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<SEC-DOCUMENT>0000093410-01-000015.txt : 20010329
<SEC-HEADER>0000093410-01-000015.hdr.sgml : 20010329
ACCESSION NUMBER: 0000093410-01-000015
CONFORMED SUBMISSION TYPE: 10-K
PUBLIC DOCUMENT COUNT: 19
CONFORMED PERIOD OF REPORT: 20001231
FILED AS OF DATE: 20010328
FILER:
COMPANY DATA:
COMPANY CONFORMED NAME: CHEVRON CORP
CENTRAL INDEX KEY: 0000093410
STANDARD INDUSTRIAL CLASSIFICATION: PETROLEUM REFINING [2911]
IRS NUMBER: 940890210
STATE OF INCORPORATION: DE
FISCAL YEAR END: 1231
FILING VALUES:
FORM TYPE: 10-K
SEC ACT:
SEC FILE NUMBER: 001-00368
FILM NUMBER: 1581910
BUSINESS ADDRESS:
STREET 1: 575 MARKET STREET
CITY: SAN FRANCISCO
STATE: CA
ZIP: 94105
BUSINESS PHONE: 4158947700
MAIL ADDRESS:
STREET 1: 575 MARKET STREET
CITY: SAN FRANCISCO
STATE: CA
ZIP: 94105
FORMER COMPANY:
FORMER CONFORMED NAME: STANDARD OIL CO OF CALIFORNIA
DATE OF NAME CHANGE: 19840705
</SEC-HEADER>
<DOCUMENT>
<TYPE>10-K
<SEQUENCE>1
<FILENAME>0001.txt
<DESCRIPTION>CHEVRON CORPORATION 2000 FORM 10-K
<TEXT>
2000
================================================================================
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
|X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2000
-----------------
OR
|_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
-------- ---------
Commission File Number 1-368-2
---------
Chevron Corporation
(Exact name of registrant as specified in its charter)
Delaware 94-0890210
----------------------- --------------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
575 Market Street, San Francisco, California 94105
------------------------------------------- ----------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (415) 894-7700
--------------
NONE
--------------------------------------------------------------
(Former name or former address, if changed since last report.)
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
Title of Each Class on Which Registered
----------------------------------------- -----------------------
Common stock par value $.75 per share New York Stock Exchange, Inc.
Preferred stock purchase rights Chicago Stock Exchange
Pacific Exchange
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
------ ------
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. |X|
Aggregate market value of the voting stock held by nonaffiliates of the
Registrant
As of February 28, 2001 - $54,753,640,718
Number of Shares of Common Stock outstanding as of
February 28, 2001 - 641,094,523
DOCUMENTS INCORPORATED BY REFERENCE
(To The Extent Indicated Herein)
Notice of Annual Meeting and Proxy Statement Dated March 21, 2001 (in Part III)
================================================================================
<PAGE>
TABLE OF CONTENTS
Item Page No.
- ---- ---------
PART I
1. Business...................................................... 1
(a) General Development of Business....................... 1
(b) Description of Business and Properties................ 3
Capital and Exploratory Expenditures................ 4
Petroleum - Exploration and Production................ 5
Liquids and Natural Gas Production.............. 5
Acreage........................................... 6
Reserves and Contract Obligations................. 7
Development Activities.......................... 8
Exploration Activities.......................... 9
Review of Ongoing Exploration and
Production Activities In Key Areas............. 9
Petroleum - Natural Gas Liquids....................... 14
Petroleum - Refining.................................. 14
Petroleum - Refined Products Marketing................ 15
Petroleum - Transportation............................ 17
Chemicals............................................. 18
Coal.................................................. 18
Electronic Commerce and Technology.................... 19
Research and Environmental Protection................. 19
2. Properties.................................................... 20
3. Legal Proceedings............................................. 20
4. Submission of Matters to a Vote of Security Holders........... 20
Executive Officers of the Registrant.......................... 21
PART II
5. Market for the Registrant's Common Equity
and Related Stockholder Matters............................... 22
6. Selected Financial Data....................................... 22
7. Management's Discussion and Analysis of Financial
Condition and Results of Operations........................... 22
8. Financial Statements.......................................... 22
8. Supplementary Data - Quarterly Results...................... 22
- Oil and Gas Producing Activities....... 22
9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure........................ 22
PART III
10. Directors and Executive Officers of the Registrant............ 23
11. Executive Compensation........................................ 23
12. Security Ownership of Certain Beneficial Owners
and Management............................................... 23
13. Certain Relationships and Related Transactions................ 23
PART IV
14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K.......................................... 23
Schedule II - Valuation and Qualifying Accounts............... 25
<PAGE>
PART I
Item 1. Business
(a) General Development of Business
Summary Description of Chevron
- ------------------------------
Chevron Corporation(1), a Delaware corporation, manages its investments in, and
provides administrative, financial and management support to, U.S. and foreign
subsidiaries and affiliates that engage in fully integrated petroleum
operations, chemicals operations, coal mining and energy services. The company
operates in the United States and approximately 100 other countries. Petroleum
operations consist of exploring for, developing and producing crude oil and
natural gas; refining crude oil into finished petroleum products; marketing
crude oil, natural gas and the many products derived from petroleum; and
transporting crude oil, natural gas and petroleum products by pipelines, marine
vessels, motor equipment and rail car. Chemicals operations include the
manufacture and marketing of commodity petrochemicals, plastics for industrial
uses and fuel and lubricating oil additives.
In this report, exploration and production of crude oil, natural gas liquids and
natural gas may be referred to as "E&P" or "upstream" activities. Refining,
marketing and transportation may be referred to as "RM&T" or "downstream"
activities. A list of the company's major subsidiaries is presented on page E-2
of this Annual Report on Form 10-K. As of December 31, 2000, Chevron had 34,610
employees, 73 percent of whom were employed in U.S. operations. Approximately
5,500, or 22 percent, of the company's U.S. employees are unionized.
- --------------------------------------------------------------------------------
CAUTIONARY STATEMENTS RELEVANT TO FORWARD-LOOKING INFORMATION FOR THE
PURPOSE OF "SAFE HARBOR" PROVISIONS OF THE
PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This annual report on Form 10-K contains forward-looking statements
relating to Chevron's operations that are based on management's current
expectations, estimates and projections about the petroleum and chemicals
industries. Words such as "anticipates," "expects," "intends," "plans,"
"projects," "believes," "seeks," "estimates" 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, are difficult to
predict and could cause actual results to differ from those expressed or
forecasted in the forward-looking statements. Therefore, actual outcomes and
results may differ materially from what is expressed or forecasted in such
forward-looking statements. You 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 factors that could cause actual results to differ materially are
crude oil and natural gas prices; refining margins and marketing margins;
chemicals prices and competitive conditions affecting supply and demand for
aromatics, olefins and additives products; actions of competitors; the
competitiveness of alternate energy sources or product substitutes;
technological developments; inability of the company's joint-venture partners to
fund their share of operations and development activities; potential failure to
achieve expected production from existing and future oil and gas development
projects; potential delays in the development, construction or start-up of
planned projects; the ability to successfully consummate the proposed merger
with Texaco and successfully integrate the operations of both companies;
potential disruption or interruption of the company's production or
manufacturing facilities due to accidents or political events; potential
liability for remedial actions under existing or future environmental
regulations and litigation; significant investment or product changes under
existing or future environmental regulations (including, particularly,
regulations and litigation dealing with gasoline composition and
characteristics); and potential liability resulting from pending or future
litigation. In addition, such statements could be affected by general domestic
and international economic and political conditions. Unpredictable or unknown
factors not discussed herein also could have material adverse effects on
forward-looking statements.
- --------------------------------------------------------------------------------
(1)Incorporated in Delaware in 1926 as Standard Oil Company of California, the
company adopted the name Chevron Corporation in 1984. As used in this report,
the term "Chevron" and such terms as "the company," "the corporation," "our,"
"we," and "us" may refer to Chevron Corporation, one or more of its consolidated
subsidiaries, or to all of them taken as a whole, but unless it is stated
otherwise, does not include "affiliates" of Chevron - i.e., those companies
accounted for by the equity method (generally owned 50 percent or less), or
investments accounted for by the cost method.
As used in this report, the term "Caltex" may refer to the Caltex Group of
companies, any one company of the group, any of their consolidated subsidiaries,
or to all of them taken as a whole, and also includes the "affiliates" of
Caltex.
All of these terms are used for convenience only, and are not intended as a
precise description of any of the separate companies, each of which manages its
own affairs.
-1-
<PAGE>
Overview of Petroleum Industry
- ------------------------------
Petroleum industry operations and profitability are influenced by many factors,
over some of which individual oil and gas companies have little control.
Governmental policies, particularly in the areas of taxation, energy and the
environment, have a significant impact on petroleum activities, regulating where
and how companies conduct their operations and formulate their products and, in
some cases, limiting their profits directly. Prices for crude oil and natural
gas, petroleum products and petrochemicals are determined by supply and demand
for these commodities. OPEC member countries are typically the world's swing
producers of crude oil, and their production levels are a major factor in
determining worldwide supply. Demand for crude oil and its products and natural
gas is largely driven by the condition of local, national and worldwide
economies, although weather patterns and taxation relative to other energy
sources also play a significant part. Natural gas is generally produced and
consumed on a country or regional basis.
Operating Environment
- ---------------------
Refer to page FS-2 of this Annual Report on Form 10-K in Management's Discussion
and Analysis of Financial Condition and Results of Operations for a discussion
on the company's current operating environment and outlook.
Chevron Strategic Priorities
- ----------------------------
Chevron's strategic objective is to exceed the financial performance of its
strongest industry competitors in terms of total stockholder return. The
company's overriding goal is to achieve the highest total stockholder return in
its peer group for the five-year period 2000 - 2004. To achieve its goal, the
company has targeted a 15 percent annual growth rate in earnings per share for
the three-year period 2000 - 2002, supported by worldwide liquids and natural
gas production growth of 4 to 4.5 percent per year, and a minimum 12 percent
return on capital employed.
To attain these financial and operational targets, the company has established
four key priorities:
o Operational Excellence: Safe, reliable, efficient and environmentally
sound operations throughout are the top priority for the company. The
company seeks to ensure it achieves sustainable improvements in its
operations.
o Cost Reduction: The company will continue to focus on ways of reducing
costs across its activities. As examples, the company has seen ongoing
successes in cost reduction in the areas of energy consumption and global
procurement of goods and services.
o Capital Stewardship: The company is implementing work processes designed to
ensure that it employs capital funding most efficiently. This involves
decision-making tools aimed at selecting the most financially and
strategically attractive projects. Additionally, the company has developed
processes to ensure the execution of projects is efficient, bringing
projects to completion on time and within budgeted expenditures.
o Profitable Growth: The company will seek continued growth in its core
businesses - exploration and production, refining, marketing and
transportation, and chemicals. The company is also looking to capture new
opportunities, such as investing in power and gas through its Dynegy
affiliate, new process technologies - including a method for converting
natural gas to liquids - and information and Internet technologies.
Supporting these four priorities is a continued and improved focus on:
o Organizational Capability: The company has developed strategies to build
capability systems to achieve top performance in the four priorities
described above.
Chevron-Texaco Merger Agreement
- -------------------------------
In October 2000, Chevron and Texaco announced an agreement to combine the two
companies into an integrated global energy company. Upon approval by regulatory
authorities and stockholders of both companies, and fulfillment of other
conditions, Chevron will issue 0.77 of its common shares for each share of
Texaco stock. The new company - ChevronTexaco Corporation - will have
significantly enhanced positions in upstream and downstream operations, a global
chemicals business, a growth platform in power generation, and industry-leading
skills in technology innovation. Synergistic savings of at least $1.2 billion
are expected within six to nine months of the merger.
-2-
<PAGE>
In advance of the merger approval by various regulatory authorities, Chevron and
Texaco work teams have been actively planning the integration of the two
companies, subject to customary legal restrictions on exchange of data between
competitors. In February 2001, the top 50 executives of the combined company
were announced. At the same time, a proposed organization structure was
outlined. The principal executive officers who will constitute a new Office of
the Chairman will be Chairman and CEO David O'Reilly (currently Chairman and CEO
of Chevron) and Vice Chairmen Richard Matzke (currently Vice Chairman of
Chevron) and Glenn Tilton (currently Chairman and CEO of Texaco). Three
corporate executive vice presidents will report to the office of the chairman
and have individual responsibility for downstream (refining marketing and
transportation); power, chemicals and technology; and administrative and
corporate services. Upstream (exploration and production) businesses will report
to Mr. Matzke.
On March 1, 2001, the European Union announced that it had approved the proposed
merger. Approvals are pending from the U. S. Federal Trade Commission (FTC) and
other agencies. Until consummation of the merger, Chevron and Texaco remain
competitors and continue to conduct day-to-day business under the laws dealing
with competitive practices for any independent company.
(b) Description of Business and Properties
The company's largest business segments are exploration and production
(upstream) and refining, marketing and transportation (downstream). Chemicals is
also a significant operation, conducted mainly by the company's affiliate -
Chevron Phillips Chemical Company LLC. The petroleum activities of the company
are widely dispersed geographically, with upstream and downstream operations in
the United States and Canada and upstream operations in Nigeria, Angola, Chad,
Equatorial Guinea, Republic of Congo, Democratic Republic of Congo, Australia,
the United Kingdom, Norway, China, Papua New Guinea, Thailand, Argentina, Brazil
and Venezuela. The company's Caltex affiliate, through its subsidiaries and
affiliates, conducts exploration and production and geothermal operations in
Indonesia and refining and marketing activities in Asia, Africa, the Middle
East, Australia and New Zealand, with major operations in Korea, Australia,
Thailand, the Philippines, Singapore and South Africa. The company's
Tengizchevroil affiliate conducts production activities in Kazakhstan. The
company expects to expand its operations in the Caspian Region by exploring for
crude oil and natural gas, expanding the production and transportation
infrastructure, developing new crude oil and natural gas markets, and
identifying other business opportunities.
The company's Dynegy Inc. (Dynegy) affiliate is one of the leading marketers of
energy products and services in the United States with customers in the United
States, Canada, the United Kingdom and other European countries. Its business
activities include energy marketing; independent power generation; gathering,
processing, selling and transportation of natural gas and natural gas liquids;
and broadband trading. In February 2000, Dynegy merged with Illinova
Corporation, an energy services holding company based in Illinois. The company
expects that this merger will accelerate Dynegy's growth in the power generation
and marketing business.
The company's Chevron Phillips Chemical Company LLC (CPCC) affiliate has
operations in the United States, Belgium, China, South Korea, Singapore, Saudi
Arabia and Mexico. CPCC commenced operations in July 2000 when Chevron combined
most of its petrochemicals businesses with those of Phillips Petroleum Company
into a 50-50 joint venture. The company's wholly owned Oronite additives
business has operations in the United States, France, Netherlands, Singapore,
Japan and Brazil.
Tabulations of segment sales and other operating revenues, earnings, income
taxes and assets, by United States and International geographic areas, for the
years 1998 to 2000, may be found in Note 10 to the consolidated financial
statements beginning on page FS-21 of this Annual Report on Form 10-K. In
addition, similar comparative data for the company's investments in and income
from equity affiliates and property, plant and equipment are contained in Notes
13 and 14 on pages FS-24 to FS-25.
The company's worldwide operations can be affected significantly by changing
economic, tax, regulatory and political environments in the various countries,
including the United States, in which it operates. Environmental regulations and
government policies concerning economic development, energy and taxation may
have a significant effect on the company's operations. Management evaluates the
economic and political risk of initiating, maintaining or expanding operations
in any geographical area. The company closely monitors political events
worldwide and the
-3-
<PAGE>
possible threat these may pose to its activities - particularly the company's
oil and gas exploration and production operations - and the safety of the
company's employees.
The company attempts to avoid unnecessary involvement in partisan politics in
the communities in which it operates but participates in the political process
to safeguard its assets and to ensure that the community benefits from its
operations and remains receptive to its continued presence.
A discussion of the company's use of derivative financial instruments to manage
its exposure to price risk stemming from its integrated petroleum activities is
contained on page FS-6 of this Annual Report on Form 10-K.
Capital and Exploratory Expenditures
Worldwide capital and exploratory (C&E) expenditures totaled $5.153 billion in
2000, compared with $6.133 billion in 1999. Expenditures for consolidated
worldwide exploration and production decreased by 35 percent between years. This
decrease was driven by the absence in 2000 of two significant international
exploration and production acquisitions in 1999, which totaled approximately
$1.7 billion: the Rutherford-Moran Oil Corporation in Thailand and Petrolera
Argentina San Jorge S.A. in Argentina. Consolidated international refining,
marketing and transportation expenditures increased by 114 percent in 2000
driven by additional investments in the Caspian Pipeline Consortium, which
continued construction of pipeline facilities linking the Tengiz Field in
Kazakhstan with the Russian Black Sea port of Novorossiysk. Consolidated
chemicals expenditures were 70 percent lower in 2000 following the formation of
CPCC, which is accounted for under the equity method. All Other expenditures
increased by over 300 percent between years as the company made an additional
investment of about $300 million in Dynegy Inc.
The company's share of affiliates' capital expenditures increased by 24 percent
between years to $967 million, driven by higher expenditures by the company's
Tengizchevroil and Dynegy Inc. affiliates.
Chevron's C&E expenditures during 2000 and 1999 are summarized in the following
table:
<TABLE>
<CAPTION>
Capital and Exploratory Expenditures
(Millions of Dollars)
2000 1999 Change %
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Exploration and Production - United States $1,237 $ 900 $ 337 37
International 1,475 3,242 (1,767) (55)
-------- ------- -------
Sub-total 2,712 4,142 (1,430) (35)
Refining, Marketing
and Transportation - United States 481 516 (35) (7)
International 391 183 208 114
-------- ------ -------
Sub-total 872 699 173 25
Chemicals - United States 78 326 (248) (76)
International 41 67 (26) (39)
-------- ------ -------
Sub-total 119 393 (274) (70)
All Other 483 117 366 313
-------- ------ -------
Total Consolidated Companies 4,186 5,351 (1,165) (22)
Chevron's Share in Affiliates 967 782 185 24
-------- ------ -------
Total Including Affiliates $5,153 $6,133 $ (980) (16)
======== ====== =======
</TABLE>
The company's 2001 C&E expenditures, including its share of equity affiliates'
expenditures, are projected at $6 billion, 16 percent higher than 2000 spending
levels. The company plans to invest $3.7 billion, or 62 percent of its total
spending, in worldwide exploration and production, of which $1.2 billion will be
expended in the United States. About $1.4 billion will be invested in worldwide
refining, marketing and transportation activities. Investments in chemicals will
be about $250 million with about $650 million targeted for all other activities,
including power and natural gas facilities and distribution, and technology. The
spending plans discussed above are for Chevron as a stand-alone entity and do
not reflect the impact of the pending merger with Texaco. They also do
-4-
<PAGE>
not include the acquisition of an additional 5 percent equity interest in the
Tengizchevroil project in Kazakhstan, which closed in January 2001.
Petroleum - Exploration and Production
Liquids and Natural Gas Production
The following table summarizes the company's and affiliates' net production of
crude oil, natural gas liquids and natural gas for 2000 and 1999.
<TABLE>
<CAPTION>
Net Production* Of Crude Oil And Natural Gas Liquids And Natural Gas
--------------------------------------------------------------------
Crude Oil & Natural Gas
Natural Gas Liquids (Millions of
(Thousands of Barrels per Day) Cubic Feet per Day)
------------------------------ -------------------------
2000 1999 2000 1999
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
United States
-California 108.9 111.8 116.0 114.8
-Gulf of Mexico 116.0 104.7 784.5 790.0
-Texas 35.9 45.7 266.5 323.0
-Wyoming 11.0 10.0 154.6 170.3
-Other States 40.1 43.6 236.7 240.3
----------------------------------------------------------------
Total United States 311.9 315.8 1,558.3 1,638.4
----------------------------------------------------------------
Angola 159.5 145.6 - -
Nigeria 147.1 144.0 46.8 39.2
Canada 65.4 65.0 146.2 193.6
Argentina 51.1 13.4 50.8 8.8
Australia 41.4 30.4 223.0 227.1
United Kingdom (North Sea) 36.0 42.2 218.6 218.8
Congo 24.5 28.9 - -
Norway 15.3 15.8 0.7 0.4
Thailand 14.3 3.7 69.6 39.4
China 13.9 13.9 - -
Indonesia 12.6 17.0 - -
Papua New Guinea 10.8 15.2 - -
Democratic Republic of Congo 8.3 8.8 - -
Venezuela 4.1 2.5 - -
Colombia 1.1 11.4 - -
Netherlands - - 1.3 1.9
----------------------------------------------------------------
Total International 605.4 557.8 757.0 729.2
----------------------------------------------------------------
Total Consolidated Companies 917.3 873.6 2,315.3 2,367.6
Chevron's Share of Affiliates 241.3 253.4 153.8 145.0
----------------------------------------------------------------
Total Including Affiliates 1,158.6 1,127.0 2,469.1 2,512.6
================================================================
<FN>
* Net production excludes royalty interests owned by others.
</FN>
</TABLE>
In 2000, Chevron conducted its worldwide exploration and production operations
in the United States and approximately 25 other countries. Worldwide net crude
oil and natural gas liquids production, including that of affiliates but
excluding volumes produced under operating service agreements, increased for the
eighth consecutive year by nearly 3 percent from the 1999 levels. Net liquids
production in the United States fell slightly. International net liquids
production, including affiliates, increased by about 4 percent in 2000 - the
eleventh consecutive year of production increases. This increase was due
primarily to a full year of production in Argentina and Thailand following
acquisitions the company made in 1999; higher production from new fields in
Angola; and
-5-
<PAGE>
higher production in Australia. These increases were partially offset by
production declines in Indonesia, Colombia and the United Kingdom.
Net production of natural gas, including affiliates, fell by 2 percent in 2000.
United States production fell about 5 percent, as normal field declines more
than offset new and enhanced production from the Gulf of Mexico shelf and
deepwater Gulf of Mexico. International volumes increased 4 percent in 2000.
Higher production from the Argentina and Thailand properties acquired in 1999
were slightly offset by lower production in Canada due to normal field declines.
Acreage
At December 31, 2000, the company owned or had under lease or similar agreements
undeveloped and developed oil and gas properties located throughout the world.
Undeveloped acreage includes undeveloped proved acreage. The geographical
distribution of the company's acreage is shown in the next table.
