Quarterly Report — Form 10-Q Filing Table of Contents
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(Exact name of registrant as
specified in its charter)
Delaware
94-0890210
(State or other jurisdiction
of
(I.R.S. Employer
incorporation or
organization)
Identification Number)
6001 Bollinger Canyon Road,
94583-2324
San Ramon, California
(Zip Code)
(Address of principal executive
offices)
Registrant’s
telephone number, including area code:
(925) 842-1000
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(Former name or former address, if changed since last
report.)
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
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accelerated filer, an accelerated filer, a non-accelerated
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filer” and “smaller reporting company” in
Rule 12b-2
of the Exchange Act.
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(Do not check if a smaller
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Indicate the number of shares outstanding of each of the
issuer’s classes of common stock, as of the latest
practicable date:
Cautionary Statements Relevant to Forward-Looking Information
for the Purpose of “Safe Harbor” Provisions of the
Private Securities Litigation Reform Act of 1995
2
PART I
FINANCIAL INFORMATION
Item 1.
Consolidated Financial Statements —
Consolidated Statement of Income for the Three and Six Months
Ended June 30, 2008, and 2007
3
Consolidated Statement of Comprehensive Income for the Three and
Six Months Ended June 30, 2008, and 2007
This quarterly report on
Form 10-Q
of Chevron Corporation contains forward-looking statements
relating to Chevron’s operations that are based on
management’s current expectations, estimates, and
projections about the petroleum, chemicals, and other
energy-related industries. Words such as
“anticipates,”“expects,”“intends,”“plans,”“targets,”“projects,”“believes,”“seeks,”“schedules,”“estimates,”“budgets” and similar expressions are intended to
identify such forward-looking statements. These statements are
not guarantees of future performance and are subject to certain
risks, uncertainties and other factors, some of which are beyond
our control and are difficult to predict. Therefore, actual
outcomes and results may differ materially from what is
expressed or forecasted in such forward-looking statements. The
reader should not place undue reliance on these
forward-looking
statements, which speak only as of the date of this report.
Unless legally required, Chevron undertakes no obligation to
update publicly any forward-looking statements, whether as a
result of new information, future events or otherwise.
Among the important factors that could cause actual results to
differ materially from those in the forward-looking statements
are crude-oil and natural-gas prices; refining, marketing and
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 company’s joint-venture
partners to fund their share of operations and development
activities; the potential failure to achieve expected net
production from existing and future crude-oil and natural-gas
development projects; potential delays in the development,
construction or
start-up of
planned projects; the potential disruption or interruption of
the company’s net production or manufacturing facilities or
delivery/transportation networks due to war, accidents,
political events, civil unrest, severe weather or crude-oil
production quotas that might be imposed by OPEC (Organization of
Petroleum Exporting Countries); the potential liability for
remedial actions or assessments under existing or future
environmental regulations and litigation; significant investment
or product changes under existing or future environmental
statutes, regulations and litigation; the potential liability
resulting from pending or future litigation; the company’s
acquisition or disposition of assets; gains and losses from
asset dispositions or impairments; government-mandated sales,
divestitures, recapitalizations, industry-specific taxes,
changes in fiscal terms or restrictions on scope of company
operations; foreign currency movements compared with the
U.S. dollar; the effects of changed accounting rules under
generally accepted accounting principles promulgated by
rule-setting bodies; and the factors set forth under the heading
“Risk Factors” on pages 32 and 33 of the
company’s 2007 Annual Report on
Form 10-K/A.
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.
The accompanying consolidated financial statements of Chevron
Corporation and its subsidiaries (the company) have not been
audited by independent accountants. In the opinion of the
company’s management, the interim data include all
adjustments necessary for a fair statement of the results for
the interim periods. These adjustments were of a normal
recurring nature.
Certain notes and other information have been condensed or
omitted from the interim financial statements presented in this
Quarterly Report on
Form 10-Q.
Therefore, these financial statements should be read in
conjunction with the company’s 2007 Annual Report on
Form 10-K/A.
The results for the three- and six-month periods ended
June 30, 2008, are not necessarily indicative of future
financial results.
Earnings in the first quarter 2007 included a $700 million
gain on a sale of the company’s interest in refining and
related assets in the Netherlands. Second quarter 2007 results
included a $680 million gain on the sale of the
company’s holding of Dynegy Inc. common stock.
Note 2.
Information
Relating to the Statement of Cash Flows
The “Net increase in operating working capital” was
composed of the following operating changes:
Six Months Ended
June 30
2008
2007
(Millions of dollars)
Increase in accounts and notes receivable
$
(8,160
)
$
(1,464
)
Increase in inventories
(1,062
)
(590
)
Increase in prepaid expenses and other current assets
(216
)
(484
)
Increase in accounts payable and accrued liabilities
7,438
1,014
Increase in income and other taxes payable
1,498
1,036
Net decrease in operating working capital
$
(502
)
$
(488
)
In accordance with the cash-flow classification requirements of
FAS 123R, Share-Based Payment, the “Net
increase in operating working capital” includes reductions
of $98 million and $65 million for excess income tax
benefits associated with stock options exercised during the six
months ended June 30, 2008 and 2007, respectively. These
amounts are offset by an equal amount in “Net purchases of
treasury shares.”
“Net Cash Provided by Operating Activities” included
the following cash payments for interest on debt and for income
taxes:
Six Months Ended
June 30
2008
2007
(Millions of dollars)
Interest on debt (net of capitalized interest)
$
2
$
149
Income taxes
8,679
5,696
7
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The “Net sales of marketable securities” consisted of
the following gross amounts:
Six Months Ended
June 30
2008
2007
(Millions of dollars)
Marketable securities purchased
$
(3,103
)
$
(836
)
Marketable securities sold
3,400
873
Net sales of marketable securities
$
297
$
37
The “Net purchases of treasury shares” represents the
cost of common shares acquired in the open market less the cost
of shares issued for share-based compensation plans. Net
purchases totaled $3.6 billion and $2.6 billion in the
2008 and 2007 periods, respectively. Purchases in the first half
of 2008 were under the company’s stock repurchase program
initiated in September 2007.
The major components of “Capital expenditures” and the
reconciliation of this amount to the capital and exploratory
expenditures, including equity affiliates, presented in
“Management’s Discussion and Analysis of Financial
Condition and Results of Operations,” are presented in the
following table:
Six Months Ended
June 30
2008
2007
(Millions of dollars)
Additions to properties, plant and equipment
$
8,433
$
6,365
Additions to investments
487
464
Current-year dry-hole expenditures
154
209
Payments for other liabilities and assets, net
(103
)
(81
)
Capital expenditures
8,971
6,957
Expensed exploration expenditures
361
335
Assets acquired through capital lease obligations
11
183
Capital and exploratory expenditures, excluding equity affiliates
9,343
7,475
Company’s share of expenditures by equity affiliates
941
1,096
Capital and exploratory expenditures, including equity affiliates
$
10,284
$
8,571
Note 3.
Operating
Segments and Geographic Data
Although each subsidiary of Chevron is responsible for its own
affairs, Chevron Corporation manages its investments in these
subsidiaries and their affiliates. For this purpose, the
investments are grouped as follows: upstream
— exploration and production; downstream —
refining, marketing and transportation; chemicals; and all
other. The first three of these groupings represent the
company’s “reportable segments” and
“operating segments” as defined in Financial
Accounting Standards Board (FASB) Statement No. 131,
Disclosures about Segments of an Enterprise and Related
Information (FAS 131).
The segments are separately managed for investment purposes
under a structure that includes “segment managers” who
report to the company’s “chief operating decision
maker” (CODM) (terms as defined in FAS 131). The CODM
is the company’s Executive Committee, a committee of senior
officers that includes the Chief Executive Officer, and that in
turn reports to the Board of Directors of Chevron Corporation.
The operating segments represent components of the company as
described in FAS 131 terms that engage in activities
(a) from which revenues are earned and expenses are
incurred; (b) whose operating results are regularly
reviewed by the CODM, which makes decisions about resources to
be allocated to the segments and to assess their performance;
and (c) for which discrete financial information is
available.
8
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Segment managers for the reportable segments are directly
accountable to and maintain regular contact with the
company’s CODM to discuss the segment’s operating
activities and financial performance. The CODM approves annual
capital and exploratory budgets at the reportable segment level,
as well as reviews capital and exploratory funding for major
projects and approves major changes to the annual capital and
exploratory budgets. However,
business-unit
managers within the operating segments are directly responsible
for decisions relating to project implementation and all other
matters connected with daily operations. Company officers who
are members of the Executive Committee also have individual
management responsibilities and participate in other committees
for purposes other than acting as the CODM.
“All other” activities include mining operations,
power generation businesses, worldwide cash management and debt
financing activities, corporate administrative functions,
insurance operations, real estate activities, alternative fuels,
technology companies, and the company’s interest in Dynegy
Inc. prior to its sale in May 2007.
The company’s primary country of operation is the United
States of America, its country of domicile. Other components of
the company’s operations are reported as
“International” (outside the United States).
Segment Earnings The company evaluates the
performance of its operating segments on an after-tax basis,
without considering the effects of debt financing interest
expense or investment interest income, both of which are managed
by the company on a worldwide basis. Corporate administrative
costs and assets are not allocated to the operating segments.
