchased crude oil and products. |
|
|
|
|
|
|
|
|
|
|
|
|
|
Refer also to Note 13, on page FS-42. |
|
$ |
|
|
|
|
$ |
6,725 |
|
|
$ |
23,822 |
|
See accompanying Notes to the Consolidated Financial Statements.
FS-27
Consolidated
Statement of Comprehensive Income
Millions of dollars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31 |
|
|
|
2007 |
|
|
|
2006 |
|
|
2005 |
|
|
|
|
|
|
Net Income |
|
$ |
18,688 |
|
|
|
$ |
17,138 |
|
|
$ |
14,099 |
|
|
|
|
|
|
Currency translation adjustment |
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized net change arising during period |
|
|
31 |
|
|
|
|
55 |
|
|
|
(5 |
) |
|
|
|
|
|
Unrealized holding gain (loss) on securities |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net gain (loss) arising during period |
|
|
17 |
|
|
|
|
(88 |
) |
|
|
(32 |
) |
Reclassification to net income of net realized loss |
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
19 |
|
|
|
|
(88 |
) |
|
|
(32 |
) |
|
|
|
|
|
Derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
derivatives (loss) gain on hedge transactions |
|
|
(10 |
) |
|
|
|
2 |
|
|
|
(242 |
) |
Reclassification to net income of net realized loss |
|
|
7 |
|
|
|
|
95 |
|
|
|
34 |
|
Income taxes on derivatives transactions |
|
|
(3 |
) |
|
|
|
(30 |
) |
|
|
77 |
|
|
|
|
|
|
Total |
|
|
(6 |
) |
|
|
|
67 |
|
|
|
(131 |
) |
|
|
|
|
|
Defined benefit plans |
|
|
|
|
|
|
|
|
|
|
|
|
|
Minimum pension liability adjustment |
|
|
|
|
|
|
|
(88 |
) |
|
|
89 |
|
Actuarial loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization to net income of net actuarial loss |
|
|
356 |
|
|
|
|
|
|
|
|
|
|
Actuarial gain arising during period |
|
|
530 |
|
|
|
|
|
|
|
|
|
|
Prior service cost |
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization to net income of net prior service credits |
|
|
(15 |
) |
|
|
|
|
|
|
|
|
|
Prior service cost arising during period |
|
|
204 |
|
|
|
|
|
|
|
|
|
|
Non-sponsored defined benefit plans |
|
|
19 |
|
|
|
|
|
|
|
|
|
|
Income taxes on defined benefit plans |
|
|
(409 |
) |
|
|
|
50 |
|
|
|
(31 |
) |
|
|
|
|
|
Total |
|
|
685 |
|
|
|
|
(38 |
) |
|
|
58 |
|
|
|
|
|
|
Other Comprehensive Gain (Loss), Net of Tax |
|
|
729 |
|
|
|
|
(4 |
) |
|
|
(110 |
) |
|
|
|
|
|
Comprehensive Income |
|
$ |
19,417 |
|
|
|
$ |
17,134 |
|
|
$ |
13,989 |
|
|
|
|
|
|
See accompanying Notes to the Consolidated Financial Statements.
FS-28
Consolidated
Balance Sheet
Millions of dollars, except per-share amounts
|
|
|
|
|
|
|
|
|
|
|
|
At December 31 |
|
|
|
2007 |
|
|
|
2006 |
|
|
|
|
|
|
Assets |
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
7,362 |
|
|
|
$ |
10,493 |
|
Marketable securities |
|
|
732 |
|
|
|
|
953 |
|
Accounts and notes receivable (less allowance: 2007 $165; 2006 $175) |
|
|
22,446 |
|
|
|
|
17,628 |
|
Inventories: |
|
|
|
|
|
|
|
|
|
Crude oil and petroleum products |
|
|
4,003 |
|
|
|
|
3,586 |
|
Chemicals |
|
|
290 |
|
|
|
|
258 |
|
Materials, supplies and other |
|
|
1,017 |
|
|
|
|
812 |
|
|
|
|
|
|
|
|
Total inventories |
|
|
5,310 |
|
|
|
|
4,656 |
|
Prepaid expenses and other current assets |
|
|
3,527 |
|
|
|
|
2,574 |
|
|
|
|
|
|
Total Current Assets |
|
|
39,377 |
|
|
|
|
36,304 |
|
Long-term receivables, net |
|
|
2,194 |
|
|
|
|
2,203 |
|
Investments and advances |
|
|
20,477 |
|
|
|
|
18,552 |
|
Properties, plant and equipment, at cost |
|
|
154,084 |
|
|
|
|
137,747 |
|
Less: Accumulated depreciation, depletion and amortization |
|
|
75,474 |
|
|
|
|
68,889 |
|
|
|
|
|
|
|
|
Properties, plant and equipment, net |
|
|
78,610 |
|
|
|
|
68,858 |
|