<TABLE>
<CAPTION>
Acreage* At December 31, 2000
(Thousands of Acres)
Developed
Undeveloped Developed and Undeveloped
------------------- ------------------- ------------------
Gross Net Gross Net Gross Net
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
United States 4,759 3,288 2,728 1,593 7,487 4,881
-------- -------- -------- -------- -------- --------
Canada 21,709 12,361 1,377 504 23,086 12,865
Africa 20,345 6,705 216 79 20,561 6,784
Asia 12,239 5,636 208 57 12,447 5,693
Other International 30,715 13,616 1,199 300 31,914 13,916
-------- -------- -------- -------- -------- --------
Total International 85,008 38,318 3,000 940 88,008 39,258
-------- -------- -------- -------- -------- --------
Total Consolidated Companies 89,767 41,606 5,728 2,533 95,495 44,139
Chevron's Share in Affiliates 2,767 1,334 286 144 3,053 1,478
-------- -------- -------- -------- -------- --------
Total Including Affiliates 92,534 42,940 6,014 2,677 98,548 45,617
======== ======== ======== ======== ======== ========
<FN>
*Gross acreage includes the total number of acres in all tracts in which the
company has an interest.
Net acreage is the sum of the company's fractional interests in gross
acreage.
</FN>
</TABLE>
Refer to Table III on pages FS-34 to FS-36 of this Annual Report on Form 10-K
for data about the company's average sales price per unit of oil and gas
produced, as well as the average production cost per unit for 2000, 1999 and
1998. The following table summarizes gross and net productive wells at year-end
2000 for the company and its affiliates.
-6-
<PAGE>
<TABLE>
<CAPTION>
Productive Oil And Gas Wells At December 31, 2000
Productive(1) Productive(1)
Oil Wells Gas Wells
------------------- --------------------
Gross(2) Net(2) Gross(2) Net(2)
-------- -------- --------- ---------
<S> <C> <C> <C> <C>
United States 23,452 11,715 4,515 2,154
-------- -------- --------- ---------
Canada 1,062 863 197 142
Africa 1,359 514 8 3
Other International 2,036 900 162 73
-------- -------- --------- ---------
Total International 4,457 2,277 367 218
-------- -------- --------- ---------
Total Consolidated Companies 27,909 13,992 4,882 2,372
Chevron's Share of Affiliates 8,304 4,120 273 75
-------- -------- --------- ---------
Total Including Affiliates 36,213 18,112 5,155 2,447
======== ======== ========= =========
Multiple completion wells included above: 690 390 384 234
<FN>
(1)Includes wells producing or capable of producing and injection wells temporarily functioning as producing
wells. Wells that produce both oil and gas are classified as oil wells.
(2)Gross wells include the total number of wells in which the company has an interest. Net wells are the sum of
the company's fractional interests in gross wells.
</FN>
</TABLE>
Reserves and Contract Obligations
Table IV on pages FS-36 and FS-37 of this Annual Report on Form 10-K sets forth
the company's net proved oil and gas reserves, by geographic area, as of
December 31, 2000, 1999 and 1998. During 2001, the company will file estimates
of oil and gas reserves with the Department of Energy, Energy Information
Agency. Those estimates are consistent with the reserve data reported on page
FS-37 of this Annual Report on Form 10-K.
In 2000, Chevron's worldwide oil and equivalent-gas (BOE) barrels of net proved
reserves additions exceeded production for the eighth consecutive year, with a
replacement rate of 152 percent of net production, including sales and
acquisitions. Excluding sales and acquisitions, the replacement rate was 132
percent of net production. The following table summarizes the company's net
additions to net proved reserves of crude oil and natural gas liquids and
natural gas, compared with net production during 2000.
<TABLE>
<CAPTION>
Reserves Replacement - 2000
Additions to Net BOE Reserves
Reserves Production Replacement %
------------------- ----------------- ------------ Memo:
Including
Liquids Gas Liquids Gas Sales and
(mmbbls)(1) (bcf)(2) (mmbbls)(1) (bcf)(2) Acquisitions
---------- ------- ---------- ------- ------------
<S> <C> <C> <C> <C> <C> <C>
United States 96.2 275.8 114.1 570.3 78% 68%
Africa 299.9 462.2 124.2 17.1 192% 297%
Other international(3) 245.8 661.2 185.7 316.3 148% 149%
--------- ------- -------- -------
Total Worldwide 641.9 1,399.2 424.0 903.7 132% 152%
========== ======= ======== =======
<FN>
(1) mmbbls = millions of barrels
(2) bcf = billions of cubic feet
(3) Includes equity in affiliates
</FN>
</TABLE>
The company sells crude oil and gas from its producing operations under a
variety of contractual arrangements. Most contracts generally commit the company
to sell quantities based on production from specified properties but
-7-
<PAGE>
certain gas sales contracts specify delivery of fixed and determinable
quantities. In the United States, the company is obligated to sell substantially
all of the natural gas produced and owned or controlled by the company in the
lower 48 states to Dynegy Inc. Outside the United States, the company is
contractually committed to deliver approximately 110 billion cubic feet of
natural gas through 2003 from Australian and U.K. reserves and approximately 375
billion cubic feet of natural gas post 2003 through 2020 from Australian
reserves only. Substantially all of these contracts include variable-pricing
terms. The company believes it can satisfy these contracts from quantities
available from production of the company's proved developed Australian and U.K.
natural gas reserves.
Development Activities
- ----------------------
Details of the company's development expenditures and costs of proved property
acquisitions for 2000, 1999 and 1998 are presented in Table I on page FS-33 of
this Annual Report on Form 10-K.
The table below summarizes the company's net interest in productive and dry
development wells completed in each of the past three years and the status of
the company's development wells drilling at December 31, 2000. A "development
well" is a well drilled within the proved area of an oil or gas reservoir to the
depth of a stratigraphic horizon known to be productive. "Wells drilling"
include wells temporarily suspended.
<TABLE>
<CAPTION>
Development Well Activity
Wells Drilling Net Wells Completed(1)
-----------------------------------------------
At 12/31/00 2000 1999 1998
----------------- ------------ ------------ ------------
Gross(2) Net(2) Prod. Dry Prod. Dry Prod Dry
------ ---- ----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C> <C> <C>
United States 141 61 348 7 411 7 324 5
------ ---- ----- --- ----- --- ----- ---
Africa 9 3 39 - 18 - 38 1
Other International 24 13 128 - 42 - 33 2
------ ---- ----- --- ----- --- ----- ---
Total International 33 16 167 - 60 - 71 3
------ ---- ----- --- ----- --- ----- ---
Total Consolidated Companies 174 77 515 7 471 7 395 8
Equity in Affiliates 49 17 252 - 220 - 272 -
------ ---- ----- --- ----- --- ----- ---
Total Including Affiliates 223 94 767 7 691 7 667 8
====== ==== ===== === ===== === ===== ===
<FN>
(1) Indicates the number of wells completed during the year regardless of when drilling was initiated. Completion refers to
the installation of permanent equipment for the production of oil or gas or, in the case of a dry well, the reporting of
abandonment to the appropriate agency.
(2) Gross wells include the total number of wells in which the company has an interest. Net wells are the sum of the
company's fractional interests in gross wells.
</FN>
</TABLE>
-8-
<PAGE>
Exploration Activities
- ----------------------
The following table summarizes the company's net interests in productive and dry
exploratory wells completed in each of the last three years and the number of
exploratory wells drilling at December 31, 2000.
<TABLE>
<CAPTION>
Exploratory Well Activity
Wells Drilling Net Wells Completed(1)
-----------------------------------------------
At 12/31/00 2000 1999 1998
----------------- ------------ ------------ ------------
Gross(2) Net(2) Prod. Dry Prod. Dry Prod. Dry
------ ---- ----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C> <C> <C>
United States 36 22 60 22 72 30 46 12
------- ----- ------ ---- ----- ----- ------ ----
Africa 5 2 - 2 1 2 7 2
Other International 17 7 14 16 7 9 9 8
------- ----- ------ ---- ----- ----- ------ --
Total International 22 9 14 18 8 11 16 10
------- ----- ------ ---- ----- ----- ------ --
Total Consolidated Companies 58 31 74 40 80 41 62 22
Chevron's Share in Affiliates 7 3 - - 1 - 2 -
------- ----- ------ ---- ----- ----- ------ ---
Total Including Affiliates 65 34 74 40 81 41 64 22
======= ===== ====== ==== ===== ===== ====== ===
<FN>
(1)Indicates the number of wells completed during the year regardless of when
drilling was initiated. Completion refers to the installation of permanent
equipment for the production of oil or gas or, in the case of a dry well, the
reporting of abandonment to the appropriate agency.
(2)Gross wells include the total number of wells in which the company has an
interest. Net wells are the sum of the company's fractional interests in
gross wells.
</FN>
</TABLE>
"Exploratory wells" are wells drilled to find and produce oil or gas in unproved
areas and include delineation wells, which are wells drilled to find a new
reservoir in a field previously found to be productive of oil or gas in another
reservoir or to extend a known reservoir beyond the proved area. "Wells
drilling" include wells temporarily suspended. The company had $400 million of
suspended exploratory wells included in properties, plant and equipment at
year-end 2000, an increase of $26 million from 1999. Decreases in the United
States were more than offset by increases in Angola, China and Canada. The wells
are suspended pending a final determination of the commercial potential of the
related oil and gas fields. The ultimate disposition of these well costs is
dependent on: (1) decisions on additional major capital expenditures, (2) the
results of additional exploratory drilling that is underway or firmly planned,
and in some cases, (3) securing final regulatory approvals for development.
Details of the company's exploration expenditures and costs of unproved property
acquisitions for 2000, 1999 and 1998 are presented in Table I on page FS-33 of
this Annual Report on Form 10-K.
Review of Ongoing Exploration and Production Activities in Key Areas
- --------------------------------------------------------------------
Chevron's 2000 key upstream activities not discussed in Management's Discussion
and Analysis of Financial Condition and Results of Operations beginning on page
FS-2 of this Annual Report on Form 10-K are presented below. In addition to the
activities discussed, Chevron was active in other geographic areas, but these
activities were of less significance.
A) United States
United States exploration and production activities are concentrated in about
300 fields located in the Gulf of Mexico, Texas, the Rocky Mountains, California
and Alaska. Some of the company's more significant activities in the United
States are described below.
Chevron has interests in three deepwater developments in the Gulf of Mexico.
Genesis, Chevron's first deepwater operation, located in 2,600 feet of water,
began production in January 1999. Chevron is operator and has a 57 percent
interest in Genesis, which reached peak total production of 58,000 barrels of
crude oil and 86 million cubic feet of gas per day in September 2000. Average
total production for 2001 is estimated at 42,000 barrels of crude oil and 54
million cubic feet of gas per day. Chevron has a 40 percent interest in the
Gemini deepwater development located in Mississippi Canyon Block 292 in 3,400
feet of water. Initial production occurred in June 1999. Total production from
Gemini averaged 131 million cubic feet of gas per day in 2000. Typhoon is
-9-
<PAGE>
Chevron's third deepwater development, in 2,000 feet of water, in the Gulf of
Mexico. Initial production from Typhoon is scheduled for third quarter 2001. The
platform will support production facilities for 40,000 barrels of oil and 60
million cubic feet of gas per day. Chevron is the operator with a 50 percent
interest.
An aggressive 2000 well drilling program in the Gulf of Mexico Shelf enabled the
company to develop opportunities to offset field declines in production to less
than 2 percent between years. Chevron has interests in the Viosca Knoll Trend in
the Gulf of Mexico shelf and in 2000 continued to focus on establishing
production from additional gas reservoirs. Total production increased from 70
million cubic feet of gas per day at the beginning of the year to 240 million
cubic feet of gas per day at year-end. Total production is expected to average
200 million cubic feet of gas per day in 2001. The 2001-2003 program will
provide continued exploration and development of the Viosca Knoll area.
Development of the Destin Dome area of the Norphlet trend offshore Florida
continues to be hampered by delays in obtaining regulatory approvals. A draft
environmental impact statement (EIS) was issued August 1999 by the governing
agencies indicating no significant environmental impacts had been found. In July
2000, Chevron and its partners in the Destin Dome development filed a lawsuit
against the federal government to recover exploration expenses and future lost
profits following continuing delays in obtaining the necessary development
permits.
Onshore California, Chevron continued to expand its use of thermal enhanced
recovery techniques to increase the production rate and the amount of oil
ultimately recoverable from fields in the San Joaquin Valley, with efforts
focused on the Cymric Field. Average 2000 production from the San Joaquin Valley
fields was 104,000 barrels of oil and 112 million cubic feet of gas per day.
B) Africa
Nigeria: Chevron's principal subsidiary in Nigeria, Chevron Nigeria Limited
(CNL), operates and holds a 40 percent interest in 11 concessions totaling 2.3
million acres, predominantly in the swamp and near offshore regions of the Niger
Delta. During 1999, CNL's onshore and swamp area concessions were renewed for a
second 30-year term. CNL's offshore concessions expire in 2008. The renewal
process for the offshore concessions is provided for under the same statute as
for the concessions renewed in 1999. Application for renewal must be made before
one year of a concession's expiration. Based on the requirements of Nigerian law
concerning concession renewal, as well as the prior industry and company
experience with renewals, the company fully expects renewal of the offshore
concessions to be approved. Chevron Oil Company Nigeria Limited (COCNL) holds a
20 percent interest in six concessions, covering 600,000 acres, operated by
Texaco. Chevron Petroleum Nigeria Limited (CPNL) oversees and manages new
venture activities in Nigeria. CPNL has a 30 percent interest in one deepwater
Niger Delta block operated by Elf. CPNL interests in Benue Basin blocks were
relinquished after the drilling of exploratory dry holes indicated a low
probability of hydrocarbon presence. Chevron participated in Nigeria's deep- and
ultra-deep water 2000 bid round. Chevron was awarded interests in three
deepwater oil prospecting licenses, one as operator with a 50 percent interest
and 30 percent non-operating interests in the other two. Chevron and its
partners expect to develop work programs for the three newly acquired blocks
during 2001.
Total 2000 production averaged 430,000 barrels of liquids per day from 33
CNL-operated fields and approximately 47,000 barrels of oil per day from the
COCNL fields. Both production amounts were slightly higher than 1999.
Processing capacity at the Escravos gas plant increased to 285 million cubic
feet per day with start-up of Phase 2 of the project in the fourth quarter 2000,
representing another significant step toward reducing flaring of natural gas.
Front-end engineering and design for Phase 3, which will expand gas-processing
capacity to 680 million cubic feet per day, is expected to begin during the
second quarter of 2001. Feasibility engineering and preliminary technical
evaluations are nearing completion for a Gas-to-Liquids (GTL) plant proposed for
construction in Escravos. The proposed 33,000 barrels-per-day Escravos project
is expected to be the first project to use the technology and operational
expertise of a global GTL joint venture between Chevron and Sasol Limited.
Chevron is the Managing Sponsor of a consortium of six energy companies that
plans to develop a 600-mile gas transmission pipeline to connect suppliers in
the Western Delta region of Nigeria to power generation and industrial customers
in Benin, Ghana, and Togo. Subject to successful negotiation of concession
conditions with the governments, commercial operations could commence by late
2003 or 2004.
-10-
<PAGE>
Angola: The company is the operator of two concessions, Blocks 0 and 14, off the
coast of Angola's Cabinda Province. Block 0 is a 2,100 square-mile concession
adjacent to the Cabinda coastline in which Chevron has an approximate 39 percent
interest. Block 14 is a 1,560-square-mile deepwater concession located west of
Block 0, in which Chevron has a 31 percent interest.
Block 0 total crude oil production during 2000 averaged 448,000 barrels per day,
down from an average of 460,000 in 1999, mainly due to normal field declines.
Area A of Block 0 includes 23 major fields, with 15 fields currently producing.
In 2000, 35 development wells were completed in Area A. The Kungulo and Vuko
fields, part of the Area A Waterflood Major Project, achieved first injection
from a new water injection platform in May 2000. Area B includes six major
fields. The Kokongo, Lomba and the southern part of the Nemba Field have
undergone the initial stages of development and are currently on production. In
Area B, three additional infill wells in South Nemba resulted in 17,000 barrels
of oil per day of incremental gross production. An additional infill program was
initiated in Kokongo Field and will be completed during 2001. Future development
plans also include installation of the North Nemba production and gas injection
platform in 2001. North Nemba development drilling is expected to add over
40,000 barrels per day of gross production by 2002. Area C includes seven major
fields. The N'Dola and Sanha fields are currently on production.
Six fields have been discovered in Block 14 - Kuito, Landana, Benguela, Belize,
Tomboco and Lobito. The Kuito Field, Angola's first deepwater production,
averaged over 61,000 barrels of oil per day in 2000. Kuito is being developed
using a phased approach. Phases 1A and 1B well programs are complete and
construction activities have commenced on Phase 1C, with first oil scheduled for
the third quarter 2001. Tomboco and Lobito were two significant Block 14
discoveries made in 2000. These wells are located in the vicinity of three of
the previously discovered fields. The appraisal drilling program for the
Benguela, Belize and Tomboco Fields was completed in early 2000. Development
plans call for a centralized drilling and production platform for the Benguela
and Belize Fields. Tomboco will be a satellite to this facility. The impact of
the nearby Lobito Field, discovered and appraised in 2000, will be included in
engineering studies during 2001. Study of the Landana Field continues, with an
appraisal well planned in 2001.
Republic of Congo: Chevron has interests in three partner-operated license areas
- - Haute Mer, Marine VII and Mer Profonde Sud - in offshore Congo, adjacent to
Chevron's concessions in Angola. Net production from Chevron's concessions in
the Republic of Congo averaged about 25,000 barrels per day in 2000. In the
Marine VII permit area, where Chevron has an interest of about 29 percent in the
Kitina and Sounda Exploitation Permits, development of the Kitina Field
continued and total production averaged about 27,000 barrels of oil per day.
Further development work, including gas injection, is planned for 2001. In Haute
Mer, where Chevron has a 30 percent interest, development of the Nkossa Field
continued with the recompletion of several wells. Total production in the field,
operated by Elf Congo, averaged about 66,000 barrels of oil and liquefied
petroleum gas per day in 2000. Development planning for the Moho and Bilondo
fields in the Haute Mer license continues with a development decision expected
in mid-2001. Two wells were drilled in the Mer Profonde Sud exploration license
in 2000, resulting in one non-commercial oil discovery and one dry hole.
Continued participation in the permit, where Chevron has a 15 percent equity
interest, is currently being re-evaluated with a decision planned for early
2001.
Chad/Cameroon: Chevron is a 25 percent partner in a consortium comprised of
affiliates of ExxonMobil and Petronas in a project to develop the Doba oil
fields in southern Chad and construct a pipeline to the coast of Cameroon for
export of oil to world markets. This project is expected to cost approximately
$3.5 billion and have a 20- to 30-year life. First production is expected in
2004.
Equatorial Guinea: In May, 2000 Chevron entered into a Production Sharing
Contract with the Republic of Equatorial Guinea for Block L, located off the
coast of the island of Bioko. The work program has an initial period of five
years with two one-year extensions. A 3D seismic survey was initiated in
December 2000.
C) Other International Areas
Caspian Region: The Tengizchevroil (TCO) partnership, formed in 1993, includes
the Tengiz and Korolev oil fields located in western Kazakhstan. Chevron had a
45 percent interest in TCO in 2000. In January 2001, Chevron increased its
ownership interest in TCO to 50 percent. In 2000, total crude oil
production from the Tengiz Field increased for the seventh straight year,
averaging 229,000 barrels of oil per day. TCO completed a three-year
-11-
<PAGE>
plant expansion project in 2000 to increase TCO's processing and export
capacity. The project will permit crude oil production to increase to
approximately 260,000 barrels per day - the average gross production rate
expected for 2001. TCO plans to bring the Korolev field on line in 2001 by
extending its existing gathering system.
The Caspian Pipeline Consortium (CPC) was formed to build a crude oil export
pipeline from the Tengiz Field to the Black Sea port of Novorossiysk at a
projected total cost of $2.6 billion. When completed, the CPC pipeline will
allow for the export of an initial capacity of 600,000 barrels of oil per day,
expandable to 1.5 million barrels per day with additional pump stations, tankage
and marine loading facilities. Chevron has a 15 percent ownership interest in
CPC, which remains on schedule for a mid-2001 start-up.
Europe: Chevron holds interests in four producing fields offshore the United
Kingdom and Norway: the Alba oil field, the Britannia gas condensate field, and
non-operated interests in Statfjord and Draugen. Total production from the Alba
Field averaged 80,000 barrels of crude oil per day in 2000. Chevron's interest
in Alba is approximately 21 percent. Total production from the Britannia Field
averaged 692 million cubic feet of gas per day and approximately 40,000 barrels
per day of condensate during 2000. Chevron has an approximate 30 percent
interest in Britannia and shares operatorship with Conoco. In Norway, the
Draugen Field, in which Chevron has a 7.56 percent interest, produced an average
of 203,000 barrels of oil per day in 2000. Statfjord, where Chevron has a 4.84
percent interest, produced an average of 180,000 barrels per day in 2000. In the
16th Licensing Round in April, Chevron was awarded three new high-potential
licenses in the Norwegian Sea - one as operator.
Canada: Total production from the Hibernia Field offshore Newfoundland, in which
Chevron holds an interest of about 27 percent, averaged approximately 144,000
barrels of crude oil per day in 2000, up from 100,000 barrels of crude oil per
day in 1999. Also offshore Newfoundland, the company operates and holds a 28
percent interest in the Hebron Field, where a delineation well completed in 2000
confirmed previous hydrocarbon reservoirs and tested a new reservoir. At Fort
Liard in the Northwest Territories, the K-29 discovery well came into production
in April 2000. A second well came into production in early November. Combined
December total production from the two wells averaged 108 million cubic feet per
day of natural gas and byproducts. Chevron holds a 43 percent working interest
in the Fort Liard pool. In the Mackenzie Delta region of northern Canada,
Chevron formed two new joint venture partnerships to conduct exploration over a
large area totaling more than one million gross acres. One partnership is with
BP Canada Energy and covers two exploration concessions. The second partnership
is with BP and Burlington Resources Canada Energy Ltd., and covers three
exploration leases. Also in 2000, construction began on mining, extraction and
upgrading facilities for the $2.4 billion Athabasca Oil Sands Project. The
project is expected to begin production in late 2002 and reach 155,000 barrels
of bitumen per day at peak production. The tar-like bitumen will be upgraded
into high quality synthetic oil using hydroprocessing technology. Chevron has a
20 percent working interest in the project.