However, operating segments are billed for the direct use of
corporate services. Nonbillable costs remain at the corporate
level in “All Other.” Income by major operating area
for the three- and six-month periods ended June 30, 2008
and 2007, is presented in the following table:
Segment
Income
Three Months Ended
Six Months Ended
June 30
June 30
2008
2007
2008
2007
(Millions of dollars)
Upstream
United States
$
2,191
$
1,223
$
3,790
$
2,019
International
5,057
2,416
8,586
4,527
Total Upstream
7,248
3,639
12,376
6,546
Downstream
United States
(682
)
781
(678
)
1,131
International
(52
)
517
196
1,790
Total Downstream
(734
)
1,298
(482
)
2,921
Chemicals
United States
1
60
2
139
International
40
44
82
85
Total Chemicals
41
104
84
224
Total Segment Income
6,555
5,041
11,978
9,691
All Other
Interest Expense
—
(40
)
—
(88
)
Interest Income
48
115
105
213
Other
(628
)
264
(940
)
279
Net Income
$
5,975
$
5,380
$
11,143
$
10,095
9
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Segment Assets Segment assets do not include
intercompany investments or intercompany receivables. “All
Other” assets in 2008 consist primarily of worldwide cash,
cash equivalents and marketable securities, real estate,
information systems, mining operations, power generation
businesses, technology companies and assets of the corporate
administrative functions. Segment assets at June 30, 2008,
and December 31, 2007, are as follows:
Segment
Assets
At June 30
At December 31
2008
2007
(Millions of dollars)
Upstream
United States
$
25,831
$
23,535
International
65,130
61,049
Goodwill
4,629
4,637
Total Upstream
95,590
89,221
Downstream
United States
19,230
16,790
International
31,049
26,075
Total Downstream
50,279
42,865
Chemicals
United States
2,567
2,484
International
981
870
Total Chemicals
3,548
3,354
Total Segment Assets
149,417
135,440
All Other
United States
5,573
6,847
International
8,076
6,499
Total All Other
13,649
13,346
Total Assets — United States
53,201
49,656
Total Assets — International
105,236
94,493
Goodwill
4,629
4,637
Total Assets
$
163,066
$
148,786
Segment Sales and Other Operating
Revenues Operating-segment sales and other
operating revenues, including internal transfers, for the three-
and six-month periods ended June 30, 2008 and 2007, are
presented in the following table. Products are transferred
between operating segments at internal product values that
approximate market prices. Revenues for the upstream segment are
derived primarily from the production and sale of crude oil and
natural gas, as well as the sale of third-party production of
natural gas. Revenues for the downstream segment are derived
from the refining and marketing of petroleum products such as
gasoline, jet fuel, gas oils, lubricants, residual fuel oils and
other products derived from crude oil. This segment also
generates revenues from the transportation and trading of crude
oil and refined products. Revenues for the chemicals segment are
derived primarily from the manufacture and sale of additives for
lubricants and fuels. “All Other” activities include
revenues from mining operations of coal and other minerals,
power generation businesses, insurance operations, real estate
activities and technology companies.
10
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Sales and
Other Operating Revenues
Three Months Ended
Six Months Ended
June 30
June 30
2008
2007
2008
2007
(Millions of dollars)
Upstream
United States
$
12,111
$
8,073
$
21,944
$
15,095
International
13,780
8,719
24,219
16,097
Sub-total
25,891
16,792
46,163
31,192
Intersegment Elimination — United States
(4,782
)
(2,700
)
(8,633
)
(4,987
)
Intersegment Elimination — International
(8,399
)
(5,073
)
(14,169
)
(8,915
)
Total Upstream
12,710
9,019
23,361
17,290
Downstream
United States
27,957
19,247
50,111
34,950
International
39,793
25,597
71,162
47,544
Sub-total
67,750
44,844
121,273
82,494
Intersegment Elimination — United States
(135
)
(133
)
(251
)
(267
)
Intersegment Elimination — International
(44
)
(9
)
(63
)
(15
)
Total Downstream
67,571
44,702
120,959
82,212
Chemicals
United States
146
172
278
323
International
429
346
822
657
Sub-total
575
518
1,100
980
Intersegment Elimination — United States
(71
)
(66
)
(129
)
(118
)
Intersegment Elimination — International
(40
)
(38
)
(79
)
(80
)
Total Chemicals
464
414
892
782
All Other
United States
439
372
764
643
International
19
21
37
38
Sub-total
458
393
801
681
Intersegment Elimination — United States
(235
)
(179
)
(381
)
(310
)
Intersegment Elimination — International
(6
)
(5
)
(11
)
(9
)
Total All Other
217
209
409
362
Sales and Other Operating Revenues
United States
40,653
27,864
73,097
51,011
International
54,021
34,683
96,240
64,336
Sub-total
94,674
62,547
169,337
115,347
Intersegment Elimination — United States
(5,223
)
(3,078
)
(9,394
)
(5,682
)
Intersegment Elimination — International
(8,489
)
(5,125
)
(14,322
)
(9,019
)
Total Sales and Other Operating Revenues
$
80,962
$
54,344
$
145,621
$
100,646
11
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Note 4.
Summarized
Financial Data — Chevron U.S.A. Inc.
Chevron U.S.A. Inc. (CUSA) is a major subsidiary of Chevron
Corporation. CUSA and its subsidiaries manage and operate most
of Chevron’s U.S. businesses. Assets include those
related to the exploration and production of crude oil, natural
gas and natural gas liquids and those associated with refining,
marketing, supply and distribution of products derived from
petroleum, excluding most of the regulated pipeline operations
of Chevron. CUSA also holds the company’s investment in the
Chevron Phillips Chemical Company LLC (CPChem) joint venture,
which is accounted for using the equity method.
The summarized financial information for CUSA and its
consolidated subsidiaries is presented in the table below.
Six Months Ended
June 30
2008
2007
(Millions of dollars)
Sales and other operating revenues
$
109,290
$
71,500
Costs and other deductions
106,379
67,691
Net income
1,796
3,553
At June 30
At December 31
2008
2007
(Millions of dollars)
Current assets
$
39,928
$
32,803
Other assets
29,481
27,401
Current liabilities
26,571
20,050
Other liabilities
12,311
11,447
Net equity
$
30,527
$
28,707
Memo: Total debt
$
4,333
$
4,433
Note 5.
Summarized
Financial Data — Chevron Transport
Corporation
Chevron Transport Corporation Limited (CTC), incorporated in
Bermuda, is an indirect, wholly owned subsidiary of Chevron
Corporation. CTC is the principal operator of Chevron’s
international tanker fleet and is engaged in the marine
transportation of crude oil and refined petroleum products. Most
of CTC’s shipping revenue is derived by providing
transportation services to other Chevron companies. Chevron
Corporation has fully and unconditionally guaranteed this
subsidiary’s obligations in connection with certain debt
securities issued by a third party. Summarized financial
information for CTC and its consolidated subsidiaries is
presented as follows:
Three Months Ended
Six Months Ended
June 30
June 30
2008
2007
2008
2007
(Millions of dollars)
Sales and other operating revenues
$
260
$
182
$
501
$
339
Costs and other deductions
234
177
453
331
Net income
27
5
90
11
12
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
At June 30
At December 31
2008
2007
(Millions of dollars)
Current assets
$
472
$
335
Other assets
176
337
Current liabilities
116
107
Other liabilities
87
188
Net equity
$
445
$
377
There were no restrictions on CTC’s ability to pay
dividends or make loans or advances at June 30, 2008.
Note 6.
Income
Taxes
Taxes on income for the second quarter and first half of 2008
were $5.8 billion and $10.3 billion, respectively,
compared with $3.7 billion and $6.5 billion for the
corresponding periods in 2007. The associated effective tax
rates for the second quarters of 2008 and 2007 were
49 percent and 41 percent, respectively. For the
comparative
six-month
periods, the effective tax rates were 48 percent and
39 percent, respectively. The 2008 rates in the comparative
periods were higher primarily because a greater proportion of
income was earned in international upstream tax jurisdictions,
which generally have higher income tax rates than other tax
jurisdictions. The 2007 second quarter included a relatively low
effective tax rate on the sale of the company’s investment
in Dynegy common stock. In addition, the 2007 six-month period
included a relatively low effective tax rate on the first
quarter sale of refining-related assets in the Netherlands.
Note 7.
Employee
Benefits
The company has defined-benefit pension plans for many
employees. The company typically prefunds defined-benefit plans
as required by local regulations or in certain situations where
pre-funding provides economic advantages. In the United States,
this includes all qualified plans subject to the Employee
Retirement Income Security Act of 1974 (ERISA) minimum funding
standard. The company does not typically
fund U.S. nonqualified pension plans that are not
subject to funding requirements under applicable laws and
regulations because contributions to these pension plans may be
less economic and investment returns may be less attractive than
the company’s other investment alternatives.
The company also sponsors other postretirement plans that
provide medical and dental benefits, as well as life insurance
for some active and qualifying retired employees. The plans are
unfunded, and the company and the retirees share the costs.
Medical coverage for Medicare-eligible retirees in the
company’s main U.S. medical plan is secondary to
Medicare (including Part D) and the increase to the
company contribution for retiree medical coverage is limited to
no more than 4 percent each year. Certain life insurance
benefits are paid by the company.
13
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The components of net periodic benefit costs for 2008 and 2007
were:
Three Months Ended
Six Months Ended
June 30
June 30
2008
2007
2008
2007
(Millions of dollars)
Pension Benefits
United States
Service cost
$
62
$
65
$
125
$
130
Interest cost
124
121
249
242
Expected return on plan assets
(148
)
(145
)
(296
)
(289
)
Amortization of prior-service costs
(2
)
11
(4
)
23
Amortization of actuarial losses
15
32
30
64
Settlement losses
20
21
39
41
Total United States
71
105
143
211
International
Service cost
35
32
68
62
Interest cost
70
66
143
127
Expected return on plan assets
(63
)
(67
)
(133
)
(130
)
Amortization of prior-service costs
7
4
13
8
Amortization of actuarial losses
17
20
37
40
Curtailment losses
—
3
—
3
Termination costs
1
—
1
—
Total International
67
58
129
110
Net Periodic Pension Benefit Costs
$
138
$
163
$
272
$
321
Other Benefits*
Service cost
$
49
$
24
$
56
$
32
Interest cost
45
47
89
92
Amortization of prior-service costs
(20
)
(20
)
(40
)
(40
)
Amortization of actuarial losses
9
19
19
40
Net Periodic Other Benefit Costs
$
83
$
70
$
124
$
124
*
Includes costs for U.S. and international other postretirement
benefit plans. Obligations for plans outside the U.S. are not
significant relative to the company’s total other
postretirement benefit obligation.
At the end of 2007, the company estimated it would contribute
$500 million to employee pension plans during 2008
(composed of $300 million for the U.S. plans and
$200 million for the international plans). Through
June 30, 2008, a total of $127 million was contributed
(including $61 million to the U.S. plans). Total
estimated contributions for the full year continue to be
$500 million, but the company may contribute an amount that
differs from this estimate. Actual contribution amounts are
dependent upon investment returns, changes in pension
obligations, regulatory environments and other economic factors.
Additional funding may ultimately be required if investment
returns are insufficient to offset increases in plan obligations.
During the first half of 2008, the company contributed
$96 million to its other postretirement benefit plans. The
company anticipates contributing $112 million during the
remainder of 2008.
14
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Note 8.
Accounting
for Suspended Exploratory Wells
The company accounts for the cost of exploratory wells in
accordance with FAS 19, Financial Accounting and
Reporting by Oil and Gas Producing Companies, as amended by
FASB Staff Position
FAS 19-1,
Accounting for Suspended Well Costs, which provides that
an exploratory well continues to be capitalized after the
completion of drilling if certain criteria are met. The
company’s capitalized cost of suspended wells at
June 30, 2008, was $1.84 billion, an increase of
approximately $180 million from year-end 2007 due primarily
to activities in the United States, Nigeria and Australia. For
the category of exploratory well costs at year-end 2007 that
were suspended more than one year, a total of $65 million
was expensed in the first half of 2008.