Deferred charges and other assets |
|
|
3,491 |
|
|
|
|
2,088 |
|
Goodwill |
|
|
4,637 |
|
|
|
|
4,623 |
|
|
|
|
|
|
Total Assets |
|
$ |
148,786 |
|
|
|
$ |
132,628 |
|
|
|
|
|
|
Liabilities and Stockholders Equity |
|
|
|
|
|
|
|
|
|
Short-term debt |
|
$ |
1,162 |
|
|
|
$ |
2,159 |
|
Accounts payable |
|
|
21,756 |
|
|
|
|
16,675 |
|
Accrued liabilities |
|
|
5,275 |
|
|
|
|
4,546 |
|
Federal and other taxes on income |
|
|
3,972 |
|
|
|
|
3,626 |
|
Other taxes payable |
|
|
1,633 |
|
|
|
|
1,403 |
|
|
|
|
|
|
Total Current Liabilities |
|
|
33,798 |
|
|
|
|
28,409 |
|
Long-term debt |
|
|
5,664 |
|
|
|
|
7,405 |
|
Capital lease obligations |
|
|
406 |
|
|
|
|
274 |
|
Deferred credits and other noncurrent obligations |
|
|
15,007 |
|
|
|
|
11,000 |
|
Noncurrent deferred income taxes |
|
|
12,170 |
|
|
|
|
11,647 |
|
Reserves for employee benefit plans |
|
|
4,449 |
|
|
|
|
4,749 |
|
Minority interests |
|
|
204 |
|
|
|
|
209 |
|
|
|
|
|
|
Total Liabilities |
|
|
71,698 |
|
|
|
|
63,693 |
|
|
|
|
|
|
Preferred stock (authorized 100,000,000 shares, $1.00 par value; none issued) |
|
|
|
|
|
|
|
|
|
Common stock (authorized 4,000,000,000 shares, $0.75 par value; 2,442,676,580
shares issued at December 31, 2007 and 2006) |
|
|
1,832 |
|
|
|
|
1,832 |
|
Capital in excess of par value |
|
|
14,289 |
|
|
|
|
14,126 |
|
Retained earnings |
|
|
82,329 |
|
|
|
|
68,464 |
|
Notes receivable key employees |
|
|
(1 |
) |
|
|
|
(2 |
) |
Accumulated other comprehensive loss |
|
|
(2,015 |
) |
|
|
|
(2,636 |
) |
Deferred compensation and benefit plan trust |
|
|
(454 |
) |
|
|
|
(454 |
) |
Treasury stock, at cost (2007 352,242,618 shares; 2006 278,118,341 shares) |
|
|
(18,892 |
) |
|
|
|
(12,395 |
) |
|
|
|
|
|
Total Stockholders Equity |
|
|
77,088 |
|
|
|
|
68,935 |
|
|
|
|
|
|
Total Liabilities and Stockholders Equity |
|
$ |
148,786 |
|
|
|
$ |
132,628 |
|
|
|
|
|
|
See accompanying Notes to the Consolidated Financial Statements.
FS-29
Consolidated
Statement of Cash Flows
Millions of dollars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31 |
|
|
|
2007 |
|
|
|
2006 |
|
|
2005 |
|
|
|
|
|
|
Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
18,688 |
|
|
|
$ |
17,138 |
|
|
$ |
14,099 |
|
Adjustments |
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
8,708 |
|
|
|
|
7,506 |
|
|
|
5,913 |
|
Dry hole expense |
|
|
507 |
|
|
|
|
520 |
|
|
|
226 |
|
Distributions less than income from equity affiliates |
|
|
(1,439 |
) |
|
|
|
(979 |
) |
|
|
(1,304 |
) |
Net before-tax gains on asset retirements and sales |
|
|
(2,315 |
) |
|
|
|
(229 |
) |
|
|
(134 |
) |
Net foreign currency effects |
|
|
378 |
|
|
|
|
259 |
|
|
|
62 |
|
Deferred income tax provision |
|
|
261 |
|
|
|
|
614 |
|
|
|
1,393 |
|
Net decrease (increase) in operating working capital |
|
|
685 |
|
|
|
|
1,044 |
|
|
|
(54 |
) |
Minority interest in net income |
|
|
107 |
|
|
|
|
70 |
|
|
|
96 |
|
(Increase) in long-term receivables |
|
|
(82 |
) |
|
|
|
(900 |
) |
|
|
(191 |
) |
(Increase) decrease in other deferred charges |
|
|
(530 |
) |
|
|
|
232 |
|
|
|
668 |
|
Cash contributions to employee pension plans |
|
|
(317 |
) |
|
|
|
(449 |
) |
|
|
(1,022 |
) |
Other |
|
|
326 |
|
|
|
|
(503 |
) |
|
|
353 |
|
|
|
|
|
|
Net Cash Provided by Operating Activities |
|
|
24,977 |
|
|
|
|
24,323 |
|
|
|
20,105 |
|
|
|
|
|
|
Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash portion of Unocal acquisition, net of Unocal cash received |
|
|
|
|
|
|
|
|
|
|
|
(5,934 |
) |
Capital expenditures |
|
|
(16,678 |
) |
|
|
|
(13,813 |
) |
|
|
(8,701 |
) |