Australia: Chevron's primary interests in Australia involve a number of joint
ventures. The largest is the North West Shelf (NWS) Project offshore Western
Australia, where Chevron has an approximate 17 percent interest. Average total
field production during 2000 from the North Rankin and Goodwyn fields in the NWS
project was 1.5 billion cubic feet of gas per day and 99,000 barrels per day of
condensate. Total oil production from the Wanaea/ Cossack, Lambert and Hermes
fields averaged 116,000 barrels per day in 2000. Liquefied petroleum gas (LPG)
production driven by the liquids-rich gas averaged 23,400 barrels per day in
these fields. During 2000 a number of Japanese customers agreed to terms on
Letters of Intent with the NWS partners, underpinning the proposed fourth
liquefied natural gas (LNG) train, which would increase LNG production by about
50 percent. Chevron's other major area of activity is in permit areas that
include the Barrow Island and Thevenard Island oil fields and the undeveloped
Gorgon area gas fields, southwest of the NWS fields. Chevron operates a number
of joint ventures with production facilities on Barrow Island and Thevenard
Island, with interests varying from 25 percent to 50 percent. Chevron assumed
operatorship of these areas from West Australian Petroleum Pty. Ltd. in late
1999. Total oil production from the Barrow Island and Thevenard Island oil
fields in 2000, averaged 25,000 barrels per day, with Chevron's share of
production being 6,600 barrels per day. In addition to the two major joint
ventures above, Chevron has interests in the northern Browse Basin, and three
new deepwater exploration permits in the offshore Canning Basin, near the NWS
joint venture acreage. Chevron's interests vary from about 17 percent to 25
percent. During 2000, Chevron continued to pursue the Australia Gas Pipeline
Project from Papua New Guinea to Queensland, Australia. This project will allow
commercialization of Papua New Guinea natural gas reserves and recovery of
substantial quantities of natural gas liquids (NGL).
-12-
<PAGE>
Indonesia: Chevron's interests in Indonesia are managed by two affiliate
companies, PT Caltex Pacific Indonesia (CPI) and Amoseas Indonesia (AI). Chevron
owns 50 percent of both companies. CPI manages all of Chevron's interests in
four production sharing contracts in Indonesia. Chevron's net share of total
production of 705,000 barrels per day in 2000 was 158,000 barrels per day. CPI
continues to implement enhanced oil recovery projects to extract more oil from
its existing reservoirs. The Duri Field, under steamflood since 1985, is the
largest steamflood in the world. Currently 9 of 13 phases are under steam
injection, with the tenth phase scheduled for injection in late 2001. AI is a
power generation company that operates the Darajat geothermal contract area in
central Java and is constructing a cogeneration facility to support CPI's Duri
steamflood. AI's geothermal field continued to provide steam to the national
power company plant and a company-owned plant that produces electricity for the
Java power grid. Further expansion of the Darajat geothermal reservoir complex
is planned. The Darajat reservoir has proved reserves of steam to generate 350
megawatts for 30 years.
Thailand: Chevron operates Block B8/32 in the Gulf of Thailand. Chevron has an
approximate 52 percent interest in the 734,000-acre block. Chevron also holds a
33 percent interest in adjacent exploration blocks 7, 8 and 9, which are
currently inactive pending resolution of Thailand-Cambodia border issues. Block
B8/32 is currently producing oil and natural gas from two fields, Tantawan and
Benchamas. In December 2000, the Tantawan Field was producing at a rate of 38
million cubic feet of gas per day and 5,400 barrels of oil per day. The
Benchamas Field was producing at an average rate of 110 million cubic feet of
gas per day and 28,600 barrels of oil per day. In Block B8/32 development of the
Maliwan Field is under-way, with the Maliwan A platform installation and initial
production through the Benchamas facilities expected by November 2001. The
Government of Thailand awarded a Production License Area (PLA) for North
Jarmjuree in November 2000. Further delineation of the North Jarmjuree PLA is
planned in 2001.
Argentina: Chevron holds over 4.2 million acres of exploration and production
acreage in the Neuquen and Austral Basins of Argentina with working interest
shares ranging from about 18 to 100 percent in operated license areas. In
addition, Chevron holds a 14 percent interest in a major oil export pipeline
from the Neuquen producing area to the Atlantic coast. At year-end 2000,
properties in the Neuquen and Austral Basins were producing at total combined
rates of 91,000 barrels of oil-equivalent per day. During 2000, Chevron
strengthened its Neuquen Basin leasehold position by purchasing two exploration
permits and two production concessions from Alberta Energy Company. Chevron's
exploration and appraisal program in 2000 resulted in three oil and two gas
discoveries that added over 50 million barrels to Chevron's proved and probable
oil-equivalent reserves. Exploration plans include 15 wells and the acquisition
of more than 250,000 acres of seismic data in 2001.
Brazil: As part of a strategy to expand its deepwater prospects and other
interests in South America, the company acquired in 2000 a 65 percent interest
in, and was designated operator of, exploration block BM-S-7.. A 25 percent
non-operated interest was also acquired in exploration block BM-S-10. Both
blocks are located in the Santos area of the Salt Basin. These two blocks bring
Chevron's total exploration acreage in the Salt Basin to 4.1 million acres.
Seismic programs for blocks BCUM-100 and BC-20 commenced in 2000 and three
exploratory wells are planned for 2001. Chevron's interest in both these
Petrobras-operated blocks is 50 percent. Current plans for BM-S-7and BM-S-10 are
to acquire and evaluate geologic and seismic data in 2001 and 2002, with
drilling commencing in 2003.
Venezuela: Chevron and Petroleos de Venezuela, S.A. (PDVSA) formed an alliance
in 1995 to further develop the Boscan oil field and provide heavy crude oil to
Chevron in the United States through several independent supply agreements.
Chevron took over operations of the Boscan Field in 1996 under an Operating
Services Agreement and receives operating expense reimbursement and capital
recovery, plus interest and an incentive fee. Development drilling continued in
the Boscan Field, with 41 wells completed during 2000. Average production from
Boscan was at the 115,000 barrels-of-oil-per-day limit specified in the
Operating Services Agreement for the second half of 2000. Chevron also is the
operator and has a 27 percent interest in the LL-652 Field in Lake Maracaibo.
The LL-652 Field objective is to increase production over the next few years
through the application of secondary recovery technologies. LL-652 oil
production during 2000 averaged 16,500 barrels per day, up from an average of
9,700 in 1999.
-13-
<PAGE>
Petroleum - Natural Gas Liquids
The company sells natural gas liquids from its producing operations under a
variety of contractual arrangements. In the United States, the majority of sales
are to the company's Dynegy Inc. affiliate, in which the company had an
approximate 26 percent interest at year-end 2000. Dynegy and Chevron have
entered into long-term strategic alliances whereby Dynegy purchases
substantially all natural gas and natural gas liquids produced by Chevron in the
United States, excluding Alaska, and supplies natural gas and natural gas
liquids feedstocks to Chevron's U.S. refineries and chemical plants. Outside the
United States, natural gas liquids sales take place in the company's Canadian
upstream operations, with lower sales levels in Africa, Australia and Europe. In
2000, U.S. sales volumes, including Chevron's share of Dynegy sales, comprised
about 70 percent of the company's total worldwide natural gas liquids sales
volume.
Chevron's total third-party natural gas liquids sales volumes over the last
three years were as follows:
<TABLE>
<CAPTION>
Natural Gas Liquids Sales Volumes
(Thousands of Barrels per Day)
2000 1999 1998
------- ------ ------
<S> <C> <C> <C>
United States 71 65 63
Canada 23 24 26
Other International 13 10 7
------- ------- ------
Total Consolidated Companies 107 99 96
Share of Dynegy Affiliate 111 91 87
------- ------- ------
Total including Affiliate 218 190 183
======= ======= ======
</TABLE>
Petroleum - Refining
Based on refinery statistics published in the December 18, 2000 issue of The Oil
and Gas Journal, Chevron had the fourth largest U.S. refining capacity. The
company's 50 percent-owned Caltex Corporation affiliate owned or had interests
in 10 operating refineries: Australia (2), Thailand, Korea, the Philippines, New
Zealand, Singapore, Pakistan, Kenya and South Africa. In 2000, Caltex
relinquished its 4.75 percent interest in a second refinery in Thailand. In
1999, Caltex sold its interest in two Japanese refineries owned by Koa Oil
Company Limited.
Distillation operating capacity utilization in 2000, adjusted for sales and
closures, averaged 90 percent in the United States (including asphalt plants)
and 89 percent worldwide (including affiliate), compared with 91 percent in the
United States and worldwide in the prior year. Chevron's capacity utilization at
its U.S. fuels refineries averaged 94 percent in 2000, down slightly from 96
percent in 1999. Chevron's capacity utilization of its U.S. cracking and coking
facilities, which are the primary facilities used to convert heavier products to
gasoline and other light products, averaged 80 percent in 2000, up from 78
percent in the year earlier. The company processed imported and domestic crude
oil in its U.S. refining operations. Imported crude oil accounted for 70 percent
of Chevron's U.S. refinery inputs in 2000.
-14-
<PAGE>
The daily refinery inputs over the last three years for the company's and its
Caltex affiliate's refineries are shown in the following table:
<TABLE>
<CAPTION>
Petroleum Refineries: Locations, Capacities And Inputs
(Inputs and Capacities are in Thousands of Barrels Per Day)
December 31, 2000
-------------------
Operable Refinery Inputs
Locations Number Capacity 2000 1999 1998
--------------------------------------------------- ------ -------- ------ ------ -----
<S> <C> <C> <C> <C> <C>
Pascagoula, Mississippi 1 295 313 328 246
El Segundo, California 1 260 219 211 218
Richmond, California 1 225 203 207 201
El Paso,(1) Texas 1 65 60 65 62
Honolulu, Hawaii 1 54 51 51 49
Salt Lake City, Utah 1 45 44 43 40
Other(2) 2 96 53 50 52
--- ------ ------ ------ -----
Total United States 8 1,040 943 955 868
--- ------ ------ ------ -----
Burnaby, B.C., Canada 1 52 51 52 50
--- ------ ------ ------ -----
Total International 1 52 51 52 50
--- ------ ------ ------ -----
Total Consolidated Companies 9 1,092 994 1,007 918
Equity in Caltex Affiliate(3) Various Locations 10 423 363 417 425
--- ------ ------ ------ -----
Total Including Affiliate 19 1,515 1,357 1,424 1,343
=== ====== ====== ====== =====
<FN>
(1) Capacity and input amounts for El Paso represent Chevron's share.
(2) Refineries in Perth Amboy, New Jersey; and Portland, Oregon, which are
primarily asphalt plants. The Richmond Beach, Washington, plant ceased
operations in May 2000.
(3) Inputs for 1999 and 1998 include Koa Oil Co. Ltd. refineries. Interests sold in 1999. All capacities and inputs represent
Chevron's share of Caltex's equity interests in its affiliates.
</FN>
</TABLE>
Petroleum - Refined Products Marketing
Product Sales: The company and its Caltex Corporation affiliate market petroleum
products throughout much of the world. The principal trademarks for identifying
these products are "Chevron" and "Caltex." The company's Fuel and Marine
Marketing LLC (FAMM) affiliate, which was established in late 1998, markets
marine fuel and lubricating oils in approximately 100 countries worldwide.
Chevron has a 31 percent equity interest in FAMM.
The following table shows the company's and its affiliates' refined product
sales volumes, excluding intercompany sales, over the past three years. The
company's Canadian sales volumes consist of refined product sales, primarily in
British Columbia, by the company's Chevron Canada Limited subsidiary. The 2000
and 1999 volumes reported for "Other International" relate to international
sales of aviation and marine fuels, lubricants, gas oils and other refined
products, primarily in Latin America, Asia and Europe. The equity in affiliates'
sales consists of (1) the company's interest in Caltex, which maintains an
interest in about 7,800 service stations (of which about 4,700 are controlled by
Caltex), operating in more than 60 countries in the Asia-Pacific region, Africa
and the Middle East, and (2) the company's interest in FAMM.
-15-
<PAGE>
<TABLE>
<CAPTION>
Refined Products Sales Volumes
(Thousands of Barrels Per Day)
2000 1999 1998
--------- --------- --------
<S> <C> <C> <C>
United States
Gasolines 683 667 653
Jet Fuel 257 234 247
Gas Oils and Kerosene 231 236 198
Residual Fuel Oil 47 64 56
Other Petroleum Products(1) 109 101 89
--------- --------- --------
Total United States 1,327 1,302 1,243
--------- --------- --------
International
Canada 61 60 58
Other International 30 36 130
--------- --------- --------
Total International 91 96 188
--------- --------- --------
Total Consolidated Companies 1,418 1,398 1,431
Chevron's Share in Affiliates(2) 678 736 610
--------- --------- --------
Total Including Affiliates 2,096 2,134 2,041
========= ========= ========
<FN>
(1) Principally naphtha, lubes, asphalt and coke.
(2) 1999 and 1998 restated to conform to 2000 presentation
</FN>
</TABLE>
Retail Outlets: In the United States, the company supplies, directly or through
dealer and jobbers, more than 8,000 motor vehicle retail outlets, of which about
1,400 are company-owned or -leased stations, and about 600 aircraft and marine
retail outlets. The company's gasoline market area is concentrated in the
southern, southwestern and western states. According to the Lundberg Share of
Market Report, Chevron ranks among the top three gasoline marketers in 14
states, and is the top marketer of jet fuel and aviation gasoline in the western
United States.
The company has continued to take advantage of growing demand for convenience
goods and services. In 2000, non-fuel sales in company-operated stores increased
16 percent, compared with 1999.
In Canada - primarily British Columbia - the company's branded products are sold
in approximately 170 stations (mainly owned or leased).
-16-
<PAGE>
Petroleum - Transportation
Pipelines: Chevron owns and operates an extensive system of crude oil, refined
products, chemicals, natural gas liquids and natural gas pipelines in the United
States. The company also has direct or indirect interests in other U.S. and
international pipelines. The company's ownership interests in pipelines are
summarized in the following table:
<TABLE>
<CAPTION>
Pipeline Mileage At December 31, 2000
Wholly Partially
Owned Owned(1) Total
--------- -------- ---------
<S> <C> <C> <C>
United States:
Crude oil(2) 2,666 461 3,127
Natural gas 487 33 520
Petroleum products 2,059 1,738 3,797
--------- --------- --------
Total United States 5,212 2,232 7,444
--------- --------- --------
International:
Crude oil(2) - 481 481
Natural gas - 180 180
Petroleum products - 616 616
--------- --------- --------
Total International - 1,277 1,277
--------- --------- --------
Worldwide 5,212 3,509 8,721
========= ========= ===-====
<FN>
(1)Reflects equity interest in lines, except Dynegy Inc..
(2)Includes gathering lines related to the transportation function.
Excludes gathering lines related to the U.S. and international production
function.
</FN>
</TABLE>
Tankers: Chevron's controlled seagoing fleet at December 31, 2000, is summarized
in the following table. All controlled tankers were utilized in 2000. In
addition, at any given time, the company has 30 to 40 vessels under charter on a
term or voyage basis.
<TABLE>
<CAPTION>
Controlled Tankers At December 31, 2000
U.S. Flag Foreign Flag
----------------------------- ------------------------------
Cargo Capacity Cargo Capacity
Number (Millions of Barrels) Number (Millions of Barrels)
------ ------------------- ----- -------------------
<S> <C> <C> <C> <C>
Owned 2 0.8 10 13.7
Bareboat Charter 2 0.5 15 20.5
Time-Charter - - 1 0.5
-- ---- -- -----
Total 4 1.3 26 34.7
== ==== == =====
</TABLE>
Federal law requires that cargo transported between U.S. ports be carried in
ships built and registered in the United States, owned and operated by U.S.
entities and manned by U.S. crews. At year-end 2000, the company's U.S. flag
fleet was engaged primarily in transporting crude oil from Alaska to refineries
on the West Coast and Hawaii, refined products between the Gulf Coast and East
Coast, and refined products from California refineries to terminals on the West
Coast, Alaska and Hawaii.
The Federal Oil Pollution Act of 1990 requires the scheduled phase-out, by
year-end 2010, of all single hull tankers trading to U.S. ports or transferring
cargo in waters within the U.S. Exclusive Economic Zone. This has resulted in
the utilization of more costly double-hull tankers. By the end of 2000, Chevron
was operating a total of 16 double hull tankers. Chevron expects to take
delivery of two additional double-hull tankers in 2003, also to be operated
-17-
<PAGE>
under long-term bareboat charters. The company is a member of many oil-spill
response cooperatives in areas in which it operates around the world.
At year-end 2000, two of the company's controlled international flag vessels
continued to be used as floating storage vessels in its upstream operations
offshore Cabinda Province, Angola. The remaining international flag vessels were
engaged primarily in transporting crude oil from the Middle East, Indonesia,
Mexico and West Africa to ports in the United States, Europe, and Asia. Refined
products also were transported by tanker worldwide.
Chemicals
In July 2000, Chevron combined most of its petrochemicals businesses with those
of Phillips Petroleum Co. to form Chevron Phillips Chemical Company (CPCC),
headquartered in Houston, Texas. Each company owns 50 percent of the joint
venture. CPCC owns or has joint venture interests in 34 manufacturing facilities
in the United States, Belgium, China, Saudi Arabia, Singapore, South Korea and
Mexico.
In November 2000, CPCC began operation of a 100,000 tons-per-year polystyrene
plant in China. Also in 2000, CPCC and its joint-venture partner, the Saudi
Industrial Venture Capital Group, achieved design capacity production at a
petrochemical complex in Saudi Arabia with production of 480,000 tons of benzene
and 220,000 of cyclohexane.
An olefins plant is under construction in Qatar and is expected to commence
production in mid-2002 with an annual capacity of 1.1 billion pounds of ethylene
and 1 billion pounds of polyethylene. CPCC has a 49 percent interest in this
facility with the Qatar General Petroleum Corp owning the remaining 51 percent.
Following the merger with Phillips Petroleum Co., Chevron retained its "Oronite"
fuel and lubricant additives business. Chevron Oronite owns five manufacturing
facilities in the United States, France, Singapore, Japan and Brazil and has
equity interests in facilities in India and Mexico.
The following table shows 2000 Chemicals revenues and net income and details on
manufacturing facilities as of December 31, 2000.
<TABLE>
<CAPTION>
Chemicals Operations
Year ended December 31, 2000 At December 31, 2000
---------------------------- --------------------------------
Revenue* Net Income Manufacturing Facilities
($ Millions) ($ Millions) U.S. International
----------- ----------- --------------------------------
<S> <C> <C> <C> <C>
Consolidated operations $3,305 $ 163 1 4
Share of Affiliates (123) 23 13
---------
Total Income 40
========
<FN>
*Includes intercompany sales and excludes income from equity affiliates.
</FN>
</TABLE>
Coal
The Company's wholly owned coal mining and marketing subsidiary, The Pittsburg &
Midway Coal Mining Co. (P&M), owned and operated four surface mines and one
underground mine at year-end 2000. The Sebree Mine in Kentucky, which was idled
in November 1998, was sold in 2000. P&M also owns an approximate 30 percent
interest in Inter-American Coal Holding N.V., which has interests in mining
operations in Venezuela.
Sales and other operating revenues in 2000 were $297 million from sales of 14.0
million tons of coal. The average selling price for coal from mines owned and
operated by P&M was $21.22 per ton in 2000, compared with $22.73 per ton in
1999. Earnings in 2000 were affected negatively by a union work stoppage for
several months during the year and operating and geologic complications at
certain mines. At year-end 2000, P&M controlled approximately
-18-
<PAGE>
218 million tons of developed and undeveloped coal reserves, including
significant reserves of environmentally desirable low-sulfur fuel.
Electronic Commerce and Technology
In 1999, Chevron implemented a new growth initiative aimed at developing
business opportunities capitalizing on Internet Web technology. The company
established a subsidiary to leverage "e-business" opportunities in Chevron's
business units. Additionally, the new subsidiary is involved in the development
of new Internet "business to business" (B2B) ideas for use in the company's own
operations and for potential development with other outside investors.
Chevron also established a technology ventures unit during 1999. The company
makes equity investments in a broad portfolio of emerging technology companies
with expertise in information technology, materials sciences and biotechnology.
These investments are directed toward areas where the company could potentially
be a customer.
Because some of these investments in e-business and new ventures may be in new
or unproven technologies and business processes, ultimate success is not always
certain. Although not all initiatives may prove to be economically viable, the
company's overall investment in this area is not significant to the company's
consolidated financial position.
Research and Environmental Protection
Research: The company's principal research laboratories are in Richmond and San
Ramon, California and Houston, Texas. The Richmond facility engages in research
on new and improved refinery processes, develops petroleum and chemicals
products, and provides technical services for the company and its customers. The
San Ramon and Houston facilities conduct research and provide technical support
in geology, geophysics, and oil production methods such as hydraulics, assisted
recovery programs and drilling, including offshore drilling. Employees in
subsidiaries engaged primarily in research activities at year-end 2000 numbered
about 1,000. Chevron's research and development expenses were $171 million, $182
million and $187 million for the years 2000, 1999 and 1998, respectively.
Licenses under the company's patents are generally made available to others in
the petroleum and chemicals industries, but the company does not derive
significant income from licensing patents.
Environmental Protection: Virtually all aspects of the company's businesses are
subject to various federal, state and local environmental, health and safety
laws and regulations. These regulatory requirements continue to change and
increase in both number and complexity, and govern not only the manner in which
the company conducts its operations, but also the products it sells. Chevron
expects more environmental-related regulations in the countries where it has
operations. Most of the costs of complying with the myriad laws and regulations
pertaining to its operations are embedded in the normal costs of conducting its
business.
In 2000, the company's U.S. capitalized environmental expenditures were $171
million, representing approximately 7 percent of the company's total
consolidated U.S. capital and exploratory expenditures. The company's U.S.
capitalized environmental expenditures were $121 million and $192 million in
1999 and 1998, respectively. These environmental expenditures include capital
outlays to retrofit existing facilities, as well as those associated with new
facilities. The expenditures are predominantly in the petroleum segment and
relate mostly to air and water quality projects and activities at the company's
refineries, oil and gas producing facilities and marketing facilities. For 2001,
the company estimates U.S. capital expenditures for environmental control
facilities will be $179 million. The future annual capital costs of fulfilling
this commitment are uncertain and will be governed by several factors, including
future changes to regulatory requirements.
Further information on environmental matters and their impact on Chevron are
contained in Management's Discussion and Analysis of Financial Condition and
Results of Operation on page FS-4 of this Annual Report on Form 10-K. The
company's 2000 environmental expenditures, remediation provisions and year-end
environmental reserves are discussed on page FS-4 of this Annual Report on Form
10-K.