Note 9.
Litigation
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 89 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 seepage of MTBE
into groundwater. Chevron has agreed in principle to a tentative
settlement of 59 pending lawsuits and claims. The terms of
this agreement which is currently under court review are
confidential and not material to the company’s 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 59 lawsuits
did not set any precedents related to standards of liability to
be used to judge the merits of the claims, corrective measures
required or monetary damages to be assessed for the remaining
lawsuits and claims or future lawsuits and claims. As a result,
the company’s 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 Unocal’s 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 company’s 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.
Ecuador Chevron is a defendant in a civil
lawsuit before the Superior Court of Nueva Loja in Lago Agrio,
Ecuador brought in May 2003 by plaintiffs who claim to be
representatives of certain residents of an area where an oil
production consortium formerly had operations. The lawsuit
alleges damage to the environment from the oil exploration and
production operations, and seeks unspecified damages to fund
environmental remediation and restoration of the alleged
environmental harm, plus a health monitoring program. Until
1992, Texaco Petroleum Company (Texpet), a subsidiary of Texaco
Inc., was a minority member of this consortium with
Petroecuador, the Ecuadorian state-owned oil company, as the
majority partner; since 1990, the operations have been conducted
solely by Petroecuador. At the conclusion of the consortium, and
following an independent third-party environmental audit of the
concession area, Texpet entered into a formal agreement with the
Republic of Ecuador and Petroecuador for Texpet to remediate
specific sites assigned by the government in proportion to
Texpet’s ownership share of the consortium. Pursuant to
that agreement, Texpet conducted a three-year remediation
program at a cost of $40 million. After certifying that the
sites were properly remediated, the government granted
15
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Texpet and all related corporate entities a full release from
any and all environmental liability arising from the consortium
operations.
Based on the history described above, Chevron believes that this
lawsuit lacks legal or factual merit. As to matters of law, the
company believes first, that the court lacks jurisdiction over
Chevron; second, that the law under which plaintiffs bring the
action, enacted in 1999, cannot be applied retroactively to
Chevron; third, that the claims are barred by the statute of
limitations in Ecuador; and, fourth, that the lawsuit is also
barred by the releases from liability previously given to Texpet
by the Republic of Ecuador and Petroecuador. With regard to the
facts, the Company believes that the evidence confirms that
Texpet’s remediation was properly conducted and that the
remaining environmental damage reflects Petroecuador’s
failure to timely fulfill its legal obligations and
Petroecuador’s further conduct since assuming full control
over the operations.
In April 2008, a mining engineer appointed by the court to
identify and determine the cause of environmental damage, and to
specify steps needed to remediate it, issued a report
recommending that the court assess $8 billion, which would,
according to the engineer, provide financial compensation for
purported damages, including wrongful death claims, and pay for,
among other items, environmental remediation, healthcare
systems, and additional infrastructure for Petroecuador. The
engineer’s report also asserts that an additional
$8.3 billion could be assessed against Chevron for unjust
enrichment. The engineer’s report is not binding on the
court. Chevron also believes that the engineer’s work was
performed, and his report prepared, in a manner contrary to law
and in violation of the court’s orders. Chevron intends to
move to strike the report and otherwise continue a vigorous
defense against any attempted imposition of liability.
Management does not believe an estimate of a reasonably possible
loss (or a range of loss) can be made in this case. Due to the
defects associated with the engineer’s report, management
does not believe the report itself has any utility in
calculating a reasonably possible loss (or a range of loss).
Moreover, the highly uncertain legal environment surrounding the
case provides no basis for management to estimate a reasonably
possible loss (or a range of loss).
Note 10.
Other
Contingencies and Commitments
Guarantees The company and its subsidiaries
have certain other contingent liabilities with respect to
guarantees, direct or indirect, of debt of affiliated companies
or third parties. Under the terms of the guarantee arrangements,
generally the company would be required to perform should the
affiliated company or third party fail to fulfill its
obligations under the arrangements. In some cases, the guarantee
arrangements may have recourse provisions that would enable the
company to recover any payments made under the terms of the
guarantees from assets provided as collateral.
Off-Balance-Sheet Obligations The company and
its subsidiaries have certain other contractual obligations
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, storage and regasification capacity, drilling rigs,
utilities and petroleum products, to be used or sold in the
ordinary course of the company’s business.
Indemnifications The company provided certain
indemnities of contingent liabilities of Equilon and Motiva to
Shell and Saudi Refining, Inc., in connection with the February
2002 sale of the company’s interests in those investments.
The company would be required to perform if the indemnified
liabilities become actual losses. Were that to occur, the
company could be required to make future payments up to
$300 million. Through the end of June 2008, the company
paid $48 million under these indemnities and continues to
be obligated for possible additional indemnification payments in
the future.
The company has also provided indemnities relating to contingent
environmental liabilities related to assets originally
contributed by Texaco to the Equilon and Motiva joint ventures
and environmental conditions that existed prior to the formation
of Equilon and Motiva or that occurred during the period of
Texaco’s ownership interest in the joint ventures. In
general, the environmental conditions or events that are subject
to these indemnities must have
16
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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 company’s liability is
unlimited until April 2022, when the liability expires. The
acquirer of the assets sold in 1997 shares in certain
environmental remediation costs up to a maximum obligation of
$200 million, which had not been reached as of
June 30, 2008.
Minority Interests The company has commitments
of $226 million related to minority interests in subsidiary
companies.
Environmental The company is subject to loss
contingencies pursuant to laws, regulations, private claims and
legal proceedings related to environmental matters that are
subject to legal settlements or that in the future may require
the company to take action to correct or ameliorate the effects
on the environment of prior release of chemicals or petroleum
substances, including MTBE, by the company or other parties.
Such contingencies may exist for various sites, including, but
not limited to, federal Superfund sites and analogous sites
under state laws, refineries, crude-oil fields, service
stations, terminals, land development areas, and mining
operations, whether operating, closed or divested. These future
costs are not fully determinable due to such factors as the
unknown magnitude of possible contamination, the unknown timing
and extent of the corrective actions that may be required, the
determination of the company’s liability in proportion to
other responsible parties, and the extent to which such costs
are recoverable from third parties.
Although the company has provided for known environmental
obligations that are probable and reasonably estimable, the
amount of additional future costs may be material to results of
operations in the period in which they are recognized. The
company does not expect these costs will have a material effect
on its consolidated financial position or liquidity. Also, the
company does not believe its obligations to make such
expenditures have had, or will have, any significant impact on
the company’s competitive position relative to other
U.S. or international petroleum or chemical companies.
Chevron’s environmental reserve at December 31, 2007,
was approximately $1.5 billion. At June 30, 2008, the
environmental reserve increased to approximately
$1.9 billion. The increase was mainly associated with
remediation liabilities Chevron has incurred for sites that were
previously sold.
Financial Instruments The company believes it
has no material market or credit risks to its operations,
financial position or liquidity as a result of its commodities
and other derivatives activities, including
forward-exchange
contracts and interest rate swaps.
Equity Redetermination For oil and gas
producing operations, ownership agreements may provide for
periodic reassessments of equity interests in estimated
crude-oil and natural-gas reserves. These activities,
individually or together, may result in gains or losses that
could be material to earnings in any given period. One such
equity redetermination process has been under way since 1996 for
Chevron’s interests in four producing zones at the Naval
Petroleum Reserve at Elk Hills, California, for the time when
the remaining interests in these zones were owned by the
U.S. Department of Energy. A wide range remains for a
possible net settlement amount for the four zones. For this
range of settlement, Chevron estimates its maximum possible net
before-tax liability at approximately $200 million, and the
possible maximum net amount that could be owed to Chevron is
estimated at about $150 million. The timing of the
settlement and the exact amount within this range of estimates
are uncertain.
17
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Other Contingencies Chevron receives claims
from and submits claims to customers; trading partners;
U.S. federal, state and local regulatory bodies;
governments; contractors; insurers; and suppliers. The amounts
of these claims, individually and in the aggregate, may be
significant and take lengthy periods to resolve.
The company and its affiliates also continue to review and
analyze their operations and may close, abandon, sell, exchange,
acquire or restructure assets to achieve operational or
strategic benefits and to improve competitiveness and
profitability. These activities, individually or together, may
result in gains or losses in future periods.
Note 11.
Restructuring
and Reorganization Costs
In 2007, the company implemented a restructuring and
reorganization program in its global downstream operations.
Approximately 1,000 employees were eligible for severance
payments. As of June 30, 2008, approximately
600 employees had been terminated under the program. Most
of the associated positions are located outside of the United
States. The program is expected to be complete by the end of
2009.
Shown in the table below is the activity for the company’s
liability related to the downstream reorganization. The
associated charges against income were categorized as
“Operating expenses” or “Selling, general and
administrative expenses” on the Consolidated Statement of
Income.
The company implemented FASB Statement No. 157, Fair
Value Measurements (FAS 157), as of January 1,2008. FAS 157 was amended in February 2008 by FASB Staff
Position (FSP)
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, and by FSP
FAS 157-2,
Effective Date of FASB Statement No. 157, which
delayed the company’s application of FAS 157 for
nonrecurring nonfinancial assets and liabilities until
January 1, 2009.
Implementation of FAS 157 did not have a material effect on
the company’s results of operations or consolidated
financial position and had no effect on the company’s
existing fair-value measurement practices. However, FAS 157
requires disclosure of a fair-value hierarchy of inputs the
company uses to value an asset or a liability. The three levels
of the fair-value hierarchy are described as follows:
Level 1: Quoted prices (unadjusted) in active markets for
identical assets and liabilities. For the company, Level 1
inputs include exchange-traded futures contracts for which the
parties are willing to transact at the exchange-quoted price and
marketable securities that are actively traded.
Level 2: Inputs other than Level 1 that are
observable, either directly or indirectly. For the company,
Level 2 inputs include quoted prices for similar assets or
liabilities, prices obtained through third-party broker quotes
and prices that can be corroborated with other observable inputs
for substantially the complete term of a contract.
18
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Level 3: Unobservable inputs. The company does not use
Level 3 inputs for any of its recurring fair-value
measurements. Beginning January 1, 2009, Level 3
inputs may be required for the determination of fair value
associated with certain nonrecurring measurements of
nonfinancial assets and liabilities.