Repayment of loans by equity affiliates |
|
|
21 |
|
|
|
|
463 |
|
|
|
57 |
|
Proceeds from asset sales |
|
|
3,338 |
|
|
|
|
989 |
|
|
|
2,681 |
|
Net sales of marketable securities |
|
|
185 |
|
|
|
|
142 |
|
|
|
336 |
|
Net purchases of other short-term investments |
|
|
(799 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Used for Investing Activities |
|
|
(13,933 |
) |
|
|
|
(12,219 |
) |
|
|
(11,561 |
) |
|
|
|
|
|
Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net payments of short-term obligations |
|
|
(345 |
) |
|
|
|
(677 |
) |
|
|
(109 |
) |
Repayments of long-term debt and other financing obligations |
|
|
(3,343 |
) |
|
|
|
(2,224 |
) |
|
|
(966 |
) |
Proceeds from issuances of long-term debt |
|
|
650 |
|
|
|
|
|
|
|
|
20 |
|
Cash dividends common stock |
|
|
(4,791 |
) |
|
|
|
(4,396 |
) |
|
|
(3,778 |
) |
Dividends paid to minority interests |
|
|
(77 |
) |
|
|
|
(60 |
) |
|
|
(98 |
) |
Net purchases of treasury shares |
|
|
(6,389 |
) |
|
|
|
(4,491 |
) |
|
|
(2,597 |
) |
Redemption of preferred stock of subsidiaries |
|
|
|
|
|
|
|
|
|
|
|
(140 |
) |
|
|
|
|
|
Net Cash Used for Financing Activities |
|
|
(14,295 |
) |
|
|
|
(11,848 |
) |
|
|
(7,668 |
) |
|
|
|
|
|
Effect of Exchange Rate Changes
On Cash and Cash Equivalents |
|
|
120 |
|
|
|
|
194 |
|
|
|
(124 |
) |
|
|
|
|
|
Net Change in Cash and Cash Equivalents |
|
|
(3,131 |
) |
|
|
|
450 |
|
|
|
752 |
|
Cash and Cash Equivalents at January 1 |
|
|
10,493 |
|
|
|
|
10,043 |
|
|
|
9,291 |
|
|
|
|
|
|
Cash and Cash Equivalents at December 31 |
|
$ |
7,362 |
|
|
|
$ |
10,493 |
|
|
$ |
10,043 |
|
|
|
|
|
|
See accompanying Notes to the Consolidated Financial Statements.
FS-30
Consolidated
Statement of Stockholders Equity
Shares in thousands; amounts in millions of dollars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
|
2006 |
|
|
2005 |
|
|
|
Shares |
|
|
Amount |
|
|
|
Shares |
|
|
Amount |
|
|
Shares |
|
|
Amount |
|
|
|
|
|
|
Preferred Stock |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
$ |
|
|
|
|
|
|
|
$ |
|
|
|
|
|
|
|
Common Stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1 |
|
|
2,442,677 |
|
|
$ |
1,832 |
|
|
|
|
2,442,677 |
|
|
$ |
1,832 |
|
|
|
2,274,032 |
|
|
$ |
1,706 |
|
Shares issued for Unocal acquisition |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
168,645 |
|
|
|
126 |
|
|
|
|
|
|
|
|
Balance at December 31 |
|
|
2,442,677 |
|
|
$ |
1,832 |
|
|
|
|
2,442,677 |
|
|
$ |
1,832 |
|
|
|
2,442,677 |
|
|
$ |
1,832 |
|
|
|
|
|
|
Capital in Excess of Par |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1 |
|
|
|
|
|
$ |
14,126 |
|
|
|
|
|
|
|
$ |
13,894 |
|
|
|
|
|
|
$ |
4,160 |
|
Shares issued for Unocal acquisition |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,585 |
|
Treasury stock transactions |
|
|
|
|
|
|
163 |
|
|
|
|
|
|
|
|
232 |
|
|
|
|
|
|
|
149 |
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31 |
|
|
|
|
|
$ |
14,289 |
|
|
|
|
|
|
|
$ |
14,126 |
|
|
|
|
|
|
$ |
13,894 |
|
|
|
|
|
|
Retained Earnings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1 |
|
|
|
|
|
$ |
68,464 |
|
|
|
|
|
|
|
$ |
55,738 |
|
|
|
|
|
|
$ |
45,414 |
|
Net income |
|
|
|
|
|
|
18,688 |
|
|
|
|
|
|
|
|
17,138 |
|
|
|
|
|
|
|
14,099 |
|
Cash dividends on common stock |
|
|
|
|
|
|
(4,791 |
) |
|
|
|
|
|
|
|
(4,396 |
) |
|
|
|
|
|
|
(3,778 |
) |
Adoption of EITF 046, Accounting for Stripping Costs
Incurred during Production in the Mining Industry |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(19 |
) |
|
|
|
|
|
|
|
|
Adoption of FIN 48, Accounting for Uncertainty in Income Taxes |
& |