-19-
<PAGE>
Item 2. Properties
The location and character of the company's oil, natural gas and coal properties
and its refining, marketing, transportation and chemicals facilities are
described above under Item 1. Business. Information in response to the
Securities Exchange Act Industry Guide No. 2 ("Disclosure of Oil and Gas
Operations") is also contained in Item 1 and in Tables I through VI on pages
FS-33 to FS-38 of this Annual Report on Form 10-K. Note 14, "Properties, Plant
and Equipment," to the company's financial statements is on page FS-25 of this
Annual Report on Form 10-K. It presents information on the company's gross and
net properties, plant and equipment, and related additions and depreciation
expense, by geographic area and operating segment for 2000, 1999 and 1998.
Item 3. Legal Proceedings
A. El Segundo Refinery - Oil Spill Penalty
The Los Angeles Regional Water Quality Control Board has proposed an
administrative civil penalty for a jet fuel spill to groundwater resulting from
a leak in an underground pipeline at the Company's El Segundo Refinery. The
Company has remediated the spill and taken preventive steps to reduce the risk
of future spills.
B. El Paso Refinery - Clean Air Act
The Texas Natural Resources Conservation Commission and Chevron Products Company
have agreed to enter into an Agreed Order with respect to alleged air violations
at Chevron's El Paso Refinery. The alleged violations that are the subject of
the Agreed Order have been corrected and the Company has agreed to pay an
administrative civil penalty of $102,500.
C. Rangely Field - Clean Water Act
Chevron Production Company, as operator of the Rangely Unit, and its working
interest partners, have agreed to pay a $750,000 civil penalty associated with
alleged clean water act violations associated with produced water and crude oil
spills at the Rangely Production facility in northwestern Colorado. In addition,
the Company and its partners have committed to spend approximately $3 million in
facility upgrades to reduce the risk of spills from the injection line leaks.
Chevron's share of these expenditures will be 60 percent. Chevron and its
partners, the U.S. EPA and the Department of Justice have agreed to resolve the
matter through a consent decree, which will govern issues associated with the
injection line installation and leaks over the next five years.
D. Richmond Refinery - VOC Emissions
The Company has entered into a Settlement Agreement with the Bay Area Air
Quality Management District with respect to alleged violations of the air
district's fugitive VOC emission rules at the Company's Richmond Refinery. The
alleged violations involve emissions from connectors within the refinery. The
Company has agreed under the Settlement Agreement to pay a penalty of $242,500
and has agreed to surrender two tons per year of emission reduction credits for
volatile organic compounds.
E. Salt Lake Marketing Terminal - Air Emission Controls
The Utah Division of Air Quality has proposed a civil penalty in conjunction
with the loading of gasoline into tanker trucks without certain air emission
controls. The Company is negotiating with the Division to resolve all issues
relating to the alleged violations.
Other previously reported legal proceedings have been settled, not pursued, or
the issues resolved as not to merit further reporting.
Item 4. Submission of Matters to a Vote of Security Holders
No matter was submitted during the fourth quarter of 2000 to a vote of security
holders through the solicitation of proxies or otherwise.
-20-
<PAGE>
Executive Officers of the Registrant at March 1, 2001
Name and Age Executive Office Held Major Area of
Responsibility
- ------------------- ------------------------------ --------------------
D. J. O'Reilly 54 Chairman of the Board since 2000 Chief Executive Officer
Director since 1998
Executive Committee Member
since 1994
R. H. Matzke 64 Vice-Chairman of the Board Worldwide Exploration and
since 2000 and Production Activities
Director since 1997
President of Chevron Overseas
Petroleum Inc. from 1989 to 2000
Executive Committee Member
since 1993
D. W. Callahan 58 Executive Vice-President Chemicals, Coal,
since 2000 Human Resources,
Vice-President since 1999 Technology
President of Chevron Chemical
Company from 1999 to 2000
Executive Committee Member
since 1999
H. D. Hinman 60 Vice-President and Law
General Counsel since 1993
Executive Committee Member
since 1993
G.L. Kirkland 50 President of Chevron U.S.A. North American
Production Company since 2000 Exploration and
Executive Committee Member Production
since 2000
M. R. Klitten 56 Executive Vice-President Worldwide Refining,
since 2000 Marketing and
Vice-President since 1989 and Transportation
Executive Committee Member Activities,
since 1989 Global Procurement,
Real Estate,
Aircraft Services
P.J. Robertson 54 Vice-President since 1994 Overseas Exploration and
President of Chevron Overseas Production
Petroleum Inc. since 2000
Executive Committee Member
since 1997
J.S. Watson 44 Vice-President and Chief Finance
Financial Officer since 2000
Vice-President since 1998
Executive Committee Member
since 2000
P.A. Woertz 47 Vice-President since 1998 U.S. Refining, Marketing,
President of Chevron Products Logistics and Trading
Company since 1998
Executive Committee Member
since 1998
The Executive Officers of the Corporation consist of the Chairman of the Board,
the Vice-Chairman of the Board, and such other officers of the Corporation who
are either Directors or members of the Executive Committee, or are chief
executive officers of principal business units. Except as noted below, all of
the Corporation's Executive Officers have held one or more of such positions for
more than five years.
D.W. Callahan - Senior Vice President, Chevron Chemical Company - 1991
- President, Chevron Chemical Company - 1999
-21-
<PAGE>
G.L. Kirkland - General Manager, Asset Management, Chevron
Nigeria Limited - 1996
- Chairman and Managing Director, Chevron
Nigeria Limited - 1996
- President, Chevron USA Production Company - 2000
P.J. Robertson - Executive Vice-President of Chevron U.S.A.
Production Company - 1996
- Vice-President, Chevron Corporation and
President of Chevron U.S.A. Production Company - 1997
J.S. Watson - President, Chevron Canada Limited - 1996
- Vice-President, Strategic Planning, Chevron
Corporation - 1998
- Vice-President and Chief Financial Officer,
Chevron Corporation - 2000
P.A. Woertz - President, Chevron International Oil Company - 1996
- Vice President, Logistics and Trading,
Chevron Products Company - 1996
- President, Chevron Products Company - 1998
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
Matters
The information on Chevron's common stock market prices, dividends, principal
exchanges on which the stock is traded and number of stockholders of record is
contained in the Quarterly Results and Stock Market Data tabulations, on page
FS-11 of this Annual Report on Form 10-K.
Item 6. Selected Financial Data
The selected financial data for years 1996 through 2000 are presented on page
FS-39 of this Annual Report on Form 10-K.
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
The index to Financial Statements, Supplementary Data and Management's
Discussion and Analysis of Financial Condition and Results of Operations is
presented on page FS-1 of this Annual Report on Form 10-K.
Item 8. Financial Statements and Supplementary Data
The index to Financial Statements, Supplementary Data and Management's
Discussion and Analysis of Financial Condition and Results of Operations is
presented on page FS-1 of this Annual Report on Form 10-K.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None.
-22-
<PAGE>
PART III
Item 10. Directors and Executive Officers of the Registrant
The information on Directors appearing on pages 4 through 9 of the Notice of
Annual Meeting of Stockholders and Proxy Statement dated March 21, 2001, is
incorporated herein by reference in this Annual Report on Form 10-K. See
Executive Officers of the Registrant on pages 21 and 22 of this Annual Report on
Form 10-K for information about executive officers of the company.
Item 405 of Regulation S-K calls for disclosure of any known late filing or
failure by an insider to file a report required by Section 16 of the Exchange
Act. This disclosure is contained on page 12 of the Notice of Annual Meeting of
Stockholders and Proxy Statement dated March 21, 2001 under the heading "Section
16(a) Beneficial Ownership Reporting Compliance," and is incorporated herein by
reference in this Annual Report on Form 10-K. Chevron believes all filing
requirements were complied with during 2000.
Item 11. Executive Compensation
The information on pages 13 through 22 of the Notice of Annual Meeting of
Stockholders and Proxy Statement dated March 21, 2001, is incorporated herein by
reference in this Annual Report on Form 10-K.
Item 12. Security Ownership of Certain Beneficial Owners and Management
The information on page 12 of the Notice of Annual Meeting of Stockholders and
Proxy Statement dated March 21, 2001 appearing under the heading "Directors' and
Executive Officers' Stock Ownership," is incorporated herein by reference in
this Annual Report on Form 10-K.
Item 13. Certain Relationships and Related Transactions
There were no relationships or related transactions requiring disclosure under
Item 404 of Regulation S-K.
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
(a) The following documents are filed as part of this report:
(1) Financial Statements: Page(s)
Report of Independent Accountants FS-12
Consolidated Statement of Income
for the three years ended December 31, 2000 FS-12
Consolidated Statement of Comprehensive Income
for the three years ended December 31, 2000 FS-12
Consolidated Balance Sheet at December 31,
2000 and 1999 FS-13
Consolidated Statement of Cash Flows
for the three years ended December 31, 2000 FS-14
Consolidated Statement of Stockholders' Equity
for the three years ended December 31, 2000 FS-15
Notes to Consolidated Financial Statements FS-16 to FS-32
-23-
<PAGE>
(2) Financial Statement Schedules:
We have included on page 25 of this Annual report on Form 10-K,
Financial Statement Schedule II - Valuation and Qualifying
Accounts.
The Combined Financial Statements of the Caltex Group of Companies
are filed as part of this report.
Caltex Group of Companies Combined Financial Statements C-1 to C-20
All schedules for the Caltex Group are omitted because they are not
applicable or the required information is included in the combined
financial statements or notes thereto.
(3) Exhibits:
The Exhibit Index on pages 27 and 28 of this Annual Report on Form
10-K lists the exhibits that are filed as part of this report.
(b) Reports on Form 8-K:
(1) A Current Report on Form 8-K was filed by the company on December
21, 2000. In this report, Chevron announced a change in the
certifying accountant for the Chevron Profit Sharing/Savings Plan.
(2) A Current Report on Form 8-K was filed by the company on March 15,
2001. In this report, Chevron filed the company's 2000 audited
financial statements, Management's Discussion and Analysis of
Financial Condition and Results of Operations for 2000 and
Supplementary Data.
-24-
<PAGE>
<TABLE>
<CAPTION>
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS ($ MILLIONS)
Year ended December 31,
2000 1999 1998
----- ------ ------
<S> <C> <C> <C>
Employee Termination Benefits:
- -----------------------------
Balance at January 1 $ 85 $ - $ -
Additions charged to costs and expenses - 220 -
Expenditures (85) (135) -
--------------------------------
Balance at December 31 $ - $ 85 $ -
================================
Allowance for Doubtful Accounts:
- -------------------------------
Balance at January 1 $ 43 $ 31 $ 33
Additions to allowance 31 66 3
Bad debt write-offs (23) (54) (5)
--------------------------------
Balance at December 31 $ 51 $ 43 $ 31
================================
Deferred Income Tax Valuation Allowance (1)
- ---------------------------------------
Balance at January 1 $ 452 $ 295 $ 439
Additions charged to deferred income tax expense 56 189 4
Deductions credited to deferred income tax expense (193) (32) (148)
--------------------------------
Balance at December 31 $ 315 $ 452 $ 295
================================
<FN>
1 See also Note 15 to the consolidated financial statements on page FS-26.
</FN>
</TABLE>
-25-
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized, on the 28th day of March
2000.
Chevron Corporation
By DAVID J. O'REILLY*
-----------------------------------------
David J. O'Reilly, Chairman of the Board
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities indicated on the 28th day of March 2001.
Principal Executive Officers (And Directors) Directors
DAVID J. O'REILLY* SAMUEL H. ARMACOST*
- ---------------------------------------------- -------------------------------
David J. O'Reilly, Chairman of the Board Samuel H. Armacost
RICHARD H. MATZKE* SAM GINN *
- ---------------------------------------------- -------------------------------
Richard H. Matzke, Vice-Chairman of the Board Sam Ginn
CARLA A. HILLS *
-------------------------------
Carla A. Hills
J. BENNETT JOHNSTON*
-------------------------------
J. Bennett Johnston
CHARLES M. PIGOTT*
-------------------------------
Principal Financial Officer Charles M. Pigott
JOHN S. WATSON* FRANK A. SHRONTZ*
- ---------------------------------------------- -------------------------------
John S. Watson, Vice-President, Finance Frank A. Shrontz
and Chief Financial Officer
CARL WARE*
-------------------------------
Principal Accounting Officer Carl Ware
STEPHEN J. CROWE* JOHN A. YOUNG*
- ---------------------------------------------- -------------------------------
Stephen J. Crowe, Vice-President John A. Young
and Comptroller
*By: /s/ LYDIA I. BEEBE
---------------------------------------------------
Lydia I. Beebe, Attorney-in-Fact
-26-
<PAGE>
EXHIBIT INDEX
Exhibit
No. Description
- -------- ----------------------------------------------------------------------
3.1 Restated Certificate of Incorporation of Chevron Corporation,
dated November 23, 1998, filed as Exhibit 3.1 to Chevron
Corporation's Annual Report on Form 10-K for 1998 dated March 31,
1999, and incorporated by reference herein.
3.2 By-Laws of Chevron Corporation, as amended November 23, 1998, filed as
Exhibit 3.2 to Chevron Corporation's Annual Report on Form 10-K for
1998 dated March 31, 1999, and incorporated by reference herein.
4.1 Rights Agreement dated as of November 23, 1998, between Chevron
Corporation and ChaseMellon Shareholder Services L.L.C., as Rights
Agent, filed as Exhibit 4.1 to Chevron Corporation's Current Report on
Form 8-K dated November 23, 1998, and incorporated herein by
reference.
4.2 Amendment No. 1 to Rights Agreement dated as of October 15, 2000,
between Chevron Corporation and ChaseMellon Shareholder
Services L.L.C., as Rights Agent, filed as Exhibit 4.2 to Chevron
Corporation's Registration Statement on Form 8-A dated
December 7, 2000, and incorporated herein by reference.
Pursuant to the Instructions to Exhibits, certain instruments defining
the rights of holders of long-term debt securities of the corporation
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.
10.1 Chevron Corporation Deferred Compensation Plan for Directors, as
amended and restated effective January 1, 2001.
10.2 Management Incentive Plan of Chevron Corporation, as amended and
restated effective October 30, 1996, filed as Appendix B to Chevron
Corporation's Notice of Annual Meeting of Stockholders and Proxy
Statement dated March 21, 1997, and incorporated herein by reference.
10.3 Chevron Corporation Excess Benefit Plan, amended and restated as of
July 1, 1996, filed as Exhibit 10 to Chevron Corporation's Report on
Form 10-Q for the quarterly period ended March 31, 1997, and
incorporated herein by reference.
10.4 Chevron Restricted Stock Plan for Non-Employee Directors, as amended
and restated effective April 30, 1997, filed as Appendix A to Chevron
Corporation's Notice of Annual Meeting of Stockholders and Proxy
Statement dated March 21, 1997, and incorporated herein by reference.
10.5 Chevron Corporation Long-Term Incentive Plan, as amended and restated
effective October 30, 1996, filed as Appendix C to Chevron
Corporation's Notice of Annual Meeting of Stockholders and Proxy
Statement dated March 21, 1997, and incorporated herein by reference.
10.6 Chevron Corporation Salary Deferral Plan for Management Employees,
effective January 1, 1997, filed as Exhibit 10 to Chevron
Corporation's Report on Form 10-Q for the quarterly period ended June
30, 1997, and incorporated herein by reference.
10.7 Agreement and Plan of Merger dated as of October 15, 2000, among
Texaco Inc., Chevron Corporation and Keepep Inc., filed as Exhibit 2.1
to a Current Report on Form 8-K filed by the company on October 16,
2000 and an amended Current Report on Form 8-K filed by the company on
October 16, 2000.
10.8 Stock Option Agreement dated as of October 15, 2000 between Chevron
Corporation and Texaco Inc., filed as Exhibit 2.2 to a Current Report
on Form 8-K filed by the company on October 16, 2000 and an amended
Current Report on Form 8-K filed by the company on October 16, 2000.
-27-
<PAGE>
10.9 Stock Option Agreement dated as of October 15, 2000 between Chevron
Corporation and Texaco Inc., filed as Exhibit 2.3 to a Current Report
on Form 8-K filed by the company on October 16, 2000 and an amended
Current Report on Form 8-K filed by the company on October 16, 2000.
12.1 Computation of Ratio of Earnings to Fixed Charges (page E-1).
21.1 Subsidiaries of Chevron Corporation (page E-2).
23.1 Consent of PricewaterhouseCoopers LLP (page E-3).
23.2 Consent of KPMG (page E-4).
24.1 Powers of Attorney for directors and certain officers of
to Chevron Corporation, authorizing the signing of the Annual Report on
24.12 Form 10-K on their behalf.
99.1 Definitions of Selected Financial Terms (page E-5).
Copies of above exhibits not contained herein are available, at a fee of $2 per
document, to any security holder upon written request to the Secretary's
Department, Chevron Corporation, 575 Market Street, San Francisco, California
94105.
-28-
<PAGE>
INDEX TO MANAGEMENT'S DISCUSSION AND ANALYSIS
CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page(s)
Management's Discussion and Analysis FS-2 to FS-10
Quarterly Results and Stock Market Data FS-11
Report of Management FS-11
Report of Independent Accountants FS-12
Consolidated Statement of Income FS-12
Consolidated Statement of Comprehensive Income FS-12
Consolidated Balance Sheet FS-13
Consolidated Statement of Cash Flows FS-14
Consolidated Statement of Stockholders' Equity FS-15
Notes to Consolidated Financial Statements FS-16 to FS-32
Supplemental Information on Oil and Gas Producing Activities FS-33 to FS-38
Five-Year Financial Summary FS-39
FS-1
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
-----------------------------------------------------------
AND RESULTS OF OPERATIONS
-------------------------
2000 KEY INDICATORS
- -------------------
o Net income was $5.185 billion, the most profitable year in the company's
history
o Exploration and production operational earnings more than doubled to
$4.5 billion
o Average U.S. crude oil realization increased 69 percent to $27.20
per barrel
o Average U.S. natural gas realization was up 87 percent to $4.04 per
thousand cubic feet
o International net liquids production increased for the
11th consecutive year - up over 4 percent
o Worldwide net oil and gas reserve additions exceeded production for the
eighth consecutive year
o U.S. refining, marketing and transportation operational earnings doubled on
higher margins and improved plant reliability
o Annual dividends increased for the 13th consecutive year
<TABLE>
<CAPTION>
KEY FINANCIAL RESULTS
- ---------------------
Millions of dollars,
except per-share amounts ..................... 2000 1999 1998
- -----------------------------------------------------------------------------------------
<S> <C> <C> <C>
Net Income ................................. $ 5,185 $ 2,070 $ 1,339
Special Charges
Included in Net Income .................... (252) (216) (606)
--------------------------------------
Earnings, Excluding Special Items .......... $ 5,437 $ 2,286 $ 1,945
--------------------------------------
Per Share:
Net Income - Basic ...................... $ 7.98 $ 3.16 $ 2.05
- Diluted .................... $ 7.97 $ 3.14 $ 2.04
Dividends ............................... $ 2.60 $ 2.48 $ 2.44
Sales and
Other Operating Revenues .................. $50,592 $35,448 $29,943
Return on:
Average Capital Employed ................ 20.8% 9.4% 6.7%
Average Stockholders' Equity ............ 27.5% 11.9% 7.8%
=========================================================================================
</TABLE>
<TABLE>
<CAPTION>
NET INCOME BY MAJOR OPERATING AREA
- ----------------------------------
Millions of dollars 2000 1999 1998
- ---------------------------------------------------------------------
<S> <C> <C> <C>
Exploration and Production
United States* .................... $ 1,889 $ 482 $ 330
International ..................... 2,602 1,093 707
-----------------------------
Total Exploration and Production .. 4,491 1,575 1,037
-----------------------------
Refining, Marketing and Transportation
United States ..................... 549 357 572
International ..................... 104 74 28
-----------------------------
Total Refining, Marketing
and Transportation .............. 653 431 600
-----------------------------
Chemicals .......................... 40 109 122
All Other* ......................... 1 (45) (420)
-----------------------------
Net Income ......................... $ 5,185 $ 2,070 $ 1,339
=====================================================================
<FN>
*1999 and 1998 conformed for 2000 segment change to All Other for the company's
share of equity earnings in Dynegy Inc.
</FN>
</TABLE>
Chevron's record net income of $5.185 billion in 2000 was up significantly
over 1999 net income of $2.070 billion and 1998 net income of $1.339 billion.
Special charges in 2000 included asset write-downs, environmental remediation
reserve additions, prior-years' tax adjustments and litigation costs. Partially
offsetting these charges were gains from the equity accounting effect of the
issuance of additional common stock by the company's Dynegy equity affiliate,
asset sales, insurance recoveries for property damage, actuarial calculations
for the company's benefit plans and LIFO inventory adjustments. Net special
charges in 1999 included losses from asset write-downs, environmental
remediation provisions and restructuring charges, which were partially offset by
benefits from the sale of assets, LIFO inventory gains, and net favorable
adjustments for prior-years' taxes and litigation issues. In 1998, the net
special charges included a loss provision of $637 million for litigation,
substantially all of which pertained to a lawsuit against Gulf Oil Corporation
by Cities Service filed in 1982 - prior to the Chevron-Gulf merger in 1984.
Included in net income were foreign currency gains of $142 million in 2000,
and losses of $38 million in 1999 and $47 million in 1998.
Net income for the company's individual business segments is discussed in
the Results of Operations section.
ENVIRONMENT AND OUTLOOK
- ------------------------
Record earnings for Chevron in 2000 were largely the result of a
substantial improvement in crude oil and natural gas prices, along with higher
worldwide oil-equivalent production. Crude oil prices continued an upswing from
20-year lows that were experienced in late 1998. Natural gas prices - more
sensitive to regional supply-demand balances - rose to historic highs in the
U.S. spot market in late 2000. Capitalizing on these higher-price conditions,
the company increased its worldwide oil-equivalent production by 5 percent -
including the effect of volumes produced internationally under operating service
agreements, and adjusting for the effects of higher prices on Chevron's share of
net production under production-sharing contracts and variable royalty
arrangements.
The average spot price in 2000 for West Texas Intermediate (WTI), a
benchmark crude oil, was $30.34 per barrel, up nearly 60 percent from $19.30 per
barrel in 1999 and more than double the 1998 average price. The average U.S.
Henry Hub spot natural gas price of $4.23 per thousand cubic feet increased 86
percent, compared with the 1999 average of $2.27, and was more than twice the
1998 level. The sharp rise in crude oil prices was primarily the result of the
1999 agreement among certain OPEC and non-OPEC oil producing countries to
restrict production, as well as increased demand and lower petroleum inventories
worldwide. Higher U.S. natural gas prices reflected a strengthened economy and
sharply increased demand for natural gas from power generators, at the same time
North American natural gas producers struggled to increase supply and maintain
inventory levels.