The fair value hierarchy for assets and liabilities measured at
fair value at June 30, 2008, is as follows:
Assets
and Liabilities Measured at Fair Value on a Recurring
Basis
Prices in Active
Other
Markets for
Observable
Unobservable
At June 30
Identical Assets
Inputs
Inputs
2008
(Level 1)
(Level 2)
(Level 3)
Marketable Securities
$
427
$
427
$
—
$
—
Derivatives
326
107
219
—
Total Assets at Fair Value
$
753
$
534
$
219
$
—
Derivatives
$
1,105
$
171
$
934
$
—
Total Liabilities at Fair Value
$
1,105
$
171
$
934
$
—
Marketable securitiesThe company calculates
fair value for its marketable securities based on quoted market
prices for identical assets and liabilities.
DerivativesThe company records its derivative
instruments — other than any commodity derivative
contracts that are designated as normal purchase and normal
sale — on the Consolidated Balance Sheet at fair
value, with virtually all the offsetting amount to the
Consolidated Statement of Income. For derivatives with identical
or similar provisions as contracts that are publicly traded on a
regular basis, the company uses the market values of the
publicly traded instruments as an input for fair-value
calculations.
The company’s derivative instruments principally include
crude oil, natural gas and refined-product futures, swaps,
options and forward contracts, as well as interest-rate swaps
and foreign-currency forward contracts. Derivatives classified
as Level 1 include futures, swaps and options contracts
traded in active markets such as the NYMEX (New York Mercantile
Exchange). Level 2 derivatives include swaps (including
interest rate), options, and forward (including foreign
currency) contracts principally with financial institutions and
other oil and gas companies, the fair values for which are
obtained from third party broker quotes, industry pricing
services and exchanges. These Level 2 fair values are
routinely corroborated on a sample basis with observable
market-based inputs.
Note 13.
New
Accounting Standards
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 companyJanuary 1, 2009, with retroactive adoption of
the Statement’s 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 parent’s equity. It will also require the amount of
consolidated net income attributable to the parent and the
19
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
noncontrolling interest to be clearly identified and presented
on the face of the consolidated income statement. Certain
changes in a parent’s 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.
FASB Statement No. 161, Disclosures about Derivative
Instruments and Hedging Activities
(FAS 161) In March 2008, the FASB issued
FAS 161, which becomes effective for the company on
January 1, 2009. This standard amends and expands the
disclosure requirements of FASB Statement No. 133,
Accounting for Derivative Instruments and Hedging
Activities. FAS 161 requires disclosures related to
objectives and strategies for using derivatives; the fair-value
amounts of, and gains and losses on, derivative instruments; and
credit-risk-related contingent features in derivative
agreements. The effect on the company’s disclosures for
derivative instruments as a result of the adoption of
FAS 161 in 2009 will depend on the company’s
derivative instruments and hedging activities at that time.
20
Item 2.
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
Second
Quarter 2008 Compared with Second Quarter 2007
and Six Months 2008 Compared with Six Months 2007
Key
Financial Results
Income by
Business Segment
Three Months Ended
Six Months Ended
June 30
June 30
2008
2007
2008
2007
(Millions of dollars)
Upstream — Exploration and Production
United States
$
2,191
$
1,223
$
3,790
$
2,019
International
5,057
2,416
8,586
4,527
Total Upstream
7,248
3,639
12,376
6,546
Downstream — Refining, Marketing and
Transportation
United States
(682
)
781
(678
)
1,131
International
(52
)
517
196
1,790
Total Downstream
(734
)
1,298
(482
)
2,921
Chemicals
41
104
84
224
Total Segment Income
6,555
5,041
11,978
9,691
All Other
(580
)
339
(835
)
404
Net Income*
$
5,975
$
5,380
$
11,143
$
10,095
* Includes foreign currency effects
$
126
$
(138
)
$
81
$
(258
)
Net income for the second quarter 2008 was
$6.0 billion ($2.90 per share — diluted),
compared with $5.4 billion ($2.52 per share —
diluted) in the corresponding 2007 period. Net income for the
first six months of 2008 was $11.1 billion ($5.38 per
share — diluted), vs. $10.1 billion ($4.70 per
share — diluted) in the 2007 first half. In the
following discussion, the term “earnings” is defined
as segment income.
Upstream earnings in the second quarter of 2008 were
$7.2 billion, compared with $3.6 billion in the
year-ago period. Earnings for the first half of 2008 were
$12.4 billion, vs. $6.5 billion a year earlier. The
increase between both comparative periods was driven by higher
prices for crude oil and natural gas.
Downstream incurred a loss of $734 million in the
second quarter of 2008, compared with earnings of
$1.3 billion a year earlier. For the six-month periods, a
loss of $482 million was recorded in 2008 versus earnings
of $2.9 billion in 2007. The 2007 first half included an
approximate $700 million gain on the first-quarter sale of
the company’s interest in a refinery and related assets in
the Netherlands. The losses in the 2008 periods were associated
mainly with market conditions that prevented the higher price of
crude-oil feedstocks used in the refining process from being
fully recovered in the sales price of gasoline and other refined
products.
Chemicals earned $41 million and $84 million
for the second quarter and first-half 2008, respectively.
Comparative amounts in 2007 were $104 million and
$224 million.
Refer to pages 25 to 27 for additional discussion of earnings by
business segment and “All Other” activities for the
second quarter and first six months of 2008 versus the same
periods in 2007.
Business
Environment and Outlook
Chevron is a global energy company with its most significant
business activities in the following countries: Angola,
Argentina, Australia, Azerbaijan, Bangladesh, Brazil, Cambodia,
Canada, Chad, China, Colombia,
21
Democratic Republic of the Congo, Denmark, France, India,
Indonesia, Kazakhstan, Myanmar, the Netherlands, Nigeria,
Norway, the Partitioned Neutral Zone between Kuwait and Saudi
Arabia, 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.
Chevron’s current and future earnings depend largely on the
profitability of its upstream (exploration and production) and
downstream (refining, marketing and transportation) business
segments. The single biggest factor that affects the results of
operations for both segments is movement in the price of crude
oil. In the downstream business, crude oil is the largest cost
component of refined products. The overall trend in earnings is
typically less affected by results from the company’s
chemicals business and other activities and investments.
Earnings for the company in any period may also be influenced by
events or transactions that are infrequent
and/or
unusual in nature.
Chevron and the oil and gas industry at large 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 company’s operating expenses for all
business segments and capital expenditures, but particularly for
the upstream business. The company’s operations,
particularly upstream, can also be affected by changing
economic, regulatory and political environments in the various
countries in which it operates, including the United States.
Civil unrest, acts of violence or strained relations between a
government and the company or other governments may impact the
company’s operations or investments. Those developments
have at times significantly affected the company’s related
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 and taxes on the company. Other
governments may attempt to do so in the future. The company will
continue to monitor these developments, take them into account
in evaluating future investment opportunities, and otherwise
seek to mitigate any risks to the company’s current
operations or future prospects.
The company also continually evaluates opportunities to dispose
of assets that are not key to providing sufficient long-term
value, or to acquire assets or operations complementary to its
asset base to help augment the company’s growth. Asset
dispositions and restructurings may occur in future periods and
could result in significant gains or losses.
Comments related to earnings trends for the company’s major
business areas are as follows:
Upstream Earnings for the upstream segment are
closely aligned with industry price levels for crude oil and
natural gas. Crude-oil and natural-gas prices are subject to
external factors over which the company has no control,
including product demand connected with global economic
conditions, industry inventory levels, production quotas imposed
by the Organization of Petroleum Exporting Countries (OPEC),
weather-related damage and disruptions, competing fuel prices,
and regional supply interruptions or fears thereof that may be
caused by military conflicts, civil unrest or political
uncertainty. Moreover, any of these factors could also inhibit
the company’s production capacity in an affected region.
The company monitors developments closely in the countries in
which it operates and holds investments, and attempts to manage
risks in operating its facilities and business.
Price levels for capital and exploratory costs and operating
expenses associated with the efficient production of crude-oil
and natural-gas can also be subject to external factors beyond
the company’s control. External factors include not only
the general level of inflation but also prices charged by the
industry’s material- and
service-providers,
which can be affected by the volatility of the industry’s
own supply and demand conditions for such materials and
services. 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.
22
During 2007, industry price levels for West Texas Intermediate
(WTI), a benchmark crude oil, averaged $72 per barrel. The
price for WTI averaged $111 per barrel for the first half of
2008 and was about $124 per barrel at the end of July. Worldwide
crude oil prices have remained strong due mainly 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 in 2007, a wide differential in prices existed during the
first half of 2008 between high-quality
(high-gravity,
low sulfur) crude oils and those of lower quality (low-gravity,
high sulfur). The relatively lower price for the heavier crudes
has been associated with an ample supply and a relatively lower
demand due to the limited number of refineries that are able to
process this lower-quality feedstock into light products (motor
gasoline, jet fuel, aviation gasoline and diesel fuel). The
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 in
certain fields in Angola, China and the United Kingdom North
Sea. (Refer to page 30 for the company’s average
U.S. and international crude-oil realizations.)
In contrast to price movements in the global market for crude
oil, price changes for natural gas in many regional markets are
more closely aligned with supply and demand conditions in those
markets. In the United States, benchmark prices at Henry
Hub averaged nearly $10 per thousand cubic feet (MCF) in the
first half of 2008, compared with $7.40 for the first half of
2007 and about $7 for the full year 2007. At the end of July
2008, the Henry Hub spot price was approximately $9 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.
Certain other regions of the world in which the company operates
have different supply, demand and regulatory circumstances,
typically resulting in significantly lower average sales prices
for the company’s production of natural gas. (Refer to
page 30 for the company’s average natural gas
realizations for the U.S. and international regions.)
Additionally, excess-supply conditions that exist in certain
parts of the world cannot easily serve to mitigate the
relatively high-price conditions in the United States and other
markets because of the lack of infrastructure to transport and
receive liquefied natural gas.
To help address this regional imbalance between supply and
demand for natural gas, Chevron is planning increased
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 prices for crude oil
and natural gas, the longer-term trend in earnings for the
upstream segment is also a function of other factors, including
the company’s ability to find or acquire and efficiently
produce crude oil and natural gas, changes in fiscal terms of
contracts, changes in tax rates on income, and the cost of goods
and services.