Although down from their highs in 2000, crude oil and natural gas prices
remained strong in early 2001. In mid- February 2001, the price of WTI was about
$30 per barrel. The Henry Hub spot natural gas price that peaked at $10.50 per
thousand cubic feet in late December 2000 fell below $6.00 per thousand cubic
feet by mid-February. It is uncertain how long these price levels will continue.
Some factors
FS-2
<PAGE>
that may affect future price changes include fluctuations in crude oil
production by producing countries, unforeseen supply disruptions, increases or
decreases in worldwide inventory levels, changes in demand for heating oil and
natural gas as a result of winter weather conditions, electricity generating
requirements, and the demand for refined products reflecting the overall
strength of the world economies. High crude oil and natural gas prices enhance
the company's revenues and earnings in exploration and production operations.
However, these same conditions could adversely affect financial results in the
refining and marketing and the chemicals businesses if the higher feedstock
costs cannot be recovered through sufficient product price increases.
Chevron's U.S. downstream margins and earnings improved substantially in
2000, despite higher crude oil feedstock costs and fuel expense for the
company's refineries. Earnings in the future will depend on refined products
margins in Chevron's primary U.S. operating areas- the West Coast, the South and
the South-west- and on safe, reliable refining operations. Internationally,
Caltex operations in the Asia-Pacific region continued to suffer from weak
refined products margins, resulting from surplus refining capacity, higher
feedstock costs and a highly competitive environment. Caltex may continue to be
adversely affected by these conditions throughout 2001.
The outlook for the company's chemicals businesses remains uncertain
because of fluctuating feedstock costs, depressed demand and excess capacity
conditions for commodity chemicals. While results early in 2000 benefited from
price increases for certain products, the industry experienced a weakening of
margins in the second half of the year. The company expects these conditions to
continue in 2001.
For the company as a whole in 2000, strong operating cash flows and a
continued focus on cost control- mitigating the effect of higher operating
expenses from increased fuel and utility costs- helped enable a 16 percent
increase in the 2001 capital budget to $6 billion. Profitable growth from such a
robust capital spending program is linked, among other things, to the company's
continued success in operating safely and achieving excellence in stewardship
over the company's global portfolio of world-class capital investment
opportunities.
CHEVRON-TEXACO MERGER AGREEMENT
- --------------------------------
Chevron and Texaco announced in October 2000 an agreement to combine the
two companies into an integrated global energy company. Upon approval by
regulatory authorities and stockholders of both companies, and fulfillment of
other conditions, Chevron will issue 0.77 of its common shares for each share of
Texaco common stock. The new company- ChevronTexaco Corporation- will have
significantly enhanced positions in upstream and downstream operations, a global
chemicals business, a growth platform in power generation, and industry-leading
skills in technology innovation. Synergistic annual savings of at least $1.2
billion are expected within six to nine months of the merger.
Chevron and Texaco anticipate that the U.S. Federal Trade Commission (FTC)
will require asset dispositions as a condition of not challenging the merger.
While the scope and method of such dispositions were unknown in late February,
the companies anticipated that divestiture of certain U.S. refining, marketing
and transportation businesses would be required to address market concentration
issues. Merger-related fees and expenses, consisting primarily of U.S.
Securities and Exchange Commission (SEC) filing fees; fees and expenses of
investment bankers, attorneys and accountants; and financial printing and other
related charges are estimated at $125 million for both companies. Substantially
all of these costs will be incurred in 2001.
Though not yet fully quantified, significant costs also will be incurred
after the merger for integration-related expenses, including the elimination of
duplicate facilities, operational realignment and severance payments for
work-force reductions.
The merger agreement provides for the payment of termination fees of as
much as $1 billion by either party under certain circumstances. Chevron and
Texaco also were granted options to purchase shares of the other, under the same
conditions as the payments of the termination fees. Texaco granted Chevron an
option to purchase 107 million shares of Texaco's common stock, at $53.71 per
share. Chevron granted Texaco an option to purchase 127 million shares of
Chevron's common stock, at $85.96 per share.
OTHER SIGNIFICANT DEVELOPMENTS
- -------------------------------
Key operating highlights and events during 2000 and early 2001 to capture
profitable growth opportunities included:
Tengiz - Tengizchevroil's (TCO) total gross crude oil production averaged
over 280,000 barrels per day in the fourth quarter 2000 - a record and exceeding
the target of 260,000 barrels per day - as a result of processing plant
expansion and the absence of turnaround work. For 2001, average gross production
is expected to be about 260,000 barrels per day, considering the effect of
planned shutdowns for maintenance and other operational activities. In January
2001, Chevron closed on its purchase of an additional 5 percent share in TCO,
bringing the company's ownership interest to 50 percent. As a result of the
purchase, Chevron will record an additional 177 million barrels of
oil-equivalent reserves in 2001.
Caspian Pipeline - Construction of a pipeline by the Caspian Pipeline
Consortium (CPC), in which Chevron owns a 15 percent interest, remains on
schedule for a mid-2001 start-up. The 900-mile pipeline will connect the Tengiz
Field in western Kazakhstan to the Black Sea port of Novorossiysk. This pipeline
will provide a less costly transportation alternative for the export of TCO's
crude oil production.
Angola - Chevron made two significant new oil discoveries - Tomboco and
Lobito - in deepwater Block 14, where the company is operator and has a 31
percent ownership interest. While development plans for the two new discoveries
are in the early stages, Tomboco and Lobito provide potential synergies with the
development of two other Block 14 discoveries, Benguela and Belize.
Chad-Cameroon - Chevron, with a 25 percent interest, and its partners began
the development of the Doba oil fields in southern Chad and construction of a
650-mile pipeline from the fields to marine export facilities on the coast of
Cameroon. This project is expected to cost $3.5 billion to develop and have a
20- to 30-year life. First production is expected in 2004.
Nigeria - Chevron was awarded interests in three deepwater oil prospecting
licenses (OPL) offshore Nigeria. Chevron, with a 50 percent interest, will serve
as operator of OPL 250. The company also was awarded 30 percent nonoperating
interests in OPL 214 and OPL 318. Work also continues on the initiative to
convert natural gas into clean petroleum fuels
FS-3
<PAGE>
and to significantly reduce the amount of flared natural gas at the company's
producing operations. A gas-to-liquids facility, which will combine the
technologies from Sasol Limited and Chevron, will be built adjacent to existing
operations at Escravos.
Thailand - The government of Thailand approved Chevron's plan for the
development of North Jarmjuree, a 200-square-mile offshore production area
located in Block B8/32. North Jarmjuree is the fourth production area granted
within Block B8/32, which also includes the Tantawan, Benchamas and Maliwan
fields. Chevron is operator and holds a 52 percent interest in Block B8/32.
Canada - Chevron, as operator with a 43 percent interest, and its partners
began production of natural gas from two wells at Fort Liard, Northwest
Territories. Combined production is expected to average about 105 million cubic
feet per day of natural gas and byproducts in 2001. Construction also began on
the mining, extraction and upgrading facilities for the Athabasca Oil Sands
Project, in which Chevron has a 20 percent interest. The project is expected to
begin production in late 2002 and reach 155,000 barrels of bitumen per day at
its peak.
U.S. Gulf of Mexico - Two additional fields in the Viosca Knoll Carbonate
Trend began producing a combined 106 million cubic feet of natural gas per day
in November 2000. Chevron is the largest contiguous leaseholder in the Carbonate
Trend, holding a majority interest in 54 leases.
Oil and Gas Reserves Replacement - The company added 875 million barrels of
oil-equivalent reserves during 2000, or 152 percent of production for the year,
including the effects of sales and acquisitions. Among the major additions were
about 130 million barrels each for the Tengiz Field in Kazakhstan and the Chad
acquisition. More than 175 million barrels of the total amount were the result
of successful discoveries in areas that included Thailand, Argentina, Nigeria,
Angola, the United Kingdom and the U.S. Gulf of Mexico Shelf.
Chevron Phillips Chemical Company - Effective July 1, 2000, Chevron and
Phillips Petroleum Company (Phillips) formed Chevron Phillips Chemical Company
LLC (CPCC), a 50-50 joint venture that combined most of the companies'
petrochemicals businesses. At year-end 2000, CPCC had total assets of $6.7
billion.
ENVIRONMENTAL MATTERS
- ----------------------
Virtually all aspects of the businesses in which the company engages are
subject to various federal, state and local environmental, health and safety
laws and regulations. These regulatory requirements continue to increase in both
number and complexity and govern not only the manner in which the company
conducts its operations, but also the products it sells. Most of the costs of
complying with laws and regulations pertaining to company operations and
products are embedded in the normal costs of doing business.
Accidental leaks and spills requiring cleanup may occur in the ordinary
course of business. In addition to the costs for environmental protection
associated with its ongoing operations and products, the company may incur
expenses for corrective actions at various owned and previously owned facilities
and at third-party waste-disposal sites used by the company. An obligation may
arise when operations are closed or sold, or at non-Chevron sites where company
products have been handled or disposed of. Most of the expenditures to fulfill
these obligations relate to facilities and sites where past operations followed
practices and procedures that were considered acceptable at the time but now
require investigative and/or remedial work to meet current standards.
Using definitions and guidelines established by the American Petroleum
Institute, Chevron estimated its worldwide environmental spending in 2000 at
$910 million for its consolidated companies. Included in these expenditures were
$212 million of environmental capital expenditures and $698 million of costs
associated with the control and abatement of hazardous substances and pollutants
from ongoing operations. For 2001, total worldwide environmental capital
expenditures are estimated at $264 million. These capital costs are in addition
to the ongoing costs of complying with environmental regulations and the costs
to remediate previously contaminated sites.
The following table analyzes the annual changes to the company's before-tax
environmental remediation reserves, including those for Superfund sites. For
2000, the company recorded additional provisions for estimated remediation costs
at refined products marketing sites, chemicals manufacturing facilities, and
various owned and previously owned refining facilities.
<TABLE>
<CAPTION>
Millions of dollars 2000 1999 1998
- ---------------------------------------------------------
<S> <C> <C> <C>
Balance at January 1 $ 814 $ 826 $ 987
Expense Provisions 336 219 73
Expenditures (195) (231) (234)
- ---------------------------------------------------------
Balance at December 31 $ 955 $ 814 $ 826
=========================================================
</TABLE>
Under provisions of the Superfund law, the Environmental Protection Agency
(EPA) has designated Chevron a potentially responsible party, or has otherwise
involved the company, in the remediation of 315 hazardous waste sites. The
company has made expense provisions or payments in 2000 and prior years for
approximately 223 of these sites. No single site is expected to result in a
material liability for the company. For the remaining sites, investigations are
not yet at a stage where the company is able to quantify a probable liability or
determine a range of reasonably possible exposures. The Superfund law provides
for joint and several liability. Any future actions by the EPA and other
regulatory agencies to require Chevron to assume other potentially responsible
parties' costs at designated hazardous waste sites are not expected to have a
material effect on the company's consolidated financial position or liquidity.
Remediation reserves at year-end 2000, 1999 and 1998 for Superfund sites were
$32 million, $33 million and $44 million, respectively.
It is likely that the company will continue to incur additional
liabilities, beyond those recorded, for environmental remediation relating to
past operations. These future costs are indeterminable 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. While the amount of future
costs may be material to the company's results of operations in the period in
which they are recognized, the company does not expect these costs to have a
material effect on its consolidated financial position or liquidity. Also, the
company does not believe its obligations to make such expen-
FS-4
<PAGE>
ditures have had, or will have, any significant impact on the company's
competitive position relative to other petroleum or chemical companies.
The company maintains additional reserves for dismantlement, abandonment
and restoration of its worldwide oil and gas and coal properties at the end of
their productive lives. Many of these costs are related to environmental issues.
Expense provisions are recognized on a unit-of-production basis. The amount of
these reserves at year-end 2000 was $1.5 billion and is included in accumulated
depreciation, depletion and amortization in the company's consolidated balance
sheet.
For the company's other ongoing operating assets, such as refineries and
chemicals facilities, no provisions are made for exit or cleanup costs that may
be required when such assets reach the end of their useful lives, unless a
decision to sell or otherwise abandon the facility has been made.
LITIGATION AND OTHER UNCERTAINTIES
- ----------------------------------
Chevron and five other oil companies filed suit in 1995 contesting the
validity of a patent granted to Unocal Corporation for reformulated gasoline,
which Chevron sells in California in certain months of the year. In March 2000,
the U.S. Court of Appeals for the Federal Circuit upheld a September 1998
District Court decision that Unocal's patent was valid and enforceable and
assessed damages of 5.75 cents per gallon for gasoline produced in infringement
of the patent. In May 2000, the Federal Circuit Court denied a petition for
rehearing with the U.S. Court of Appeals for the Federal Circuit filed by
Chevron and the five other defendants in this case. The defendant companies
petitioned the U.S. Supreme Court in August 2000 for the case to be heard. In
February 2001, the Supreme Court denied the petition to review the lower court's
ruling. The defendants are pursuing other legal alternatives to have Unocal's
patent ruled invalid.
If Unocal's patent ultimately is upheld, the company's financial exposure
includes royalties, plus interest, for production of gasoline that is proved to
have infringed the patent. As a result of the March 2000 ruling, the company
recorded a special after-tax charge of $62 million. The majority of this charge
pertained to the estimated royalty on gasoline production in the early part of a
four-year period ending December 31, 1999 - before Chevron modified its
manufacturing processes to minimize the production of gasoline that allegedly
infringed on Unocal's patented formulations. Subsequently, the company has been
accruing in the normal course of business any future estimated liability for
potential infringement of the patent covered by the trial court's ruling. In
June 2000, Chevron paid $22.7 million to Unocal - $17.2 million for the original
court judgment for California gasoline produced in violation of Unocal's patent
from March through July 1996 and $5.5 million of interest and fees. Unocal has
obtained additional patents for alternate formulations that could affect a
larger share of U.S. gasoline production. Chevron believes these additional
patents are invalid and unenforceable. However, if such patents ultimately are
upheld, the competitive and financial effects on the company's refining and
marketing operations, while presently indeterminable, could be material.
Another issue involving the company is the ongoing public debate concerning
the petroleum industry's use of MTBE and its potential environmental impact
through seepage into groundwater. Along with other oil companies, the company is
a party to lawsuits and claims related to the use of the chemical MTBE in
certain oxygenated gasolines. These actions may require the company to correct
or ameliorate the alleged effects on the environment of prior disposal or
release of MTBE by the company or other parties. Additional lawsuits and claims
related to the use of MTBE may be filed in the future. Costs to the company
related to these lawsuits and claims are not currently determinable. Chevron has
eliminated the use of MTBE in gasoline it sells in certain areas.
Chevron also receives claims from and submits claims to customers, trading
partners, host governments, contractors, insurers and suppliers. The company is
also party to numerous other lawsuits. In some of these matters, plaintiffs and
claimants may seek to recover large and sometimes unspecified amounts. In
others, they may seek to have the company perform specific activities, including
remediation of alleged damages. These matters may remain unresolved for several
years, and it is not practical to estimate a range of possible loss. Although
losses or gains could be material to earnings in any given period, management
believes that resolution of these matters will not materially affect the
company's consolidated financial position or its liquidity.
At year-end 2000, the value of the assets of the company's main U.S.
pension plan exceeded the projected pension obligations by $657 million. This
excess can be attributable to higher than expected returns on the investment of
the plan assets over the past several years. If investment returns decline in
the future and are insufficient to offset increases in the plan's obligations,
pension expense may increase and additional funding may be required.
Company operations, particularly exploration and production, can be
affected by other changing economic, regulatory and political environments in
the various countries in which it operates, including the United States. In
certain locations, host governments have imposed restrictions, controls and
taxes, and in others, political conditions have existed that may threaten the
safety of employees and the company's continued presence in those countries.
Internal unrest or strained relations between a host government and the company
or other governments may affect the company's operations. Those developments
have, at times, significantly affected the company's related operations and
results, and are carefully considered by management when evaluating the level of
current and future activity in such countries. Areas in which the company has
significant operations include the United States, Canada, Australia, the United
Kingdom, Norway, Republic of Congo, Angola, Nigeria, Chad, Equatorial Guinea,
Democratic Republic of Congo, Papua New Guinea, China, Thailand, Venezuela,
Argentina and Brazil. The company's Caltex affiliates have significant
operations in Indonesia, Korea, Australia, Thailand, the Philippines, Singapore
and South Africa. The company's Tengizchevroil affiliate operates in Kazakhstan.
The company's Dynegy affiliate has operations in the United States, Canada, the
United Kingdom and other European countries.
The company and its affiliates 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.
For oil and gas producing operations, ownership agreements may provide for
periodic reassessments of equity interests in estimated oil and gas reserves.
These activities, individually or together, may result in gains or losses that
could be material to earnings in any given period.
FS-5
<PAGE>
FINANCIAL INSTRUMENTS
- ----------------------
The company utilizes various derivative instruments, principally swaps and
futures, to manage its exposure to price risk stemming from its integrated
petroleum activities. All these instruments are commonly used in oil and gas
trading activities and involve little complexity. (See Note 9 to the
consolidated financial statements for further details.) Most of the activity in
these instruments is intended to hedge physical transactions. 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. Its
control systems are designed to monitor and manage its financial exposures in
accordance with company policies and procedures.
NEW ACCOUNTING STANDARDS
- -------------------------
The company adopted The Financial Accounting Standards Board (FASB)
Statement No. 133, "Accounting for Derivative Instruments and Hedging
Activities" (FAS 133), as amended by FAS 138, "Accounting for Certain Derivative
Instruments and Certain Hedging Activities - An Amendment of FASB Statement No.
133," effective January 1, 2001. Because of Chevron's limited use of derivative
instruments (as described above), the company has elected not to account for its
derivative instruments as hedges. Accordingly, upon adoption the fair values of
the derivative instruments will be recorded as assets or liabilities on the
balance sheet, and changes in fair values of these instruments beyond normal
sales and purchases will be reflected in current income. The company may elect
to apply hedge accounting, which has different financial statement effects, to
possible future transactions involving derivative instruments, if significant.
Such an election would reduce earnings volatility that might otherwise result if
changes in fair values were recognized in current income. The adoption of FAS
133 and FAS 138 did not have a significant impact on the company's results of
operations or financial position.
In September 2000, the FASB issued Statement No. 140, "Accounting for
Transfers and Servicing of Financial Assets and Extinguishments of Liabilities -
A Replacement of FASB Statement No. 125" (FAS 140). FAS 140 is effective for
transfers occurring after March 31, 2001, and for disclosures relating to
securitization transactions and collateral for fiscal years ending after
December 15, 2000. FAS 140 has no significant effect on Chevron's accounting or
disclosures for the types of transactions in the scope of the new standard.
EMPLOYEE TERMINATION BENEFITS AND OTHER RESTRUCTURING COSTS
- -----------------------------------------------------------
In 1999, the company implemented a staff reduction program in all of its
operating segments across several business functions and accrued $220 million
before tax for severance and other termination benefits for approximately 3,500
employees. Employees affected were primarily U.S.-based. All employee
terminations were completed by June 30, 2000, and no significant adjustments
were required for amounts previously accrued. Termination benefits for
approximately 3,100 of the 3,500 employees were payable from the assets of the
company's U.S. and Canadian pension plans. Most of the future savings connected
with this program relate to the termination and relocation of U.S.-based
employees.
RESULTS OF OPERATIONS
- ---------------------
Sales and other operating revenues were $50.6 billion in 2000, compared
with $35.4 billion in 1999 and $29.9 billion in 1998. Revenues for 2000 and 1999
increased on sharply higher prices for crude oil, natural gas and refined
products. The 2000 revenue increase was offset partially by the absence of
chemicals revenues in the second half of the year due to the July 1 formation of
the Chevron Phillips joint venture, which is accounted for under the equity
method.
Income from equity affiliates totaled $750 million in 2000, $526 million in
1999 and $228 million in 1998. Changes in earnings from Tengizchevroil and
Caltex were the primary cause of the fluctuations between years. In 2000,
increases in earnings from Tengizchevroil, Caltex and Dynegy were offset
partially by losses from the Chevron Phillips joint venture.
Other income totaled $787 million in 2000, $612 million in 1999 and $386
million in 1998. The fluctuations between years were the result of changes in
net gains from asset sales and interest income from investments.
Purchased crude oil and products costs in 2000 were 52 percent higher than
in 1999 and 94 percent higher than in 1998 because of higher prices for crude
oil, natural gas, refined products and chemicals feedstock. Prices fell
precipitously in 1998 and did not begin to recover until the second quarter
1999. Offsetting some of the effect of higher prices in 2000 was the absence of
costs as a result of the Chevron Phillips joint venture formation.
Operating, selling, general and administrative expenses, excluding the
effects of special items, increased to $6,487 million- from $6,169 million in
1999 and $6,251 million in 1998- primarily due to higher fuel costs. Mitigating
this effect
<TABLE>
<CAPTION>
Millions of dollars 2000 1999 1998
- ----------------------------------------------------------------
<S> <C> <C> <C>
Operating Expenses $5,177 $5,090 $4,834
Selling, General and
Administrative Expenses 1,725 1,404 2,239
- ----------------------------------------------------------------
Total Operating Expenses 6,902 6,494 7,073
Less: Special Charges, Before Tax 415 325 822
- ----------------------------------------------------------------
Adjusted Total Operating Expenses $6,487 $6,169 $6,251
================================================================
</TABLE>
was the absence of expenses associated with the chemicals operations contributed
to the Chevron Phillips joint venture.
Exploration expenses of $564 million in 2000 were $26 million, or 5 percent
higher than 1999, and $86 million, or 18 percent higher than 1998. In 2000,
increased drilling in the deepwater U.S. Gulf of Mexico led to a doubling of
well write-offs for U.S. operations. This increase more than offset declines in
international operations. Compared with 1998, both U.S. and international well
write-offs in 1999 were significantly higher.
Depreciation, depletion and amortization expense was $2,848 million in
2000, compared with $2,866 million in 1999 and $2,320 million in 1998.
Depreciation expense associated with asset impairments in 2000 was $138 million,
compared with $394 million in 1999 and $100 million in 1998. Increased
production of crude oil and natural gas in 2000 and 1999 resulted in higher
depreciation expense in the company's worldwide upstream operations. The overall
2000 expense reflects lower depreciation in chemicals (resulting from the
Chevron Phillips joint venture formation) and other operations.
Income tax expenses were $4,085 million in 2000, $1,578 million in 1999 and
$495 million in 1998, reflecting effective income tax rates of 44 percent, 43
percent and 27 percent for each of the three years, respectively. The increase
in the 2000 effective tax rate was primarily the result of lower
FS-6
<PAGE>
after-tax earnings from equity affiliates as a proportion of before-tax income,
the absence of tax benefits attributable to the 1999 utilization of capital
losses and a decline in U.S. tax credits as a proportion of before-tax income.