In the first half of 2008, the company’s worldwide
oil-equivalent production averaged approximately
2.57 million barrels per day. At the beginning of 2008, the
company estimated production for the full year at
2.65 million barrels per day under a set of crude-oil and
natural-gas price assumptions for the year. Actual crude-oil
prices in the 2008 first half were higher than the prices used
in the production forecast, and the impact of these higher
prices reduced the anticipated volumes recoverable under certain
production-sharing and variable-royalty agreements outside the
United States. This difference in recovered volumes accounted
for most of the variation between the first half of 2008 actual
reported rate of production and the full-year forecast. The
full-year production outlook is also subject to other factors
and many uncertainties, including quotas that may be imposed by
OPEC, changes in fiscal terms or restrictions on the scope of
company operations, delays in project
start-ups,
and production disruptions that could be caused by severe
weather, local civil unrest and changing geopolitics. Future
23
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. A significant majority of
Chevron’s upstream investment is currently being made
outside the United States. Investments in upstream projects
generally begin well in advance of the start of the associated
crude-oil and natural-gas production. For example, the
company’s recently announced startup of the
68 percent-owned deepwater Agbami project in Nigeria was
associated with a 1998 crude-oil discovery. The total maximum
oil-equivalent production at Agbami is estimated at
250,000 barrels per day by the end of 2009.
About one-fourth of the company’s net oil-equivalent
production in the first half of 2008 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 Chevron’s production
level in 2007 or in the first half of 2008. The impact of quotas
on the company’s production in future periods is uncertain.
Refer to the Results of Operations on pages 25 through 26 for
additional discussion of the company’s upstream business.
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 company’s
refining and marketing network, the effectiveness of the
crude-oil and product-supply functions and the economic returns
on invested capital. Profitability can also be affected by the
volatility of tanker-charter rates for the company’s
shipping operations, which are driven by the industry’s
demand for crude-oil and product tankers. Other factors beyond
the company’s control include the general level of
inflation and energy costs to operate the company’s
refinery and distribution network.
The company’s most significant marketing areas are the West
Coast of North America, the U.S. Gulf Coast, Latin America,
Asia, sub-Saharan Africa and the United Kingdom. Chevron
operates or has ownership interests in refineries in each of
these areas, except Latin America. Downstream earnings,
especially in the United States, have been weak since mid-2007
due mainly to increasing prices of crude oil used in the
refining process that have not always been fully recovered
through sales prices of refined products.
Refer to the Results of Operations on pages 26 through 27 for
additional discussion of the company’s downstream
operations.
Chemicals Earnings in the petrochemicals
business are closely tied to global chemical demand, industry
inventory levels and plant capacity utilization. Feedstock and
fuel costs, which tend to follow crude-oil and natural-gas price
movements, also influence earnings in this segment.
Refer to the Results of Operations on page 27 for
additional discussion of chemical earnings.
Results
of Operations
Business Segments The following section
presents the results of operations for the company’s
business segments — upstream, downstream and
chemicals — as well as for “all
other” — the departments and companies managed at
the corporate level. (Refer to Note 3 beginning on
page 8 for a discussion of the company’s
“reportable segments,” as defined in FAS 131,
Disclosures about Segments of an Enterprise and Related
Information.)
24
Upstream
Three Months Ended
Six Months Ended
June 30
June 30
2008
2007
2008
2007
(Millions of dollars)
U.S. Upstream Income
$
2,191
$
1,223
$
3,790
$
2,019
U.S. upstream income of $2.2 billion in the second
quarter of 2008 increased nearly $1 billion from the same
period last year. Higher prices for crude oil and natural gas
benefited earnings by about $1.6 billion between periods.
Partially offsetting this benefit were an increase in operating
expenses, the impact of lower production and the absence of
gains on asset sales.
Six-month 2008 earnings were $3.8 billion, compared with
$2 billion a year earlier. Higher prices for crude oil and
natural gas increased earnings by about $2.7 billion
between periods. Partially offsetting this benefit were the same
factors as mentioned above for the fluctuation in earnings
between the quarterly periods.
The average realization for crude oil and natural gas liquids in
the second quarter of 2008 was $109 per barrel, compared with
$57 a year earlier. Six-month prices were $98 and $54 for 2008
and 2007, respectively. The average natural-gas realization was
$9.84 per thousand cubic feet in the 2008 quarter, compared with
$6.56 in the year-ago period. First-half realizations were $8.67
in 2008 and $6.48 in 2007.
Net oil-equivalent production was 702,000 barrels per day
in the second quarter 2008, down 50,000 barrels per day
from the corresponding period in 2007. First-half production was
708,000 barrels per day, down 42,000 barrels per day
from the first six months of 2007. The lower production in 2008
for both comparative periods was associated with normal field
declines. The net liquids component of oil-equivalent production
decreased by 6 percent for both the quarter and first half,
to 438,000 barrels per day and 437,000, respectively. Net
natural gas production averaged 1.6 billion cubic feet per
day for both the second quarter and six months of 2008, down
about 7 percent and 5 percent, respectively, from the
comparative 2007 periods.
Three Months Ended
Six Months Ended
June 30
June 30
2008
2007
2008
2007
(Millions of dollars)
International Upstream Income*
$
5,057
$
2,416
$
8,586
$
4,527
* Includes foreign currency effects
$
80
$
(111
)
$
(87
)
$
(230
)
International upstream income of $5.1 billion in the second
quarter of 2008 increased $2.6 billion from a year earlier.
Higher prices for crude oil and natural gas benefited earnings
about $2.7 billion between periods. Partially offsetting
the benefit of higher prices was a reduction of crude-oil sales
volumes. Foreign currency effects benefited earnings by
$80 million in the 2008 quarter, compared with a
$111 million reduction to income a year earlier.
For the six-month period, earnings were $8.6 billion, up
about $4.1 billion from the 2007 period. Higher prices for
crude oil and natural gas in 2008 increased earnings by about
$4.6 billion. Partially offsetting the benefit of higher
prices was a reduction of crude-oil sales volumes, as well as
higher operating and depreciation expenses. Foreign currency
effects reduced income by $87 million in 2008, compared
with a $230 million reduction to earnings a year earlier.
The average realization for crude oil and natural gas liquids
the second quarter 2008 was about $110 per barrel, versus $61 in
the 2007 period. For the first half of 2008, the average
realization was $99 per barrel, compared with $56 for the six
months of 2007. The average natural-gas realization in the 2008
second quarter was $5.44 per thousand cubic feet, up from $3.64
in the second quarter last year. Between the six-month periods,
the average natural gas realization increased to $5.13 from
$3.74.
Net oil-equivalent production, including volumes from oil sands
in Canada, was 1.84 million barrels per day in the second
quarter 2008, down 43,000 barrels per day from the year-ago
period. Production for the first half of 2008 was
1.86 million barrels per day, down 27,000 from the 2007
first half. Absent the impact of higher prices on certain
production-sharing and variable-royalty agreements, net
production increased between both comparative periods.
25
The net liquids component of oil-equivalent production was
1.23 million barrels per day and 1.24 million barrels
per day for the second quarter and first half of 2008,
respectively. Each was about 7 percent lower than the
corresponding 2007 period. Net natural gas production of
3.62 billion cubic feet per day in the second quarter 2008
and 3.70 billion cubic feet per day in first half of 2008
increased 9 percent and 12 percent, respectively from
the year-earlier periods.
Downstream
Three Months Ended
Six Months Ended
June 30
June 30
2008
2007
2008
2007
(Millions of dollars)
U.S. Downstream (Loss) Income
$
(682
)
$
781
$
(678
)
$
1,131
U.S. downstream incurred a loss of $682 million in the
second quarter of 2008 and a loss of $678 million in the
first half of the year. In 2007, income of $781 million and
$1.1 billion was recorded in the second quarter and
first-half
periods. The losses for both periods in 2008 were associated
with higher costs of crude-oil feedstocks used in the refining
process that were not fully recovered in the sales price of
gasoline and other refined products. The losses in both periods
also included mark-to-market accounting effects of commodity
derivative instruments.
Crude-oil inputs to the company’s refineries were
816,000 barrels per day in the second quarter of 2008, down
about 7 percent from a year earlier. The decline was
primarily due to the effects of a planned turnaround at the
company’s refinery in Pascagoula, Mississippi, and
suspension of crude processing for asphalt production at the
refinery in Perth Amboy, New Jersey. Crude-oil inputs of
855,000 barrels per day in the first half of 2008 increased
about 6 percent from the 2007 six-month period as a result
of less downtime for refinery turnarounds.
Refined-product sales volumes of 1.38 million barrels per
day in the 2008 second quarter were down 8 percent from the
corresponding 2007 quarter due primarily to reduced sales of
gasoline and gas oils. Branded gasoline sales of
596,000 barrels per day were 5 percent lower. For the
six months of 2008, refined-product sales volumes of
1.41 million barrels per day were 5 percent lower than
the 2007 first half due to reduced demand for gasoline.
Three Months Ended
Six Months Ended
June 30
June 30
2008
2007
2008
2007
(Millions of dollars)
International Downstream (Loss) Income*
$
(52
)
$
517
$
196
$
1,790
* Includes foreign currency effects
$
46
$
(35
)
$
157
$
(30
)
International downstream incurred a loss of $52 million in
the second quarter of 2008, compared with income of
$517 million in the corresponding 2007 period. Earnings for
the six months of 2008 were $196 million, down nearly
$1.6 billion from the 2007 first-half, which included a
$700 million gain recorded in the first quarter on the sale
of the company’s interest in a refinery and related assets
in the Netherlands. The decline in earnings otherwise between
the comparative periods was primarily associated with higher
costs of crude-oil feedstocks used in the refining process that
were not fully recovered in the sales price of gasoline and
other refined products. The decline in earnings for both
comparative periods also included the mark-to-market accounting
effects of commodity derivative instruments. Foreign currency
effects increased 2008 income for the second quarter and first
half of 2008 by $46 million and $157 million,
respectively. In 2007, foreign currency effects reduced earnings
$35 million and $30 million in the comparative periods.
The company’s share of refinery crude-oil inputs were
952,000 barrels per day in the second quarter of 2008, up
about 1 percent from the year-ago period. Increased volumes
at the GS Caltex affiliate’s refinery in South Korea and
the company’s refinery in Cape Town, South Africa, were
partially offset due to unplanned shutdowns at the
company’s Pembroke refinery in the United Kingdom. For the
six-month period, crude-oil inputs were 960,000 barrels per
day, down 5 percent due to the sale of the company’s
interest in a Netherlands refinery.