Partially offsetting these factors in 2000 were lower foreign income taxes as a
percentage of income and a reduction in the impact of prior- year tax
adjustments.
The increase in the 1999 effective tax rate, compared with 1998, reflected
a higher proportion of earnings from international operations that were taxed at
higher rates; a lower beneficial impact from prior-period tax adjustments,
settlement of outstanding issues, and permanent differences in 1999; and lower
tax credits as a proportion of before-tax income. These factors were offset
slightly by the effect of lower taxes on taxable income received from equity
affiliates in 1999.
Foreign currency gains in 2000 were $142 million, compared with losses of
$38 million in 1999 and $47 million in 1998. During most of 2000, the U.S.
dollar strengthened against the currencies of a number of countries -
particularly Australia, the United Kingdom, Norway, Canada and certain countries
in the Caltex operating area - before weakening late in the year. In 1999, the
company's foreign exchange
<TABLE>
<CAPTION>
SELECTED OPERATING DATA 2000 1999 1998
- ----------------------------------------------------------
<S> <C> <C> <C>
U.S. EXPLORATION AND PRODUCTION
Net Crude Oil and Natural Gas
Liquids Production (MBPD) ....... 312 316 325
Net Natural Gas
Production (MMCFPD) ............. 1,558 1,639 1,739
Natural Gas Sales (MMCFPD) (1).... 3,448 3,162 3,303
Natural Gas Liquids Sales (MBPD)(1) 153 133 130
Revenues from Net Production
Crude Oil ($/Bbl) ............... $27.20 $16.11 $11.42
Natural Gas ($/MCF) ............. $ 4.04 $ 2.16 $ 2.02
INTERNATIONAL EXPLORATION
AND PRODUCTION(1)
Net Crude Oil and Natural Gas
Liquids Production (MBPD) ....... 847 811 782
Net Natural Gas
Production (MMCFPD) ............. 911 874 654
Natural Gas Sales (MMCFPD) ....... 1,813 1,774 1,504
Natural Gas Liquids Sales (MBPD) . 65 57 53
Revenues from Liftings
Liquids ($/Bbl) ................. $27.12 $17.31 $11.77
Natural Gas ($/MCF) ............. $ 2.45 $ 1.87 $ 1.94
Other Produced Volumes (MBPD) (2) 123 96 95
U.S. REFINING, MARKETING
AND TRANSPORTATION
Gasoline Sales (MBPD) ............. 683 667 653
Other Refined Products Sales (MBPD) 644 635 590
Refinery Input (MBPD) ............. 943 955 869
Average Refined Products
Sales Price ($/Bbl) ............. $39.32 $26.86 $22.37
INTERNATIONAL REFINING,
MARKETING AND TRANSPORTATION(1)
Refined Products Sales (MBPD) (3). 769 832 798
Refinery Input (MBPD) ............ 415 469 475
==========================================================
<FN>
MBPD = Thousands of barrels per day; MMCFPD = Millions of cubic feet per day;
Bbl = Barrel; MCF = Thousands of cubic feet.
(1) Includes equity in affiliates.
(2) Represents total field production under the Boscan operating service
agreement in Venezuela, and in 2000 included a Colombian operating service
agreement.
(3) 1999 restated to conform to 2000 presentation.
</FN>
</TABLE>
losses occurred primarily in the company's operations in Canada and Australia
and in the Australian operations of Caltex. The most significant losses in 1998
were in Caltex's operations in Korea, Thailand and Japan.
U.S. exploration and production earnings in 2000 and 1999, excluding
special items, were driven by sustained increases in crude oil and natural gas
prices that began in early 1999. Expenses were higher in 2000, primarily for
well write-offs, production-related taxes and operating expenses- largely
associated with higher fuel costs. Gains from asset sales were lower than in
1999 and 1998.
The company's average 2000 U.S. crude oil realization of $27.20 per barrel
was $11.09 higher than in 1999 and $15.78
<TABLE>
<CAPTION>
U.S. Exploration and Production
- ------------------------------
Millions of dollars 2000 1999* 1998*
- --------------------------------------------------------------------------
<S> <C> <C> <C>
Earnings, Excluding Special Items $1,939 $ 774 $ 346
------------------------------------------------------------------------
Asset Write-Offs and Revaluations (50) (204) (44)
Asset Dispositions .................. - 3 47
Environmental Remediation Provisions - (23) 26
Restructurings and Reorganizations .. - (42) -
Other ............................... - (26) (45)
----------------------------
Total Special Items ................. (50) (292) (16)
----------------------------
Segment Income ...................... $1,889 $ 482 $ 330
==========================================================================
<FN>
*Conformed to 2000 presentation; equity earnings from Dynegy Inc. included in
All Other.
</FN>
</TABLE>
higher than 1998. The 2000 average U.S. natural gas realization was $4.04 per
thousand cubic feet, $1.88 higher than in 1999 and double the prices in 1998.
Net liquids production for the year averaged 312,000 barrels per day, down
1 percent from 1999 and 4 percent from 1998. Net natural gas production in 2000
averaged 1.558 billion cubic feet per day, down 5 percent from 1999 and 10
percent from 1998. The lower oil-equivalent production reflected normal field
declines and asset sales, partially offset by new and enhanced production in the
Gulf of Mexico deep water and other areas of the gulf. The decline in U.S.
production in 2000 was mitigated by accelerating capital spending for
fast-payout well workovers and development drilling projects that increased
production and took advantage of the favorable price environment.
<TABLE>
<CAPTION>
International Exploration and Production
- ----------------------------------------
Millions of dollars 2000 1999 1998
- -----------------------------------------------------------------
<S> <C> <C> <C>
Earnings, Excluding Special Items $2,600 $1,156 $ 717
---------------------------------------------------------------
Asset Write-Offs and Revaluations - (37) (6)
Asset Dispositions ............. - 17 (56)
Prior-Year Tax Adjustments ..... - (23) 56
Restructurings and Reorganizations - (21) -
LIFO Inventory Gains and Other . 2 1 (4)
---------------------------
Total Special Items ............ 2 (63) (10)
---------------------------
Segment Income ................. $ 2,602 $ 1,093 $ 707
=================================================================
</TABLE>
International exploration and production earnings, excluding special items,
improved in 2000 and 1999 on higher crude oil and natural gas prices and
steadily increasing production.
Chevron's average liquids realization, including equity affiliates, was
$27.12 per barrel in 2000, compared with $17.31 per barrel in 1999 and $11.77
per barrel in 1998. The average natural gas realization was $2.45 per thousand
cubic feet in 2000, compared with $1.87 in 1999 and $1.94 in 1998.
FS-7
<PAGE>
Net liquids production of 847,000 barrels per day in 2000 increased 4
percent from 811,000 barrels per day in 1999 and 8 percent from 1998. Production
increases in Argentina, Angola, Australia and Thailand in 2000 more than offset
lower volumes from Indonesia and Colombia. In 1999, increases in Angola and
Kazakhstan, combined with production from properties acquired in Argentina and
Thailand, offset declines in Australia, Indonesia and Nigeria.
Net natural gas production of 911 million cubic feet in 2000 was up 4
percent from 1999 and nearly 40 percent from 1998. In 2000, production increases
were primarily in Argentina and Thailand, partially offset by sharply lower
production in Canada, due primarily to normal declines in mature fields.
Increases in 1999 were from the Britannia Field in the United Kingdom, as well
as from new production from the properties acquired in Thailand and Argentina.
For 11 consecutive years through 2000, international production volumes and
proved reserve quantities increased, reflecting the company's strategy of
expanding its international upstream operations. Oil-equivalent production in
2000 increased over 9 percent- including volumes produced under various
international operating service agreements, and adjusting for the effects of
higher prices on Chevron's share of net production under production-sharing
contracts and variable royalty arrangements. At year-end, oil-equivalent
reserves were higher than year-end 1999 by 8 percent.
<TABLE>
<CAPTION>
U.S. Refining, Marketing and Transportation
- ------------------------------------------
Millions of dollars 2000 1999 1998
- -------------------------------------------------------------------
<S> <C> <C> <C>
Earnings, Excluding Special Items $778 $375 $633
- -------------------------------------------------------------------
Asset Write-Offs and Revaluations (30) - (22)
Asset Dispositions - 75 -
Environmental Remediation Provisions (163) (71) (39)
Restructuring and Reorganizations - (35) -
LIFO Inventory Gains 3 13 -
Other (39) - -
---------------------------
Total Special Items (229) (18) (61)
---------------------------
Segment Income $549 $357 $572
===================================================================
</TABLE>
U.S. refining, marketing and transportation earnings, excluding special
items, doubled in 2000 to $778 million and exceeded 1998 earnings of $633
million by 23 percent. Special items in 2000 included environmental remediation
provisions for certain of the company's refining and marketing sites, some of
which had been sold or closed in prior years. Earnings improved in 2000 on
higher margins and more reliable West Coast refinery operations. Earnings in
1999 suffered from lower sales margins and operational problems at the company's
California refineries, including a fire and, some months later, a detonation
that did not result in a fire, at the Richmond Refinery. These incidents
affected capacity and efficiency to produce blending components for diesel fuel,
jet fuel and gasoline. These effects in 1999 were offset partially by increases
in refined products sales volumes and higher proceeds from business interruption
insurance.
Refined products sales volumes of 1.327 million barrels per day in 2000
increased 2 percent over 1999 volumes and 7 percent from 1998 levels. The 2000
sales volumes reflected increases in higher- value gasoline and jet fuel
volumes, more than offsetting a decline in sales of residual fuel oil.
Additionally, sales in 2000 suffered from the effect of 1999 year-end
stockpiling by customers in anticipation of possible Year 2000-related
interruptions. U.S. refined products sales realizations were $39.32 per barrel,
up 46 percent from 1999 realizations of $26.86, and up 76 percent from 1998's
depressed levels.
International refining, marketing and transportation earnings include
results of the company's consolidated Canadian refining and marketing business,
international marine operations, international supply and trading activities,
and equity earnings of Caltex Corporation. Excluding special items, 2000
earnings of $116 million improved from $49 million in 1999, but were about 6
percent lower than the $123 million recorded in 1998. Earnings benefited from
foreign exchange gains of $74 million in 2000, compared with losses of $21
million in 1999 and $69 million in 1998.
<TABLE>
<CAPTION>
International Refining, Marketing and Transportation
- ---------------------------------------------------
Millions of dollars 2000 1999 1998
- -------------------------------------------------------------------
<S> <C> <C> <C>
Earnings, Excluding Special Items $116 $ 49 $123
- -------------------------------------------------------------------
Asset Dispositions - (31) -
Prior-year Tax Adjustments - 60 -
Environmental Remediation Provisions (30) - (11)
Restructuring and Reorganizations - (31) (43)
LIFO Inventory Gains (Losses) 18 27 (16)
Other - - (25)
---------------------------
Total Special Items (12) 25 (95)
---------------------------
Segment Income $104 $ 74 $ 28
===================================================================
</TABLE>
The Caltex component of segment results for the years 1998 through 2000 is
shown in the table below.
<TABLE>
<CAPTION>
Caltex
- ------
Millions of dollars 2000 1999 1998
- ---------------------------------------------------------------
<S> <C> <C> <C>
Net Income (Loss) $ 4 $ 56 $(36)
Less:
Special Items 20 30 (82)
Foreign Currency Gains (Losses) 69 (15) (68)
LCM* Inventory Adjustments and Other (6) 76 (43)
------------------------
Adjusted (Loss) Earnings $(79) $(35) $157
===============================================================
<FN>
*Lower of cost or market
</FN>
</TABLE>
Earnings for Caltex suffered from a very competitive operating environment,
including excess refinery capacity in the Asia-Pacific region during 2000 and
1999 and weak sales margins in most of its areas of operations. Competitive
pressures prevented refined products sales realizations from rising sufficiently
to recover higher crude costs.
International refined products sales volumes were 769,000 barrels per day
in 2000, down nearly 8 percent from 832,000 barrels per day in 1999 and down 4
percent from 798,000 barrels per day in 1998. Lower trading volumes and the
third quarter 1999 sale of a Caltex affiliate primarily were responsible for the
decline in sales volumes in 2000. Higher Caltex sales volumes primarily were
responsible for the 1999 increase.
FS-8
<PAGE>
<TABLE>
<CAPTION>
Chemicals
- ---------
Millions of dollars 2000 1999 1998
- ----------------------------------------------------------------
<S> <C> <C> <C>
Earnings, Excluding Special Items $129 $205 $151
- ----------------------------------------------------------------
Asset Write-Offs and Revaluations (90) (43) (19)
Environmental Remediation Provisions (15) (28) (5)
Restructurings and Reorganizations - (22) -
LIFO Inventory Losses - (3) (5)
Other 16 - -
-------------------------
Total Special Items (89) (96) (29)
-------------------------
Segment Income $ 40 $109 $122
================================================================
</TABLE>
Chemicals earnings in 2000 included results from the company's Oronite
division, the company's petrochemicals businesses prior to its contribution to
CPCC in July 2000, and equity earnings in CPCC for the second half of the year.
The special item for asset write-downs in 2000 was for this affiliate's
impairment of assets in Puerto Rico. Operationally, commodity chemicals
businesses suffered in the second half of 2000 from generally weak product
demand, industry additions to manufacturing capacity and high raw material
costs.
Earnings in 1999 benefited from improved sales margins for major products,
higher sales volumes and lower operating expenses. The 1998 results were
adversely affected by plant shutdowns for expansions and storm damage repairs.
<TABLE>
<CAPTION>
All Other
- ---------
Millions of dollars 2000 1999* 1998*
- -------------------------------------------------------------------
<S> <C> <C> <C>
Net Charges, Excluding Special Items $(125) $(273) $ (25)
- -------------------------------------------------------------------
Asset Write-Offs and Revaluations - (62) (68)
Asset Dispositions 99 147 -
Environmental Remediation Provisions - (1) (10)
Prior-Year Tax Adjustments (77) 72 215
Restructurings and Reorganizations - (32) -
Cities Service Litigation - 104 (629)
Other 104 - 97
---------------------------
Total Special Items 126 228 (395)
---------------------------
Segment Credits (Charges) $ 1 $ (45) $(420)
===================================================================
<FN>
* Conformed to 2000 presentation to include equity earnings from Dynegy Inc.
</FN>
</TABLE>
All Other consists of coal mining operations, the company's ownership
interest in Dynegy Inc., worldwide cash management and debt financing
activities, corporate administrative costs, insurance operations and real
estate activities.
Earnings, excluding special items, for the company's coal operations were
$1 million in 2000, compared with $34 million in 1999 and $77 million in 1998.
Earnings in 2000 were affected negatively by a union work stoppage for several
months during the year and operating and geologic complications at certain
mines. In 1999, results were lower than in 1998 primarily because of the absence
of earnings from an affiliate sold in the first quarter of 1999, lower sales
tonnage and prices for the remaining coal business, and adjustments to the
carrying value of the operations that were under active negotiation for sale at
that time.
Chevron's share of Dynegy operating earnings was $119 million, a
significant increase from $44 million in 1999 and $35 million in 1998.
Significantly higher prices for natural gas and natural gas liquids and an
increase in earnings from power generation activities were the primary reasons
for the improved results.
Net charges for the balance of the All Other segment, excluding special
items, were $245 million in 2000, $351 million in 1999 and $137 million in 1998.
Lower interest expense, higher interest income and decreases in other corporate
expenses resulted in lower 2000 net charges than in 1999. The primary factors in
the higher level of charges in 1999 as compared with 1998 were an increase in
debt and lower cash balances, which caused interest expense to be higher, and
reduced interest income.
LIQUIDITY AND CAPITAL RESOURCES
- -------------------------------
Cash, cash equivalents and marketable securities totaled $2.6 billion at
year-end 2000, up 29 percent from $2.0 billion at year-end 1999. Cash provided
by operating activities in 2000 was $8.7 billion, compared with $4.5 billion in
1999 and $3.7 billion in 1998, benefiting from higher earnings. In addition,
Chevron received a cash distribution in 2000 of $835 million from Chevron
Phillips Chemical Co. after the joint venture obtained debt financing. Improved
cash flows in 2000 permitted the company to reduce overall debt levels by $2.7
billion and repurchase $1.4 billion of the company's common shares. In 1999 and
1998, debt levels increased by $1.4 billion and $1.5 billion, respectively, as
cash provided by operating activities and asset sales was not sufficient to fund
the company's total cash requirements. In 1999, a payment of $775 million was
also made to Occidental Petroleum in settlement of the Cities Service lawsuit.
In 2000, the company paid dividends of $2.60 per share, compared with $2.48
per share in 1999 and $2.44 per share in 1998, increasing for the 13th
consecutive year. In January 2001, the company declared a regular quarterly
dividend of 65 cents a share on its common stock, unchanged from the previous
quarter.
The company's total debt and capital lease obligations were $6.232 billion
at December 31, 2000, a decrease of 30 percent from $8.919 billion at year-end
1999. In early February 2001, the company announced a public offering to
repurchase $350 million of 7.45 percent guaranteed notes maturing in 2004. At
the close of the offering in late February, about $230 million had been
acquired.
At year-end 2000, Chevron had $3.250 billion in committed credit facilities
with various major banks, $2.725 billion of which had termination dates beyond
one year. These facilities support commercial paper borrowing and also can be
used for general credit requirements. No borrowings were outstanding under these
facilities during the year or at year-end 2000. In addition, Chevron has three
existing "shelf" registrations on file with the Securities and Exchange
Commission that together would permit registered offerings of up to $2.8 billion
of debt securities.
The company's debt due within 12 months, consisting primarily of commercial
paper and the current portion of long-term debt, totaled $3.804 billion at
December 31, 2000. Of this total short-term debt, $2.725 billion was
reclassified to long-term debt at year-end 2000. Settlement of these obligations
is not expected to require the use of working capital in 2001, as the company
has the intent and the ability, as evidenced by committed credit arrangements,
to refinance them on a long-term basis. The company's practice has been to
continually refinance its commercial paper, maintaining levels it believes to be
appropriate.
FS-9
<PAGE>
To allow Chevron to continue active relationships with institutional
investors in its commercial paper, the company instituted a program in 2000
under which it sells commercial paper and reinvests the borrowed funds in
money-market instruments with similar terms. At December 31, 2000, the company
had incremental short-term debt and investments of $84 million under this
program.
The company's future debt level is dependent primarily on its results of
operations and capital-spending program. The company believes it has substantial
borrowing capacity to meet unanticipated cash requirements.
In December 1997, Chevron's Board of Directors approved the repurchase of
up to $2 billion of the company's outstanding common stock for use in its
employee stock option programs. In 2000, prior to suspending the program in
October upon announcement of the merger agreement with Texaco, the company had
repurchased 16.9 million shares at a cost of $1.406 billion. Total repurchases
from the program's inception were 23.3 million shares at a cost of $1.890
billion.
<TABLE>
<CAPTION>
Financial Ratios
- ----------------
2000 1999 1998
- ---------------------------------------------------------
<S> <C> <C> <C>
Current Ratio 1.1 0.9 0.9
Interest Coverage Ratio 19.9 8.2 5.1
Total Debt/Total Debt Plus Equity 23.8% 33.4% 30.7%
=========================================================
</TABLE>
FINANCIAL RATIOS
- -----------------
The year-end current ratio is the ratio of current assets to current
liabilities. Generally, two items adversely affect Chevron's current ratio, but
in the company's opinion do not affect its liquidity. Current assets in all
years included inventories valued on a LIFO basis, which at year-end 2000 were
lower than current costs, based on average acquisition costs for the year, by
nearly $2 billion. Also, the company benefits from lower interest available on
short-term debt by continually refinancing its commercial paper. In past years,
Chevron's proportionately large amount of short-term debt contributed to keeping
its ratio of current assets to current liabilities at a relatively low level.
However, at year-end 2000, only $94 million of commercial paper, after excluding
$2.725 billion reclassified to long-term debt, was classified as a current
liability. Strong cash flows during 2000 permitted the company to reduce the
level of commercial paper required to fund its cash requirements.
The interest coverage ratio is defined as income before income tax expense,
plus interest and debt expense and amortization of capitalized interest, divided
by before-tax interest costs. Chevron's interest coverage ratio improved
significantly in 2000, primarily due to higher before-tax income and lower
interest expense as a result of lower debt levels. The company's debt ratio
(total debt/total debt plus equity) declined about a third to 23.8 percent in
2000, due to the significant reduction in overall debt balances and an increase
in equity for the year.
CAPITAL AND EXPLORATORY EXPENDITURES
- ----------------------------------------
Worldwide capital and exploratory expenditures for 2000 totaled $5.153
billion, including the company's equity share of affiliates' expenditures.
Capital and exploratory expenditures were $6.133 billion in 1999 and $5.314
billion in 1998. Expenditures for exploration and production activities
represented 62 percent of total outlays in 2000, compared with 73 percent in
1999 and 59 percent in 1998. International exploration and production spending
was 60 percent of worldwide exploration and production expenditures in 2000,
compared with 80 percent in 1999 and 62 percent in 1998, reflecting the
company's continuing focus on international exploration and production
activities. Included in 1999 were expenditures of about $1.7 billion - mainly
cash and assumption of debt - for the acquisition of Rutherford-Moran Oil
Corporation and Petrolera Argentina San Jorge S.A., exploration and production
businesses in Thailand and Argentina, respectively. All Other expenditures in
2000 included an additional investment of about $300 million in Dynegy Inc.
The company estimates 2001 capital and exploratory expenditures at $6.0
billion, including Chevron's share of spending by affiliates. This is up about
16 percent from 2000 spending levels. The 2001 program provides $3.7 billion for
exploration and production investments, of which $2.5 billion is for
international projects. Major areas of emphasis for exploration and production
are Kazakhstan, Africa, Argentina, Thailand, Canada and the deep waters of the
Gulf of Mexico. Successful implementation of the planned expenditure program for
2001 will depend upon many factors, including the ability of partners in many of
these projects, some of which are national petroleum companies of producing
countries, to fund their shares of project expenditures.
Refining and marketing expenditures are estimated at about $900 million,
with $600 million of that planned for projects in the United States, most of
which will be spent to increase retail volumes and convenience store revenue as
well as streamline distribution channels. The largest portion of the
international refining and marketing capital program will be invested by the
company's Caltex affiliate. Transportation expenditures are estimated at about
$500 million, primarily for international pipelines related to expanded upstream
production. Investments in power and natural gas facilities and distribution and
in technology will total $650 million, most of which will be invested by the
company's Dynegy affiliate. The company also plans to invest about $250 million
in the worldwide chemicals business.
The spending plans discussed above are for Chevron as a stand-alone entity
and do not reflect the impact of the pending merger with Texaco. They also do
not include the acquisition of an additional 5 percent equity in the
Tengizchevroil project in Kazakhstan, which closed in January 2001.
<TABLE>
<CAPTION>
Capital and Exploratory Expenditures
- ------------------------------------
2000 1999 1998
- ----------------------------------------------------------------------------------------------------------------
Inter- Inter- Inter-
Millions of dollars U.S. national Total U.S. national Total U.S. national Total
- ----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Exploration and Production $ 1,265 $ 1,908 $ 3,173 $ 907* $ 3,591 $ 4,498 $ 1,214* $ 1,942 $ 3,156
Refining, Marketing
and Transportation 487 608 1,095 522 412 934 654 431 1,085
Chemicals 135 52 187 326 136 462 385 359 744
All Other 698 - 698 239* - 239 329* - 329
------------------------------------------------------------------------------------
Total $ 2,585 $ 2,568 $ 5,153 $ 1,994 $ 4,139 $ 6,133 $ 2,582 $ 2,732 $ 5,314
- ----------------------------------------------------------------------------------------------------------------
Total, Excluding Equity
in Affiliates $ 2,278 $ 1,908 $ 4,186 $ 1,859 $ 3,492 $ 5,351 $ 2,460 $ 1,860 $ 4,320
================================================================================================================
<FN>
*Conformed to 2000 presentation to include the company's share of expenditures
by its Dynegy Inc. affiliate in All Other
</FN>
</TABLE>
FS-10
<PAGE>
<TABLE>
<CAPTION>
QUARTERLY RESULTS AND STOCK MARKET DATA
--------------------------------------
Unaudited
2000 1999
- -----------------------------------------------------------------------------------------------------------------------------
Millions of dollars, except per-share amounts 4TH Q 3RD Q 2ND Q 1ST Q 4TH Q 3RD Q 2ND Q 1ST Q
- -----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
REVENUES AND OTHER INCOME
Sales and other operating revenues(1)..... $13,228 $12,997 $12,982 $11,385 $10,611 $ 9,965 $ 8,473 $ 6,399
Income from equity affiliates ............ 103 276 175 196 122 127 133 144
Other income ............................. 226 348 67 146 246 85 135 146
-----------------------------------------------------------------------------
TOTAL REVENUES AND OTHER INCOME .......... 13,557 13,621 13,224 11,727 10,979 10,177 8,741 6,689
-----------------------------------------------------------------------------
COSTS AND OTHER DEDUCTIONS
Purchased crude oil and products,
operating and other expenses .......... 8,918 8,809 9,071 7,960 7,307 7,006 6,275 4,426
Depreciation, depletion and amortization . 697 801 699 651 900 767 633 566
Taxes other than on income(1)............. 1,221 1,240 1,194 1,138 1,184 1,181 1,143 1,078
Interest and debt expense ................ 104 101 126 129 138 116 113 105
-----------------------------------------------------------------------------
TOTAL COSTS AND OTHER DEDUCTIONS ......... 10,940 10,951 11,090 9,878 9,529 9,070 8,164 6,175
-----------------------------------------------------------------------------
INCOME BEFORE INCOME TAX ................. 2,617 2,670 2,134 1,849 1,450 1,107 577 514
INCOME TAX EXPENSE ....................... 1,123 1,139 1,018 805 641 525 227 185
-----------------------------------------------------------------------------
NET INCOME (2) ........................... $ 1,494 $ 1,531 $ 1,116 $ 1,044 $ 809 $ 582 $ 350 $ 329
==========================================================================================================================
NET INCOME PER SHARE - BASIC ............. $ 2.32 $ 2.36 $ 1.71 $ 1.59 $ 1.24 $ 0.88 $ 0.54 $ 0.50
- DILUTED ........... $ 2.32 $ 2.35 $ 1.71 $ 1.59 $ 1.23 $ 0.88 $ 0.53 $ 0.50
==========================================================================================================================
DIVIDENDS PAID PER SHARE ................. $ 0.65 $ 0.65 $ 0.65 $ 0.65 $ 0.65 $ 0.61 $ 0.61 $ 0.61
==========================================================================================================================
COMMON STOCK PRICE RANGE - HIGH ......... $ 88.94 $ 92.31 $ 94.88 $ 94.25 $ 96.94 $100.81 $104.94 $ 90.31
- LOW .......... $ 78.19 $ 76.88 $ 82.31 $ 69.94 $ 83.38 $ 85.56 $ 86.38 $ 73.13
==========================================================================================================================
<FN>
(1)Includes consumer excise taxes: $ 1,031 $ 1,067 $ 1,020 $ 942 $ 989 $ 1,023 $ 986 $ 912
(2)Net special (charges) credits
included in Net Income: $ (49) $ (116) $ (25) $ (62) $ (10) $ (120) $ (134) $ 48
</FN>
<FN>
The company's common stock is listed on the New York Stock Exchange (trading
symbol: CHV), as well as on the Chicago, Pacific, London and Swiss stock
exchanges. It also is traded on the Boston, Cincinnati, Detroit and Philadelphia
stock exchanges. As of February 26, 2001, stockholders of record numbered
approximately 107,000.
There are no restrictions on the company's ability to pay dividends. Chevron has
made dividend payments to stockholders for 89 consecutive years.
</FN>
</TABLE>
REPORT OF MANAGEMENT
TO THE STOCKHOLDERS OF CHEVRON CORPORATION
Management of Chevron is responsible for preparing the accompanying financial
statements and for ensuring their integrity and objectivity. The statements were
prepared in accordance with accounting principles generally accepted in the
United States of America and fairly represent the transactions and financial
position of the company. The financial statements include amounts that are based
on management's best estimates and judgments.
The company's statements have been audited by PricewaterhouseCoopers LLP,
independent accountants, selected by the Audit Committee and approved by the
stockholders. Management has made available to PricewaterhouseCoopers LLP all
the company's financial records and related data, as well as the minutes of
stockholders' and directors' meetings.
Management of the company has established and maintains a system of
internal accounting controls that is designed to provide reasonable assurance
that assets are safeguarded, transactions are properly recorded and executed in
accordance with management's authorization, and the books and records accurately
reflect the disposition of assets. The system of internal controls includes
appropriate division of responsibility. The company maintains an internal audit
department that conducts an extensive program of internal audits and
independently assesses the effectiveness of the internal controls.
The Audit Committee is composed of directors who are not officers or
employees of the company. It meets regularly with members of management, the
internal auditors and the independent accountants to discuss the adequacy of the
company's internal controls, its financial statements, and the nature, extent
and results of the audit effort. Both the internal auditors and the independent
accountants have free and direct access to the Audit Committee without the
presence of management.
/s/ David J. O'Reilly /s/ John S. Watson /s/ Stephen J. Crowe
David J. O'Reilly John S. Watson Stephen J. Crowe
Chairman of the Board Vice President Vice President
and Chief Executive Officer and Chief Financial Officer and Comptroller
February 26, 2001
FS-11
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENT OF INCOME
Year ended December 31
------------------------------------------------
Millions of dollars, except per-share amounts 2000 1999 1998
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
REVENUES AND OTHER INCOME
Sales and other operating revenues* $50,592 $35,448 $29,943
Income from equity affiliates 750 526 228
Other income 787 612 386
------------------------------------------------
TOTAL REVENUES AND OTHER INCOME 52,129 36,586 30,557
------------------------------------------------
COSTS AND OTHER DEDUCTIONS
Purchased crude oil and products 27,292 17,982 14,036
Operating expenses 5,177 5,090 4,834
Selling, general and administrative expenses 1,725 1,404 2,239
Exploration expenses 564 538 478
Depreciation, depletion and amortization 2,848 2,866 2,320
Taxes other than on income* 4,793 4,586 4,411
Interest and debt expense 460 472 405
------------------------------------------------
TOTAL COSTS AND OTHER DEDUCTIONS 42,859 32,938 28,723
------------------------------------------------
INCOME BEFORE INCOME TAX EXPENSE 9,270 3,648 1,834
INCOME TAX EXPENSE 4,085 1,578 495
================================================
NET INCOME $ 5,185 $ 2,070 $ 1,339
================================================
NET INCOME PER SHARE OF COMMON STOCK - BASIC $ 7.98 $ 3.16 $ 2.05
- DILUTED $ 7.97 $ 3.14 $ 2.04
================================================
<FN>
*Includes consumer excise taxes: $ 4,060 $ 3,910 $ 3,756
See accompanying notes to consolidated financial statements.
</FN>
</TABLE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
Year ended December 31
-------------------------------------------------
Millions of dollars 2000 1999 1998
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
NET INCOME $ 5,185 $ 2,070 $ 1,339
-------------------------------------------------
Holding gains on securities arising during period 56 29 3
Reclassification adjustment for gains included in net income (99) - -
-------------------------------------------------
Net change during period (43) 29 3
Minimum pension liability adjustment (15) (11) (15)
Currency translation adjustment (7) (43) (1)
-------------------------------------------------
OTHER COMPREHENSIVE LOSS, NET OF TAX (65) (25) (13)
-------------------------------------------------
COMPREHENSIVE INCOME $ 5,120 $ 2,045 $ 1,326
=================================================
<FN>
See accompanying notes to consolidated financial statements.
</FN>
</TABLE>
REPORT OF INDEPENDENT ACCOUNTANTS
TO THE STOCKHOLDERS
AND THE BOARD OF DIRECTORS OF CHEVRON CORPORATION
In our opinion, the consolidated financial statements listed in the index
appearing under Item 14(a)(1) on page 23 present fairly in all material
respects, the financial position of Chevron Corporation and its subsidiaries at
December 31, 2000 and 1999, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2000, in
conformity with accounting principles generally accepted in the United States of
America. In addition, in our opinion, the financial statement schedule listed in
the index appearing under Item 14(a)(2) on page 24 presents fairly, in all
material respects, the information set forth therin when read in conjunction
with the related consolidated statements. These financial statements are the
responsibility of the company's management; our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with auditing standards generally
accepted in the United States of America, which require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
San Francisco, California
February 26, 2001
FS-12
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEET
At December 31
-----------------------------------------
Millions of dollars 2000 1999
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
ASSETS
Cash and cash equivalents $ 1,896 $ 1,345
Marketable securities 734 687
Accounts and notes receivable (less allowance: 2000 - $30; 1999 - $36) 3,837 3,688
Inventories:
Crude oil and petroleum products 631 585
Chemicals 191 526
Materials, supplies and other 250 291
-----------------------------------------
1,072 1,402
Prepaid expenses and other current assets 674 1,175
-----------------------------------------
TOTAL CURRENT ASSETS 8,213 8,297
Long-term receivables 802 815
Investments and advances 8,107 5,231
Properties, plant and equipment, at cost 51,908 54,212
Less: accumulated depreciation, depletion and amortization 29,014 28,895
-----------------------------------------
22,894 25,317
Deferred charges and other assets 1,248 1,008
-----------------------------------------
TOTAL ASSETS $41,264 $40,668
===================================================================================================================
LIABILITIES AND STOCKHOLDERS' EQUITY
Short-term debt $ 1,079 $ 3,434
Accounts payable 3,163 3,103
Accrued liabilities 1,530 1,210
Federal and other taxes on income 1,479 718
Other taxes payable 423 424
-----------------------------------------
TOTAL CURRENT LIABILITIES 7,674 8,889
Long-term debt 4,872 5,174
Capital lease obligations 281 311
Deferred credits and other noncurrent obligations 1,768 1,739
Noncurrent deferred income taxes 4,908 5,010
Reserves for employee benefit plans 1,836 1,796
-----------------------------------------
TOTAL LIABILITIES 21,339 22,919
Preferred stock (authorized 100,000,000 shares, $1.00 par value, none issued) - -
Common stock (authorized 2,000,000,000 shares, $0.75 par value at
December 31, 2000, and 1,000,000 shares, $1.50 par value at
December 31, 1999; 712,487,068 shares issued) 534 1,069
Capital in excess of par value 2,758 2,215
Deferred compensation (611) (646)
Accumulated other comprehensive income (180) (115)
Retained earnings 20,909 17,400
Treasury stock, at cost (2000 - 71,427,097 shares; 1999 - 56,140,994 shares) (3,485) (2,174)
-----------------------------------------
TOTAL STOCKHOLDERS' EQUITY 19,925 17,749
-----------------------------------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $41,264 $40,668
===================================================================================================================
<FN>
See accompanying notes to consolidated financial statements.
</FN>
</TABLE>
FS-13
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENT OF CASH FLOWS
Year ended December 31
------------------------------------------
Millions of dollars 2000 1999 1998
- -------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
OPERATING ACTIVITIES
Net income $5,185 $2,070 $1,339
Adjustments
Depreciation, depletion and amortization 2,848 2,866 2,320
Dry hole expense related to prior years' expenditures 52 126 40
Distributions (less than) greater than income from equity affiliates (154) (258) 25
Net before-tax gains on asset retirements and sales (236) (471) (45)
Net foreign currency (gains) losses (67) 23 (20)
Deferred income tax provision 408 226 266
Net decrease (increase) in operating working capital (1) 846 636 (809)
(Decrease) increase in Cities Service provision - (149) 924
Cash settlement of Cities Service litigation - (775) -
Other, net (220) 187 (309)
------------------------------------------
NET CASH PROVIDED BY OPERATING ACTIVITIES(2) 8,662 4,481 3,731
------------------------------------------
INVESTING ACTIVITIES
Capital expenditures (3,657) (4,366) (3,880)
Proceeds from asset sales 524 992 434
Net sales (purchases) of marketable securities(3) 35 262 (183)
Net purchase of other short-term investments (84) - -
Distribution from Chevron Phillips Chemical Company 835 - -
Other, net (73) 32 (230)
------------------------------------------
NET CASH USED FOR INVESTING ACTIVITIES (2,420) (3,080) (3,859)
------------------------------------------
FINANCING ACTIVITIES
Net (repayments) borrowings of short-term obligations (2,484) 219 1,713
Proceeds from issuances of long-term debt 24 1,221 224
Repayments of long-term debt and other financing obligations (216) (549) (388)
Cash dividends paid (1,688) (1,625) (1,596)
Net (purchases) sales of treasury shares (1,329) 108 (261)
------------------------------------------
NET CASH USED FOR FINANCING ACTIVITIES (5,693) (626) (308)
------------------------------------------
EFFECT OF FOREIGN CURRENCY EXCHANGE RATE CHANGES
ON CASH AND CASH EQUIVALENTS 2 1 (10)
------------------------------------------
NET CHANGE IN CASH AND CASH EQUIVALENTS 551 776 (446)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 1,345 569 1,015
------------------------------------------
CASH AND CASH EQUIVALENTS AT YEAR-END $1,896 $1,345 $ 569
=========================================================================================================================
<FN>
See accompanying notes to consolidated financial statements.
</FN>
</TABLE>
<TABLE>
<CAPTION>
<S> <C> <C> <C>
(1) "Net decrease (increase) in operating working capital" is
composed of the following:
(Increase) decrease in accounts and notes receivable $ (663) $ (810) $ 552
(Increase) decrease in inventories (74) 72 (116)
Decrease (increase) in prepaid expenses and other current assets 53 (43) (23)
Increase (decrease) in accounts payable and accrued liabilities 712 915 (807)
Increase (decrease) in income and other taxes payable 818 502 (415)
--------------------------------------------
Net decrease (increase) in operating working capital $ 846 $ 636 $ (809)
======================================================================================================================
(2) "Net cash provided by operating activities" includes the
following cash payments for interest and income taxes:
Interest paid on debt (net of capitalized interest) $ 466 $ 438 $ 407
Income taxes paid $ 2,908 $ 864 $ 654
======================================================================================================================
(3) "Net sales (purchases) of marketable securities" consists
of the following gross amounts:
Marketable securities purchased $(6,223) $(2,812) $(2,679)
Marketable securities sold 6,258 3,074 2,496
---------------------------------------------
Net sales (purchases) of marketable securities $ 35 $ 262 $ (183)
=======================================================================================================================
</TABLE>
FS-14
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
2000 1999 1998
---------------------- --------------------- ---------------------
Amounts in millions of dollars Shares Amount Shares Amount Shares Amount
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
COMMON STOCK
Balance at January 1 712,487,068 $ 1,069 712,487,068 $ 1,069 712,487,068 $ 1,069
Change in par value - (535) - - - -
- ----------------------------------------------------------------------------------------------------------------------
BALANCE AT DECEMBER 31 712,487,068 $ 534 712,487,068 $ 1,069 712,487,068 $ 1,069
- ----------------------------------------------------------------------------------------------------------------------
TREASURY STOCK AT COST
Balance at January 1 56,140,994 $(2,174) 59,460,666 $(2,293) 56,555,871 $(1,977)
Purchases 16,952,503 (1,411) 56,052 (5) 5,246,100 (398)
Reissuances (1,666,400) 100 (3,375,724) 124 (2,341,305) 82
- ----------------------------------------------------------------------------------------------------------------------
BALANCE AT DECEMBER 31 71,427,097 $(3,485) 56,140,994 $(2,174) 59,460,666 $(2,293)
- ----------------------------------------------------------------------------------------------------------------------
CAPITAL IN EXCESS OF PAR
Balance at January 1 $ 2,215 $ 2,097 $ 2,022
Change in common stock par value 535 - -
Treasury stock transactions 8 118 75
-------- -------- --------
BALANCE AT DECEMBER 31 $ 2,758 $ 2,215 $ 2,097
- ----------------------------------------------------------------------------------------------------------------------
DEFERRED COMPENSATION
Balance at January 1 $ (646) $ (691) $ (750)
Net reduction of ESOP debt and other 35 45 59
-------- -------- --------
BALANCE AT DECEMBER 31 $ (611) $ (646) $ (691)
- ----------------------------------------------------------------------------------------------------------------------
ACCUMULATED OTHER
COMPREHENSIVE INCOME*
Balance at January 1 $ (115) $ (90) $ (77)
Change during year (65) (25) (13)
-------- -------- --------
BALANCE AT DECEMBER 31 $ (180) $ (115) $ (90)
- ----------------------------------------------------------------------------------------------------------------------
RETAINED EARNINGS
Balance at January 1 $17,400 $16,942 $17,185
Net income 5,185 2,070 1,339
Cash dividends (per-share amounts
2000: $2.60; 1999: $2.48; 1998: $2.44) (1,688) (1,625) (1,596)
Tax benefit from dividends paid on
unallocated ESOP shares 12 13 14
-------- -------- --------
BALANCE AT DECEMBER 31 $20,909 $17,400 $16,942
- ----------------------------------------------------------------------------------------------------------------------
TOTAL STOCKHOLDERS' EQUITY
AT DECEMBER 31 $19,925 $17,749 $17,034
======================================================================================================================
<FN>
See accompanying notes to consolidated financial statements.
</FN>
</TABLE>
<TABLE>
<CAPTION>
*ACCUMULATED OTHER COMPREHENSIVE INCOME:
Currency Translation Unrealized Holding Minimum Pension
Adjustment Gain on Securities Liability Adjustment Total
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Balance at January 1, 1998 $ (55) $ 10 $ (32) $ (77)
Change during year (1) 3 (15) (13)
- ----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 $ (56) $ 13 $ (47) $ (90)
Change during year (43) 29 (11) (25)
- ---------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999 $ (99) $ 42 $ (58) $(115)
Change during year (7) (43) (15) (65)
- ---------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2000 $(106) $ (1) $ (73) $(180)
===========================================================================================================================
</TABLE>
FS-15
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Millions of dollars, except per-share amounts
Note 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Chevron Corporation manages its investments in, and provides administrative,
financial and management support to, U.S. and foreign subsidiaries and
affiliates that engage in fully integrated petroleum operations, chemicals
operations and coal mining. Collectively, these companies, referred to as
Chevron, operate in the United States and approximately 100 other countries.
Petroleum operations consist of exploring for, developing and producing crude
oil and natural gas; refining crude oil into finished petroleum products;
marketing crude oil, natural gas and the many products derived from petroleum;
and transporting crude oil, natural gas and petroleum products by pipelines,
marine vessels, motor equipment and rail car. Chemicals operations include the
manufacture and marketing of commodity petrochemicals, plastics for industrial
uses, and fuel and lube oil additives.
In preparing its consolidated financial statements, the company follows
accounting policies that are in accordance with accounting principles generally
accepted in the United States. This requires the use of estimates and
assumptions that affect the assets, liabilities, revenues and expenses reported
in the financial statements, as well as amounts included in the notes thereto,
including discussion and disclosure of contingent liabilities. While the company
uses its best estimates and judgments, actual results could differ from these
estimates as future confirming events occur.
The nature of the company's operations and the many countries in which it
operates subject it to changing economic, regulatory and political conditions.
The company does not believe it is vulnerable to the risk of a near-term severe
impact as a result of any concentration of its activities.
Subsidiary and Affiliated Companies
The consolidated financial statements include the accounts of subsidiary
companies more than 50 percent owned. Investments in and advances to affiliates
in which the company has a substantial ownership interest of approximately 20
percent to 50 percent, or for which the company exercises significant influence
but not control over policy decisions, are accounted for by the equity method.
Under this accounting, remaining unamortized cost is increased or decreased by
the company's share of earnings or losses after dividends. Gains and losses that
arise from the issuance of stock by an affiliate that results in changes in the
company's proportionate share of the dollar amount of the affiliate's equity are
recognized currently in income. Deferred income taxes are provided for these
gains and losses.
Derivatives
Gains and losses on hedges of existing assets or liabilities are included in the
carrying amounts of those assets or liabilities and are ultimately recognized in
income as part of those carrying amounts. Gains and losses related to qualifying
hedges of firm commitments or anticipated transactions also are deferred and are
recognized in income or as adjustments of carrying amounts when the underlying
hedged transaction occurs. Cash flows associated with these derivatives are
reported with the underlying hedged transaction's cash flows. If, subsequent to
being hedged, underlying transactions are no longer likely to occur, the related
derivatives gains and losses are recognized currently in income. Gains and
losses on derivatives contracts that do not qualify as hedges are recognized
currently in "Other income." The adoption on January 1, 2001, of Financial
Accounting Standards Board (FASB) Statement No. 133, "Accounting for Derivative
Instruments and Hedging Activities," (FAS 133), and FAS 138, "Accounting for
Certain Derivative Instruments and Certain Hedging Activities - An Amendment of
FASB Statement No. 133," is not expected to have a significant effect on the
company's results of operations or consolidated financial position.