26
Total refined-product sales volumes of 2.07 million barrels
per day in the 2008 quarter were 6 percent higher than last
year’s corresponding period. Excluding the impact of the
2007 asset sales in Europe, sales volumes were up 8 percent
between periods on increased trading activity. Between the
six-month periods, refined-product sales of 2.06 million
barrels per day increased by about 2 percent.
Chemicals
Three Months Ended
Six Months Ended
June 30
June 30
2008
2007
2008
2007
(Millions of dollars)
Income*
$
41
$
104
$
84
$
224
* Includes foreign currency effects
$
1
$
—
$
—
$
(1
)
Chemical operations earned $41 million in the second
quarter 2008, compared with $104 million in the 2007
period. For the six months, earnings decreased from
$224 million in 2007 to $84 million in 2008. Reduced
earnings for both comparative periods were associated with lower
margins on sales of lubricant and fuel additives by the
company’s Oronite subsidiary and on sales of commodity
chemicals by the 50 percent-owned Chevron Phillips Chemical
Company LLC (CPChem). The reduced margins reflected higher costs
of feedstocks that could not be fully recovered in product sales
prices. Also contributing to the lower earnings between periods
were higher utility costs associated with the manufacturing
process and increased maintenance expenses for the planned
shutdowns at various U.S. manufacturing facilities.
All
Other
Three Months Ended
Six Months Ended
June 30
June 30
2008
2007
2008
2007
(Millions of dollars)
(Charges) Income — Net*
$
(580
)
$
339
$
(835
)
$
404
* Includes foreign currency effects
$
(1
)
$
8
$
11
$
3
All Other includes mining operations, power generation
businesses, worldwide cash management and debt financing
activities, corporate administrative functions, insurance
operations, real estate activities, alternative fuels and
technology companies, and the company’s interest in Dynegy
prior to its sale in May 2007.
Net charges in the second quarter of 2008 were
$580 million, compared with income of $339 million in
the same quarter of 2007. For the six months of 2008, net
charges were $835 million, compared with income of
$404 million a year earlier. The 2007 periods included a
gain of $680 million related to the sale of the
company’s investment in Dynegy common stock, a loss of
approximately $160 million associated with the early
redemption of Texaco Capital Inc. bonds and net favorable tax
items. Results in 2008 included net unfavorable corporate tax
items and increased costs of environmental remediation for sites
that previously had been closed or sold.
Consolidated
Statement of Income
Explanations of variations between periods for certain income
statement categories are provided below:
Three Months Ended
Six Months Ended
June 30
June 30
2008
2007
2008
2007
(Millions of dollars)
Sales and other operating revenues
$
80,962
$
54,344
$
145,621
$
100,646
27
Sales and other operating revenues in the second quarter of 2008
increased $27 billion from a year earlier due to higher
prices for crude oil, natural gas, natural gas liquids and
refined products. Between the six-month periods, sales and other
operating revenues increased $45 billion due to higher
prices.
Three Months Ended
Six Months Ended
June 30
June 30
2008
2007
2008
2007
(Millions of dollars)
Income from equity affiliates
$
1,563
$
894
$
2,807
$
1,831
Income from equity affiliates increased for the quarterly and
six-month periods due mainly to higher upstream-related earnings
from Tengizchevroil in Kazakhstan.
Three Months Ended
Six Months Ended
June 30
June 30
2008
2007
2008
2007
(Millions of dollars)
Other income
$
464
$
856
$
507
$
1,844
Other income for the quarterly period in 2008 decreased due to
the absence of a $680 million gain last year on the sale of
the company’s investment in Dynegy. Also contributing to
the decrease in the six-month period was the absence of a
$780 million before-tax gain on the sale of the
company’s 31 percent interest in a refinery and
related assets in the Netherlands. These gains were partially
offset by a $224 million before-tax loss on the redemption
of debt in 2007.
Three Months Ended
Six Months Ended
June 30
June 30
2008
2007
2008
2007
(Millions of dollars)
Purchased crude oil and products
$
56,056
$
33,138
$
98,584
$
61,265
Purchases increased $23 billion and $37 billion in the
quarterly and six-month periods due to higher prices for crude
oil, natural gas and refined products.
Three Months Ended
Six Months Ended
June 30
June 30
2008
2007
2008
2007
(Millions of dollars)
Operating, selling, general and administrative expenses
$
6,887
$
5,640
$
12,689
$
10,384
Operating, selling, general and administrative expenses
increased approximately $1.2 billion between the quarterly
periods. The categories of expense with the largest increases
were employee and contract labor — $384 million
and environmental remediation — $187 million.
Other categories of expense increased less than
$150 million each.
Between the six-month periods, total expenses increased
approximately $2.3 billion. The categories of expense with
the largest increases were employee and contract
labor — $699 million, environmental
remediation — $327 million, and equipment
rental — $219 million. Other categories of
expense increased less than $200 million each.
Three Months Ended
Six Months Ended
June 30
June 30
2008
2007
2008
2007
(Millions of dollars)
Exploration expenses
$
307
$
273
$
560
$
579
Exploration expenses in the 2008 second quarter increased due to
higher amounts for well write-offs and geological and
geophysical costs. The decrease in the six-month period related
to lower amounts for well write-offs in the 2008 first quarter.
28
Three Months Ended
Six Months Ended
June 30
June 30
2008
2007
2008
2007
(Millions of dollars)
Depreciation, depletion and amortization
$
2,275
$
2,156
$
4,490
$
4,119
The increase in both comparative periods was associated with
higher depreciation rates for certain oil and gas producing
fields, reflecting completion of higher-cost development
projects and asset retirement obligations.
Three Months Ended
Six Months Ended
June 30
June 30
2008
2007
2008
2007
(Millions of dollars)
Taxes other than on income
$
5,699
$
5,743
$
11,142
$
11,168
Taxes other than on income was relatively unchanged from the
2007 periods.
Three Months Ended
Six Months Ended
June 30
June 30
2008
2007
2008
2007
(Millions of dollars)
Interest and debt expense
$
—
$
63
$
—
$
137
Interest and debt expense was zero in 2008 due to all
interest-related amounts being capitalized.
Three Months Ended
Six Months Ended
June 30
June 30
2008
2007
2008
2007
(Millions of dollars)
Income tax expense
$
5,756
$
3,682
$
10,265
$
6,527
Effective income tax rates for the 2008 and 2007 second quarters
were 49 percent and 41 percent, respectively. For the
year-to-date periods, the effective tax rates were 48 and
39 percent, respectively. The higher rates in 2008 were due
to a greater proportion of income being earned in international
upstream tax jurisdictions, which generally have higher income
tax rates than other tax jurisdictions. The 2007 second quarter
included a relatively low effective tax rate on the sale of the
company’s investment in Dynegy common stock. In addition,
the 2007 six-month period included a relatively low effective
tax rate on the first-quarter sale of refining-related assets in
the Netherlands.
29
Selected
Operating Data
The following table presents a comparison of selected operating
data:
Selected
Operating Data(1)(2)
Three Months Ended
Six Months Ended
June 30
June 30
2008
2007
2008
2007
U.S. Upstream
Net crude-oil and natural-gas-liquids production (MBPD)
438
468
437
464
Net natural-gas production (MMCFPD)(3)
1,588
1,703
1,627
1,713
Net oil-equivalent production (MBOEPD)
702
752
708
750
Sales of natural gas (MMCFPD)
7,631
8,153
7,817
8,004
Sales of natural gas liquids (MBPD)
167
170
156
155
Revenue from net production
Crude oil and natural gas liquids ($/Bbl.)
$
108.67
$
57.27
$
97.66
$
53.64
Natural gas ($/MCF)
$
9.84
$
6.56
$
8.67
$
6.48
International Upstream
Net crude-oil and natural-gas-liquids production (MBPD)
1,207
1,297
1,218
1,307
Net natural-gas production (MMCFPD)(3)
3,621
3,314
3,695
3,293
Net oil-equivalent production (MBOEPD)(4)
1,835
1,878
1,860
1,887
Sales of natural gas (MMCFPD)
4,205
3,839
4,190
3,865
Sales of natural gas liquids (MBPD)(5)
127
123
131
116
Revenue from liftings
Crude oil and natural gas liquids ($/Bbl.)
$
110.44
$
61.32
$
98.63
$
56.33
Natural gas ($/MCF)
$
5.44
$
3.64
$
5.13
$
3.74
U.S. and International Upstream
Total net oil-equivalent production, including volumes from oil
sands (MBOEPD)(3)(4)
2,537
2,630
2,568
2,637
U.S. Downstream
Gasoline sales (MBPD)(6)
677
741
687
735
Sales of other refined products(MBPD)
706
765
721
742
Total
1,383
1,506
1,408
1,477
Refinery input (MBPD)
816
881
855
805
International Downstream
Gasoline sales (MBPD)(6)
512
458
507
466
Sales of other refined products (MBPD)
1,043
1,034
1,048
1,074
Share of affiliate sales (MBPD)
511
464
504
469
Total
2,066
1,956
2,059
2,009
Refinery input (MBPD)
952
942
960
1,006
(1) Includes company share of equity affiliates.
(2) MBPD — thousands of barrels per day;
MMCFPD — millions of cubic feet per day;
Bbl. — Barrel; MCF — thousands of cubic
feet; oil-equivalent gas (OEG) conversion ratio is 6,000 cubic
feet of natural gas = 1 barrel of crude oil;
MBOEPD — thousands of barrels of oil-equivalent per
day.
(3) Includes natural gas consumed in operations (MMCFPD):
United States
69
52
80
60
International
424
411
454
420
(4) Includes production from oil sands — net
(MBPD):
24
29
26
31
(5) 2007 conformed to 2008 presentation.
(6) Includes branded and unbranded gasoline.
30
Liquidity
and Capital Resources
Cash and cash equivalents and marketable securities
totaled $8.6 billion at June 30, 2008, up
$500 million from year-end 2007. Cash provided by operating
activities in the first half of 2008 was $15.3 billion, an
amount sufficient to fund the company’s capital and
exploratory program, dividend payments and repurchases of common
stock.
DividendsThe company paid dividends of
$2.5 billion to common stockholders during the first six
months of 2008. In April 2008, the company increased its
quarterly dividend by 12.1 percent to 65 cents per share.
Debt and Capital Lease and Minority Interest
Obligations Chevron’s total debt and capital
lease obligations were $6.7 billion at June 30, 2008,
down from $7.2 billion at December 31, 2007. The
decline was associated with $750 million of Chevron Canada
Funding Company bonds that matured in February 2008. The company
also had minority interest obligations of $226 million at
June 30, 2008.
The company’s debt and capital lease obligations due within
one year, consisting primarily of commercial paper and the
current portion of long-term debt, totaled $5.5 billion at
June 30, 2008, and December 31, 2007. Of these
amounts, $4.6 billion and $4.4 billion were
reclassified to long-term at the end of each period,
respectively. At June 30, 2008, settlement of these
obligations was not expected to require the use of working
capital within one year, as the company had the intent and the
ability, as evidenced by committed credit facilities, to
refinance them on a long-term basis.
At June 30, 2008, the company had $5 billion in
committed credit facilities with various major banks, which
permit the refinancing of short-term obligations on a long-term
basis. These facilities support commercial paper borrowing and
also can be used for general corporate purposes. The
company’s practice has been to continually replace expiring
commitments with new commitments on substantially the same
terms, maintaining levels management believes appropriate. Any
borrowings under the facilities would be unsecured indebtedness
at interest rates based on London Interbank Offered Rate or an
average of base lending rates published by specified banks and
on terms reflecting the company’s strong credit rating. No
borrowings were outstanding under these facilities at
June 30, 2008. In addition, the company has an automatic
shelf registration statement that expires in March 2010 for an
unspecified amount of non-convertible debt securities issued or
guaranteed by the company.
The company has outstanding public bonds issued by Chevron
Corporation Profit Sharing/Savings Plan Trust Fund, Texaco
Capital Inc. and Union Oil Company of California. All of these
securities are guaranteed by Chevron Corporation and are rated
AA by Standard and Poor’s Corporation and Aa1 by
Moody’s Investors Service. The company’s
U.S. commercial paper is rated
A-1+ by
Standard and Poor’s and
P-1 by
Moody’s. All of these ratings denote high-quality,
investment-grade securities.
The company’s future debt level is dependent primarily on
results of operations, the capital-spending program and cash
that may be generated from asset dispositions. The company
believes that it has substantial borrowing capacity to meet
unanticipated cash requirements and that during periods of low
prices for crude oil and natural gas and narrow margins for
refined products and commodity chemicals, it has the flexibility
to increase borrowings
and/or
modify capital-spending plans to continue paying the common
stock dividend and maintain the company’s high-quality debt
ratings.
Common Stock Repurchase Program In September
2007, the company authorized the acquisition of up to
$15 billion of its common shares 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. The company acquired
20.5 million shares in the open market for
$2.0 billion during the second quarter of 2008. From the
inception of the program in September 2007 through July 2008,
the company had purchased 70.2 million shares for
approximately $6.4 billion.
Current Ratio — current assets divided by
current liabilities. The current ratio was 1.2 at June 30,2008, and at December 31, 2007. The current ratio is
adversely affected by the valuation of Chevron’s
inventories on a LIFO basis. At December 31, 2007, the book
value of inventory was approximately $7 billion lower than
replacement
31
costs, based on average acquisition costs during the year. The
company does not consider its inventory valuation methodology to
affect liquidity.
Debt Ratio — total debt as a percentage of
total debt plus equity. This ratio was 7.5 percent at
June 30, 2008, and 8.6 percent at year-end 2007,
respectively.
Pension Obligations At the end of 2007, the
company estimated it would contribute $500 million to
employee pension plans during 2008 (composed of
$300 million for the U.S. plans and $200 million
for the international plans). Through June 30, 2008, a
total of $127 million was contributed (including
$61 million to the U.S. plans). Total estimated
contributions for the full year continue to be
$500 million, but the company may contribute an amount that
differs from this estimate. Actual contribution amounts are
dependent upon investment returns, changes in pension
obligations, regulatory environments and other economic factors.
Additional funding may ultimately be required if investment
returns are insufficient to offset increases in plan obligations.
Capital and Exploratory Expenditures Total
expenditures, including the company’s share of spending by
affiliates, were $10.3 billion in the first six months of
2008, compared with $8.6 billion in the corresponding 2007
period. The amounts included the company’s share of
equity-affiliate expenditures of $900 million and
$1.1 billion in the 2008 and 2007 periods, respectively.
Expenditures for upstream projects in 2008 were about
$8.4 billion, representing 82 percent of the
companywide total.
Capital
and Exploratory Expenditures by Major Operating Area
Three Months Ended
Six Months Ended
June 30
June 30
2008
2007
2008
2007
United States
Upstream
$
1,239
$
970
$
2,690
$
1,890
Downstream
528
325
900
558
Chemicals
21
38
127
67
All Other
142
133
265
396
Total United States
1,930
1,466
3,982
2,911
International
Upstream
2,887
2,579
5,723
4,826
Downstream
325
460
554
809
Chemicals
13
11
22
22
All Other
2
—
3
3
Total International
3,227
3,050
6,302
5,660
Worldwide
$
5,157
$
4,516
$
10,284
$
8,571
Contingencies
and Significant Litigation
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 89 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 seepage of MTBE
into groundwater. Chevron has agreed in principle to a tentative
settlement of 59 pending lawsuits and claims. The terms of
this agreement which is currently under court review are
confidential and not material to the company’s 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 59 lawsuits
did not set any precedents related to standards of liability to
be used to judge
32
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
company’s 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 Unocal’s 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 company’s 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.
Ecuador Chevron is a defendant in a civil
lawsuit before the Superior Court of Nueva Loja in Lago Agrio,
Ecuador brought in May 2003 by plaintiffs who claim to be
representatives of certain residents of an area where an oil
production consortium formerly had operations. The lawsuit
alleges damage to the environment from the oil exploration and
production operations, and seeks unspecified damages to fund
environmental remediation and restoration of the alleged
environmental harm, plus a health monitoring program. Until
1992, Texaco Petroleum Company (Texpet), a subsidiary of Texaco
Inc., was a minority member of this consortium with
Petroecuador, the Ecuadorian state-owned oil company, as the
majority partner; since 1990, the operations have been conducted
solely by Petroecuador. At the conclusion of the consortium, and
following an independent third-party environmental audit of the
concession area, Texpet entered into a formal agreement with the
Republic of Ecuador and Petroecuador for Texpet to remediate
specific sites assigned by the government in proportion to
Texpet’s ownership share of the consortium. Pursuant to
that agreement, Texpet conducted a three-year remediation
program at a cost of $40 million. After certifying that the
sites were properly remediated, the government granted Texpet
and all related corporate entities a full release from any and
all environmental liability arising from the consortium
operations.
Based on the history described above, Chevron believes that this
lawsuit lacks legal or factual merit. As to matters of law, the
company believes first, that the court lacks jurisdiction over
Chevron; second, that the law under which plaintiffs bring the
action, enacted in 1999, cannot be applied retroactively to
Chevron; third, that the claims are barred by the statute of
limitations in Ecuador; and, fourth, that the lawsuit is also
barred by the releases from liability previously given to Texpet
by the Republic of Ecuador and Petroecuador. With regard to the
facts, the Company believes that the evidence confirms that
Texpet’s remediation was properly conducted and that the
remaining environmental damage reflects Petroecuador’s
failure to timely fulfill its legal obligations and
Petroecuador’s further conduct since assuming full control
over the operations.
In April 2008, a mining engineer appointed by the court to
identify and determine the cause of environmental damage, and to
specify steps needed to remediate it, issued a report
recommending that the court assess $8 billion, which would,
according to the engineer, provide financial compensation for
purported damages, including wrongful death claims, and pay for,
among other items, environmental remediation, healthcare
systems, and additional infrastructure for Petroecuador. The
engineer’s report also asserts that an additional
$8.3 billion could be assessed against Chevron for unjust
enrichment. The engineer’s report is not binding on the
court. Chevron also believes that the engineer’s work was
performed, and his report prepared, in a manner contrary to law
and in violation of the court’s orders. Chevron intends to
move to strike the report and otherwise continue a vigorous
defense against any attempted imposition of liability.
Management does not believe an estimate of a reasonably possible
loss (or a range of loss) can be made in this case. Due to the
defects associated with the engineer’s report, management
does not believe the report itself has any utility in
calculating a reasonably possible loss (or a range of loss).
Moreover, the highly uncertain legal
33
environment surrounding the case provides no basis for
management to estimate a reasonably possible loss (or a range of
loss).
GuaranteesThe company and its subsidiaries
have certain other contingent liabilities with respect to
guarantees, direct or indirect, of debt of affiliated companies
or third parties. Under the terms of the guarantee arrangements,
generally the company would be required to perform should the
affiliated company or third party fail to fulfill its
obligations under the arrangements. In some cases, the guarantee
arrangements may have recourse provisions that would enable the
company to recover any payments made under the terms of the
guarantees from assets provided as collateral.
Off-Balance-Sheet ObligationsThe company and
its subsidiaries have certain other contractual obligations
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, storage and regasification capacity, drilling rigs,
utilities and petroleum products, to be used or sold in the
ordinary course of the company’s business.
IndemnificationsThe company provided certain
indemnities of contingent liabilities of Equilon and Motiva to
Shell and Saudi Refining, Inc., in connection with the February
2002 sale of the company’s interests in those investments.
The company would be required to perform if the indemnified
liabilities become actual losses. Were that to occur, the
company could be required to make future payments up to
$300 million. Through the end of June 2008, the company
paid $48 million under these indemnities and continues to
be obligated for possible additional indemnification payments in
the future.
The company has also provided indemnities relating to contingent
environmental liabilities related to assets originally
contributed by Texaco to the Equilon and Motiva joint ventures
and environmental conditions that existed prior to the formation
of Equilon and Motiva or that occurred during the period of
Texaco’s ownership interest in the joint ventures. In
general, the environmental conditions or events that are subject
to these indemnities must have arisen prior to December 2001.
Claims 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 company’s liability is
unlimited until April 2022, when the liability expires. The
acquirer of the assets sold in 1997 shares in certain
environmental remediation costs up to a maximum obligation of
$200 million, which had not been reached as of
June 30, 2008.
Minority InterestsThe company has commitments
of $226 million related to minority interests in subsidiary
companies.
EnvironmentalThe company is subject to loss
contingencies pursuant to laws, regulations, private claims and
legal proceedings related to environmental matters that are
subject to legal settlements or that in the future may require
the company to take action to correct or ameliorate the effects
on the environment of prior release of chemicals or petroleum
substances, including MTBE, by the company or other parties.
Such contingencies may exist for various sites, including, but
not limited to, federal Superfund sites and analogous sites
under state laws, refineries, crude-oil fields, service
stations, terminals, land development areas, and mining
operations, whether operating, closed or divested. These future
costs are not fully determinable due to such factors as the
unknown magnitude of possible contamination, the unknown timing
and extent of the corrective actions that may be required, the
determination of the company’s liability in proportion to
other responsible parties, and the extent to which such costs
are recoverable from third parties.
34
Although the company has provided for known environmental
obligations that are probable and reasonably estimable, the
amount of additional future costs may be material to results of
operations in the period in which they are recognized. The
company does not expect these costs will have a material effect
on its consolidated financial position or liquidity. Also, the
company does not believe its obligations to make such
expenditures have had, or will have, any significant impact on
the company’s competitive position relative to other
U.S. or international petroleum or chemical companies.
Chevron’s environmental reserve at December 31, 2007,
was approximately $1.5 billion. At June 30, 2008, the
environmental reserve increased to approximately
$1.9 billion. The increase was mainly associated with
remediation liabilities Chevron has incurred for sites that were
previously sold.
Financial InstrumentsThe company believes it
has no material market or credit risks to its operations,
financial position or liquidity as a result of its commodities
and other derivatives activities, including forward-exchange
contracts and interest rate swaps.
Income Taxes Tax positions for Chevron and its
subsidiaries and affiliates are subject to income tax audits by
many tax jurisdictions throughout the world. For the
company’s major tax jurisdictions, examinations of tax
returns for certain prior tax years had not been completed as of
June 30, 2008. For Chevron’s major tax jurisdictions,
the latest years for which income tax examinations had been
finalized were as follows: United States — 2003,
Nigeria — 1994, Angola — 2001 and Saudi
Arabia — 2003.
Settlement of open tax years, as well as tax issues in other
countries where the company conducts its businesses, is not
expected to have a material effect on the consolidated financial
position or liquidity of the company and, in the opinion of
management, adequate provision has been made for income and
franchise taxes for all years under examination or subject to
future examination.
Equity Redetermination For oil and gas
producing operations, ownership agreements may provide for
periodic reassessments of equity interests in estimated
crude-oil and natural-gas reserves. These activities,
individually or together, may result in gains or losses that
could be material to earnings in any given period. One such
equity redetermination process has been under way since 1996 for
Chevron’s interests in four producing zones at the Naval
Petroleum Reserve at Elk Hills, California, for the time when
the remaining interests in these zones were owned by the
U.S. Department of Energy. A wide range remains for a
possible net settlement amount for the four zones. For this
range of settlement, Chevron estimates its maximum possible net
before-tax liability at approximately $200 million, and the
possible maximum net amount that could be owed to Chevron is
estimated at about $150 million. The timing of the
settlement and the exact amount within this range of estimates
are uncertain.
Other Contingencies Chevron receives claims
from and submits claims to customers; trading partners;
U.S. federal, state and local regulatory bodies;
governments; contractors; insurers; and suppliers. The amounts
of these claims, individually and in the aggregate, may be
significant and take lengthy periods to resolve.
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.
New
Accounting Standards
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.
35
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 companyJanuary 1, 2009, with retroactive adoption of
the Statement’s 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 parent’s 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 parent’s 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.
FASB Statement No. 161, Disclosures about Derivative
Instruments and Hedging Activities
(FAS 161) In March 2008, the FASB issued
FAS 161, which becomes effective for the company on
January 1, 2009. This standard amends and expands the
disclosure requirements of FASB Statement No. 133,
Accounting for Derivative Instruments and Hedging
Activities. FAS 161 requires disclosures related to
objectives and strategies for using derivatives; the fair-value
amounts of, and gains and losses on, derivative instruments; and
credit-risk-related contingent features in derivative
agreements. The effect on the company’s disclosures for
derivative instruments as a result of the adoption of
FAS 161 in 2009 will depend on the company’s
derivative instruments and hedging activities at that time.
Item 3.
Quantitative
and Qualitative Disclosures About Market Risk
Information about market risks for the three months ended
June 30, 2008, does not differ materially from that
discussed under Item 7A of Chevron’s 2007 Annual
Report on
Form 10-K/A.
Item 4.
Controls
and Procedures
(a) Evaluation of disclosure controls and procedures
Chevron management has evaluated, with the participation of the
Chief Executive Officer and Chief Financial Officer, the
effectiveness of our disclosure controls and procedures (as
defined in
Rule 13a-15(e)
and
15d-15(e)
under the Securities Exchange Act of 1934) as of the end of
the period covered by this report. Based on this evaluation, the
Chief Executive Officer and Chief Financial Officer concluded
that the company’s disclosure controls and procedures were
effective as of June 30, 2008.
(b) Changes in internal control over financial reporting
During the quarter ended June 30, 2008, there were no
changes in the company’s internal control over financial
reporting that have materially affected, or were reasonably
likely to materially affect, the company’s internal control
over financial reporting.
Chevron is a major fully integrated petroleum company with a
diversified business portfolio, strong balance sheet, and
history of generating sufficient cash to fund capital and
exploratory expenditures and to pay dividends. Nevertheless,
some inherent risks could materially impact the company’s
financial results of operations or financial condition.
Information about risk factors for the three months ended
June 30, 2008, does not differ materially from that set
forth in Part I, Item 1A, of Chevron’s 2007
Annual Report on
Form 10-K/A.
36
Item 2.
Unregistered
Sales of Equity Securities and Use of Proceeds
CHEVRON
CORPORATION
ISSUER
PURCHASES OF EQUITY SECURITIES
Maximum
Total
Total Number of
Number of Shares
Number of
Average
Shares Purchased as
that May Yet Be
Shares
Price Paid
Part of Publicly
Purchased Under
Period
Purchased(1)
per Share
Announced Program
the Program
April 1-30, 2008
3,092,614
88.40
2,760,000
—
May 1-31, 2008
8,671,760
99.27
8,150,000
—
June 1-30, 2008
9,735,675
98.84
9,588,950
—
Total
21,500,049
97.51
20,498,950
(2
)
(1)
Includes 69,885 common shares repurchased during the three-month
period ended June 30, 2008, from company employees for
required personal income tax withholdings on the exercise of the
stock options issued to management and employees under the
company’s long-term incentive plans. Also includes
931,214 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 June 30, 2008.
(2)
In September 2007, the company authorized common 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. Through June 30,2008, $6.1 billion had been expended to repurchase
67,446,969 shares since the common stock repurchase program
began.
Item 4.
Submission
of Matters to a Vote of Security Holders
The following matters were submitted to a vote of stockholders
at the Annual Meeting on May 28, 2008.
Number of Shares
Voted For
Voted Against
Abstain
1. Election of Directors
Samuel H. Armacost
1,743,417,440
44,810,834
31,807,962
Linnet F. Deily
1,713,150,542
75,342,094
31,562,079
Robert E. Denham
1,744,269,018
43,844,360
31,941,339
Robert J. Eaton
1,755,515,473
33,108,822
31,430,421
Sam Ginn
1,754,511,498
33,295,139
32,248,080
Franklyn G. Jenifer
1,754,709,310
33,051,397
32,294,009
James L. Jones
1,765,116,359
22,915,465
32,022,892
Sam Nunn
1,732,544,395
56,199,932
31,291,909
David J. O’Reilly
1,757,764,953
30,689,648
31,581,638
Donald B. Rice
1,762,966,572
25,689,599
31,380,065
Peter J. Robertson
1,760,932,844
28,525,320
30,578,072
Kevin W. Sharer
1,757,173,631
31,496,112
31,384,972
Charles R. Shoemate
1,766,031,875
22,044,298
31,978,542
Ronald D. Sugar
1,766,253,958
22,179,740
31,621,017
Carl Ware
1,766,064,255
22,859,652
31,130,810
37
Number of Shares
Represent Broker
Voted For
Voted Against
Abstain
Non-Votes
2. Ratification of Independent Registered Public Accounting
Firm
1,763,587,543
27,427,886
29,039,287
—
3. Board Proposal to Amend Company’s Restated
Certificate of Incorporation to Increase the Number of
Authorized Shares of Chevron Common Stock
1,692,925,211
95,627,717
31,501,504
—
4. Stockholder Proposal to Adopt Policy to Separate the
CEO/Chairman Positions
213,611,721
1,238,892,898
34,543,318
333,006,780
5. Stockholder Proposal to Adopt Policy and Report on Human
Rights
357,594,229
922,270,421
207,183,571
333,006,496
6. Stockholder Proposal to Report on the Environmental Impact
of Canadian Oil Sands Operations
367,412,563
916,958,818
202,675,856
333,007,480
7. Stockholder Proposal to Adopt Goals and Report on
Greenhouse Gas Emissions
131,853,279
1,133,496,557
221,698,101
333,006,780
8. Stockholder Proposal to Review and Report on Guidelines
for Country Selection
113,077,141
1,162,223,669
211,747,411
333,006,496
9. Stockholder Proposal to Report on Host Country Laws
Pursuant to the Instructions to Exhibits, certain instruments
defining the rights of holders of long-term debt securities of
the company and its consolidated subsidiaries are not filed
because the total amount of securities authorized under any such
instrument does not exceed 10 percent of the total assets
of the corporation and its subsidiaries on a consolidated basis.
A copy of such instrument will be furnished to the Commission
upon request.
(12.1)
Computation of Ratio of Earnings to Fixed Charges
(31.1)
Rule 13a-14(a)/15d-14(a)
Certification by the company’s Chief Executive Officer
(31.2)
Rule 13a-14(a)/15d-14(a)
Certification by the company’s Chief Financial Officer
(32.1)
Section 1350 Certification by the company’s Chief
Executive Officer
(32.2)
Section 1350 Certification by the company’s Chief
Financial Officer
Pursuant to the requirements 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.
Pursuant to the Instructions to Exhibits, certain instruments
defining the rights of holders of long-term debt securities of
the company and its consolidated subsidiaries are not filed
because the total amount of securities authorized under any such
instrument does not exceed 10 percent of the total assets
of the corporation and its subsidiaries on a consolidated basis.
A copy of such instrument will be furnished to the Commission
upon request.
(12.1)*
Computation of Ratio of Earnings to Fixed Charges
(31.1)*
Rule 13a-14(a)/15d-14(a)
Certification by the company’s Chief Executive Officer
(31.2)*
Rule 13a-14(a)/15d-14(a)
Certification by the company’s Chief Financial Officer
(32.1)*
Section 1350 Certification by the company’s Chief
Executive Officer
(32.2)*
Section 1350 Certification by the company’s Chief
Financial Officer
Copies of above exhibits not contained herein are available to
any security holder upon written request to the Corporate
Governance Department, Chevron Corporation, 6001 Bollinger
Canyon Road, San Ramon, California
94583-2324.
40
Dates Referenced Herein and Documents Incorporated by Reference