Short-Term Investments
All short-term investments are classified as available for sale and are in
highly liquid debt or equity securities. Those investments that are part of the
company's cash management portfolio with original maturities of three months or
less are reported as "Cash equivalents." The balance of the short-term
investments is reported as "Marketable securities." Short-term investments are
marked-to-market with any unrealized gains or losses included in other
comprehensive income.
Inventories
Crude oil, petroleum products and chemicals are stated at cost, using a Last-In,
First-Out (LIFO) method. In the aggregate, these costs are below market.
Materials, supplies and other inventories generally are stated at average cost.
Properties, Plant and Equipment
The successful efforts method is used for oil and gas exploration and production
activities. All costs for development wells, related plant and equipment, and
proved mineral interests in oil and gas properties are capitalized. Costs of
exploratory wells are capitalized pending determination of whether the wells
found proved reserves. Costs of wells that are assigned proved reserves remain
capitalized. Costs also are capitalized for wells that find commercially
producible reserves that cannot be classified as proved, pending one or more of
the following: (1) decisions on additional major capital expenditures, (2) the
results of additional exploratory wells that are under way or firmly planned,
and (3) securing final regulatory approvals for development. Otherwise, well
costs are expensed if a determination cannot be made within one year following
completion of drilling as to whether proved reserves were found. All other
exploratory wells and costs are expensed.
Long-lived assets, including proved oil and gas properties, are assessed
for possible impairment by comparing their carrying values with the undiscounted
future net before-tax cash flows. Impaired assets are written down to their
estimated fair values, generally their discounted cash flows. For proved oil and
gas properties in the United States, the company generally performs the
impairment review on an individual field basis. Outside the United States,
reviews are performed on a country or concession basis. Impairment amounts are
recorded as incremental depreciation expense in the period in which the event
occurs.
Depreciation and depletion (including provisions for future abandonment and
restoration costs) of all capitalized costs of proved oil and gas producing
properties, except mineral interests, are expensed using the unit-of-production
method by individual fields as the proved developed reserves are produced.
Depletion expenses for capitalized costs of proved mineral interests are
recognized using the unit-of-production method by individual fields as the
related proved reserves are produced. Periodic valuation provisions for
impairment of capitalized costs of unproved mineral interests are expensed.
FS-16
<PAGE>
Note 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Continued
Depreciation and depletion expenses for coal are determined using the
unit-of-production method as the proved reserves are produced. The capitalized
costs of all other plant and equipment are depreciated or amortized over their
estimated useful lives. In general, the declining-balance method is used to
depreciate plant and equipment in the United States; the straight-line method
generally is used to depreciate international plant and equipment and to
amortize all capitalized leased assets.
Gains or losses are not recognized for normal retirements of properties,
plant and equipment subject to composite group amortization or depreciation.
Gains or losses from abnormal retirements are included in operating expense and
sales are included in "Other income."
Expenditures for maintenance, repairs and minor renewals to maintain
facilities in operating condition are expensed as incurred. Major replacements
and renewals are capitalized.
Environmental Expenditures
Environmental expenditures that relate to ongoing operations or to conditions
caused by past operations are expensed. Expenditures that create future benefits
or contribute to future revenue generation are capitalized.
Liabilities related to future remediation costs are recorded when
environmental assessments and/or cleanups are probable and the costs can be
reasonably estimated. Other than for assessments, the timing and magnitude of
these accruals are generally based on the company's commitment to a formal plan
of action, such as an approved remediation plan or the sale or disposal of an
asset. For the company's U.S. and Canadian marketing facilities, the accrual is
based on the probability that a future remediation commitment will be required.
For oil, gas and coal producing properties, a provision is made through
depreciation expense for anticipated abandonment and restoration costs at the
end of a property's useful life.
For Superfund sites, the company records a liability for its share of costs
when it has been named as a Potentially Responsible Party (PRP) and when an
assessment or cleanup plan has been developed. This liability includes the
company's own portion of the costs and also the company's portion of amounts for
other PRPs when it is probable that they will not be able to pay their share of
the cleanup obligation.
The company records the gross amount of its liability based on its best
estimate of future costs using currently available technology and applying
current regulations as well as the company's own internal environmental
policies. Future amounts are not discounted. Recoveries or reimbursements are
recorded as an asset when receipt is reasonably ensured.
Currency Translation
The U.S. dollar is the functional currency for the company's consolidated
operations as well as for substantially all operations of its equity affiliates.
For those operations, all gains or losses from currency transactions are
currently included in income. The cumulative translation effects for the few
equity affiliates using functional currencies other than the U.S. dollar are
included in the currency translation adjustment in stockholders' equity.
Taxes
Income taxes are accrued for retained earnings of international subsidiaries and
corporate joint ventures intended to be remitted. Income taxes are not accrued
for unremitted earnings of international operations that have been, or are
intended to be, reinvested indefinitely.
Revenue Recognition
Revenues associated with sales of crude oil, natural gas, coal, petroleum and
chemicals products, and all other sources are recorded when title passes to the
customer, net of royalties, discounts and allowances, as applicable. Revenues
from natural gas production from properties in which Chevron has an interest
with other producers are recognized on the basis of the company's net working
interest (entitlement method).
Stock Compensation
The company applies Accounting Principles Board (APB) Opinion No. 25,
"Accounting for Stock Issued to Employees," and related interpretations in
accounting for stock options and presents in Note 20 pro forma net income and
earnings per share data as if the accounting prescribed by FAS No. 123,
"Accounting for Stock-Based Compensation," had been applied.
Note 2. FORMATION OF CHEVRON PHILLIPS CHEMICAL COMPANY LLC
Effective July 1, 2000, Chevron and Phillips Petroleum Company (Phillips) formed
Chevron Phillips Chemical Company LLC (CPCC) - a 50-50 joint venture that
combined most of the petrochemicals businesses of Chevron and Phillips. Chevron
is accounting for its interest using the equity method, in accordance with
Accounting Principles Board (APB) Opinion No. 18, "The Equity Method of
Accounting for Investments in Common Stock." The net amount of assets and
liabilities contributed to CPCC was reclassified to "Investments and advances"
in the consolidated balance sheet. No gain or loss was recognized at the time of
contribution, as the transaction represented the exchange of a consolidated
business for an interest in a private joint venture and was not the culmination
of the earnings process. The difference of approximately $100 between the
carrying value of the investment and the amount of underlying equity in CPCC's
net assets is being amortized as a benefit to income over the next 10 years.
Chevron's share of CPCC's results of operations is recorded to "Income from
equity affiliates." Because CPCC is a limited liability company, Chevron records
the provision for income taxes and related tax liability applicable to its share
of CPCC's income separately in its consolidated financial statements.
The equity accounting treatment for Chevron's share of the net assets
contributed to CPCC resulted in significant variances between 2000 and 1999 in
the individual line captions appearing in the financial statements. The carrying
amounts at July 1, 2000, of the principal assets and liabilities of the
businesses Chevron contributed to CPCC were approximately $600 of net working
capital; $2,100 of net properties, plant and equipment; and $100 of investments
and advances.
Upon formation, the joint venture obtained debt financing and made a cash
payment of $835 to each owner.
FS-17
<PAGE>
Note 3. SPECIAL ITEMS AND OTHER FINANCIAL INFORMATION
Net income is affected by transactions that are unrelated to or are not
necessarily representative of the company's ongoing operations for the periods
presented. These transactions, defined by management and designated "special
items," can obscure the underlying results of operations for a year as well as
affect comparability of results between years.
Listed below are categories of special items and their net increase
(decrease) to net income, after related tax effects.
<TABLE>
<CAPTION>
Year ended December 31
--------------------------------
2000 1999 1998
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
Asset write-offs and revaluations
Exploration and production
- Oil and gas property
impairments - U.S. ...................... $ (50) $(204) $ (44)
- International .............. - - (6)
- Other asset write-offs ................. - (37) -
Refining, marketing and transportation
- Pipeline asset impairments - U.S. ...... (30) - (18)
- Marketing asset impairments - U.S. ..... - - (4)
Chemicals
- Manufacturing facility
impairment - U.S. ....................... (90) - -
- Other asset write-offs ................. - (43) (19)
All other
- Coal mining asset
impairment - U.S. ....................... - (34) -
- Information technology and
other asset write-offs .................. - (28) (68)
--------------------------------
(170) (346) (159)
Asset dispositions, net
Marketable securities ...................... 99 30 -
Pipeline interests ......................... - 75 -
Real estate ................................ - 60 -
Coal assets ................................ - 60 -
Oil and gas assets ......................... - 17 (9)
Caltex interest in equity affiliate ........ - (31) -
--------------------------------
99 211 (9)
--------------------------------
Prior-year tax adjustments .................. (77) 109 271
--------------------------------
Environmental remediation provisions, net (208) (123) (39)
--------------------------------
Restructurings and reorganizations
Corporate .................................. - (158) -
Caltex affiliate ........................... - (25) (43)
--------------------------------
- (183) (43)
--------------------------------
LIFO inventory gains (losses) ............... 23 38 (25)
--------------------------------
Other, net
Dynegy equity adjustment ................... 104 - -
Insurance recovery gain .................... 23 - -
Pension/OPEB curtailment gains ............. 16 - -
Litigation and regulatory issues* .......... (62) 78 (682)
Settlement of insurance claims for
environmental remediation costs
and damages .............................. - - 105
Caltex write-off of
start-up costs (SOP98-5) ................. - - (25)
--------------------------------
81 78 (602)
--------------------------------
Total special items, after tax .............. $(252) $(216) $(606)
===============================================================================
<FN>
* 1999 and 1998 include effects related to Cities Service litigation.
</FN>
</TABLE>
In accordance with its policy, the company recorded impairments of assets
to be held and used when changes in circumstances - primarily related to lower
oil and gas prices, downward revisions of reserves and changes in the use of the
assets - indicated that the carrying values of the assets could not be recovered
through estimated future before-tax undiscounted cash flows. Asset impairments
included in asset write-offs and revaluations were for assets held for use,
except for U.S. coal assets, which were held for sale for approximately one year
during 1998 and 1999. In late 1999, these assets were reclassified to held for
use upon cessation of negotiations with potential buyers.
The aggregate income statement effects from special items are reflected in
the following table, including Chevron's proportionate share of special items
related to equity affiliates.
<TABLE>
<CAPTION>
Year ended December 31
------------------------------
2000 1999 1998
-----------------------------------------------------------------------------
<S> <C> <C> <C>
Revenues and other income
Income from equity affiliates ............... $ (70) $ 30 $ (101)
Other income ................................ 350 353 47
------------------------------
Total revenues and other income ............. 280 383 (54)
------------------------------
Costs and other deductions
Purchased crude oil and products ............ (5) (1) 66
Operating expenses .......................... 285 344 23
Selling, general and administrative
expenses ................................... 130 (19) 799
Depreciation, depletion and amortization .... 121 427 82
------------------------------
Total costs and other deductions ............ 531 751 970
------------------------------
Income before income tax expense ............ (251) (368) (1,024)
Income tax expense .......................... (1) 152 418
------------------------------
Net income .................................. $ (252) $(216) $ (606)
=============================================================================
</TABLE>
Other financial information is as follows:
<TABLE>
<CAPTION>
Year ended December 31
----------------------------
2000 1999 1998
-----------------------------------------------------------------------------
<S> <C> <C> <C>
Total financing interest and debt costs ...... $ 492 $ 481 $ 444
Less: capitalized interest ................... 32 9 39
----------------------------
Interest and debt expense .................... 460 472 405
Research and development expenses ............ 171 182 187
Foreign currency gains (losses)* ............. $ 142 $ (38) $ (47)
=============================================================================
<FN>
* Includes $69, $(15) and $(68) in 2000, 1999, and 1998, respecitvely, for
the company's share of affiliates' foreign currency gains (losses).
</FN>
</TABLE>
The excess of current cost (based on average acquisition costs for the year)
over the carrying value of inventories for which the LIFO method is used was
$1,977, $871 and $584 at December 31, 2000, 1999 and 1998, respectively.
At December 31, 1999, a liability of $85 remained for employee termination
benefits relating to the restructuring charge recorded during the year. During
2000, these amounts were paid, all employee terminations were completed and no
significant adjustments were required for amounts previously accrued.
FS-18
<PAGE>
Note 4. CUMULATIVE EFFECT ON NET INCOME FROM ACCOUNTING CHANGES
In April 1998, The American Institute of Certified Public Accountants (AICPA)
released Statement of Position 98-5, "Reporting on the Costs of Start-up
Activities"(SOP98-5), which introduced a broad definition of items to expense as
incurred for start-up activities, including new products/services, entering new
territories, initiating new processes or commencing new operations. Chevron was
substantially in compliance with the pronouncement. However, Caltex capitalized
these types of costs for certain projects. Chevron recorded its $25 share of the
charge associated with Caltex's 1998 implementation of SOP 98-5, effective
January 1, 1998.
Also in 1998, Chevron changed its method of calculating certain Canadian
deferred income taxes, effective January 1, 1998. The benefit from this change
was $32.
The net benefit to Chevron's 1998 net income from the cumulative effect of
adopting SOP 98-5 by Caltex and the change in Chevron's method of calculating
Canadian deferred taxes was immaterial.
Note 5. INFORMATION RELATING TO THE CONSOLIDATED STATEMENT OF CASH FLOWS
The major components of "Capital expenditures" and the reconciliation of this
amount to the capital and exploratory expenditures, excluding equity in
affiliates, presented in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" are presented in the following table.
<TABLE>
<CAPTION>
Year ended December 31
------------------------------
2000 1999 1998
-------------------------------------------------------------------------------------
<S> <C> <C> <C>
Additions to properties,
plant and equipment ................................ $ 2,917 $ 5,018 $ 3,678
Additions to investments ............................ 775 449 306
Payments for other liabilities
and assets, net(1).................................. (35) (1,101) (104)
------------------------------
Capital expenditures ................................ 3,657 4,366 3,880
Expensed exploration expenditures ................... 512 413 438
Payments of long-term debt
and other financing obligations(2).................. 17 572 2
------------------------------
Capital and exploratory expenditures,
excluding equity affiliates ........................ $ 4,186 $ 5,351 $ 4,320
=====================================================================================
<FN>
(1)1999 includes liabilities assumed in acquisitions of Rutherford-Moran Oil
Corporation and Petrolera Argentina San Jorge S.A.
(2) 1999 includes obligations assumed in acquisition of Rutherford-Moran Oil
Corporation and other capital lease additions.
</FN>
</TABLE>
The consolidated statement of cash flows excludes the following significant
noncash transactions:
Chevron contributed $2,800 of net noncash assets to Chevron Phillips
Chemical Company LLC in 2000, as described in Note 2. The investment is
accounted for under the equity method.
During 1999, the company acquired the Rutherford-Moran Oil Corporation and
Petrolera Argentina San Jorge S.A. Only the net cash component of these
transactions is included as "Capital expenditures." Consideration for the
Rutherford-Moran transaction included 1.1 million shares of the company's
treasury stock valued at $91.
In 2000, $210 was reclassified from "Deferred credits and other noncurrent
obligations" to "Accrued liabilities." The payment was remitted in January 2001.
Note 6. SUMMARIZED FINANCIAL DATA - CHEVRON U.S.A. INC.
At December 31, 2000, Chevron U.S.A. Inc. was Chevron's principal operating
company, consisting primarily of its U.S. integrated petroleum operations
(excluding most of the domestic pipeline operations). Through the first half of
2000, these operations were conducted primarily by three divisions: Chevron
U.S.A. Production Company, Chevron Products Company and Chevron Chemical Company
LLC. As described in Note 2, Chevron combined most of its petrochemicals
businesses with those of Phillips Petroleum Company on July 1, 2000. Summarized
financial information for Chevron U.S.A. Inc. and its consolidated subsidiaries
is presented below.
<TABLE>
<CAPTION>
Year ended December 31
------------------------------
2000 1999 1998
-------------------------------------------------------------------------------------
<S> <C> <C> <C>
Sales and other operating revenues .................. $40,729 $28,957 $24,440
Total costs and other deductions .................... 37,528 28,329 24,338
Net income .......................................... 2,336 885 346
=====================================================================================
</TABLE>
<TABLE>
<CAPTION>
At December 31
---------------------------
2000 1999*
---------------------------------------------------------------
<S> <C> <C>
Current assets $ 4,396 $ 3,889
Other assets 20,738 20,687
Current liabilities 4,094 4,685
Other liabilities 10,251 9,730
Net equity 10,789 10,161
===============================================================
Memo: Total Debt $ 6,728 $ 7,462
<FN>
*Certain asset and liability accounts have been restated. Net equity remains
unchanged.
</FN>
</TABLE>
FS-19
<PAGE>
Note 7. SUMMARIZED FINANCIAL DATA - CHEVRON TRANSPORT CORPORATION LIMITED
Effective July 1999, Chevron Transport Corporation, a Liberian corporation, was
merged into Chevron Transport Corporation Limited (CTC), a Bermuda corporation,
which assumed all of the assets and liabilities of Chevron Transport
Corporation. CTC 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 oil and refined petroleum products. Most
of CTC's shipping revenue is derived by providing transportation services to
other Chevron companies. Chevron Corporation has 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 below.
<TABLE>
<CAPTION>
Year ended December 31
------------------------
2000 1999 1998
------------------------------------------------------------------------------
<S> <C> <C> <C>
Sales and other operating revenues ................. $ 728 $ 504 $ 573
Total costs and other deductions ................... 777 572 580
Net (loss) income .................................. (47) (50) 17
==============================================================================
</TABLE>
<TABLE>
<CAPTION>
At December 31
-------------------
2000 1999
--------------------------------------------------------------
<S> <C> <C>
Current assets $205 $184
Other assets 530 742
Current liabilities 309 580
Other liabilities 361 264
Net equity 65 82
==============================================================
</TABLE>
This information was derived from the financial statements prepared on a
stand-alone basis in conformity with generally accepted accounting principles.
In 2000, CTC's parent made an additional $30 capital contribution. There were no
restrictions on CTC's ability to pay dividends or make loans or advances at
December 31, 2000.
Note 8. STOCKHOLDERS' EQUITY
Retained earnings at December 31, 2000 and 1999, include $2,301 and $2,048,
respectively, for the company's share of undistributed earnings of equity
affiliates.
In 1998, the company declared a dividend distribution of one Right to
purchase Chevron Participating Preferred Stock. The Rights become exercisable,
unless redeemed earlier by the company, if a person or group acquires, or
obtains the right to acquire, 10 percent or more of the outstanding shares of
common stock, or commences a tender or exchange offer that would result in
acquiring 10 percent or more of the outstanding shares of common stock, either
event occurring without the prior consent of the company. The Chevron Series A
Participating Preferred Stock that the holder of a Right is entitled to receive
and the purchase price payable upon exercise of the Chevron Right are both
subject to adjustment. The person or group who had acquired 10 percent or more
of the outstanding shares of common stock without the prior consent of the
company would not be entitled to this purchase.
In October 2000, the Stockholder Rights agreement was amended to modify the
10 percent thresholds discussed above to 20 percent if the acquiring person is
Texaco Corporation.
The Rights will expire in November 2008, or they may be redeemed by the
company at 1 cent per Right prior to that date. The Rights do not have voting or
dividend rights and, until they become exercisable, have no dilutive effect on
the earnings per share of the company. Five million shares of the company's
preferred stock have been designated Series A Participating Preferred Stock and
reserved for issuance upon exercise of the Rights. No event during 2000 made the
Rights exercisable.
At December 31, 2000, 30 million shares of the company's authorized but
unissued common stock were reserved for the issuance of shares under the
Long-Term Incentive Plan (LTIP), which was approved by the stockholders in 1990.
To date, all of the plan's common stock requirements have been met from the
company's Treasury Stock, and there have been no issuances of reserved shares.
Note 9. FINANCIAL AND DERIVATIVE INSTRUMENTS
Off-Balance-Sheet Risk
The company utilizes a variety of derivative instruments, both financial and
commodity-based, as hedges to manage a small portion of its exposure to price
volatility stemming from its integrated petroleum activities. Relatively
straightforward and involving little complexity, the derivative instruments
consist mainly of futures contracts traded on the New York Mercantile Exchange
and the International Petroleum Exchange and of both crude and natural gas
swap contracts entered into principally with major financial institutions.
The futures contracts hedge anticipated crude oil purchases and sales and
product sales, generally forecasted to occur within a 60- to 90-day period.
Crude oil swaps are used to hedge sales forecasted to occur within the next
three years. The terms of the swap contracts have maturities of the same period.
Natural gas swaps are used primarily to hedge firmly committed sales, and the
terms of the swap contracts held at year-end 2000 had an average remaining
maturity of 43 months. Gains and losses on these derivative instruments offset
and are recognized in income concurrently with the recognition of the underlying
physical transactions.
The company enters into forward exchange contracts, generally with terms of
90 days or less, as a hedge against some of its foreign currency exposures,
primarily anticipated purchase transactions forecasted to occur within 90 days.
The company enters into interest rate swaps as part of its overall strategy
to manage the interest rate risk on its debt. Under the terms of the swaps, net
cash settlements, based on the difference between fixed-rate and floating-rate
interest amounts calculated by reference to agreed notional principal amounts,
are made semiannually and are recorded monthly as "Interest and debt expense."
At December 31, 2000, there were no outstanding contracts.
FS-20
<PAGE>
Note 9. FINANCIAL AND DERIVATIVE INSTRUMENTS
- - Continued
Concentrations of Credit Risk
The company's financial instruments that are exposed to concentrations of
credit risk consist primarily of its cash equivalents, marketable securities,
derivative financial instruments and trade receivables.
The company's short-term investments are placed with a wide array of
financial institutions with high credit ratings. This diversified investment
policy limits the company's exposure both to credit risk and to concentrations
of credit risk. Similar standards of diversity and creditworthiness are applied
to the company's counterparties in derivative instruments.
The trade receivable balances, reflecting the company's diversified sources
of revenue, are dispersed among the company's broad customer base worldwide. As
a consequence, concentrations of credit risk are limited. The company routinely
assesses the financial strength of its customers. Letters of credit, or
negotiated contracts when the financial strength of a customer is not considered
sufficient, are the principal securities obtained to support lines of credit.
Fair Value
Fair values are derived either from quoted market prices or, if not available,
the present value of the expected cash flows. The fair values reflect the cash
that would have been received or paid if the instruments were settled at
year-end. The fair values of the financial and derivative instruments at
December 31, 2000 and 1999, are described below.
Long-term debt of $2,147 and $2,449 had estimated fair values of $2,167 and
$2,430.
The notional principal amount of the interest rate swap for 1999 totaled
$350, with an approximate fair value of $11. The notional amounts of derivative
instruments do not represent assets or liabilities of the company but, rather,
are the basis for the settlements under the contract terms.
The company holds cash equivalents and U.S. dollar marketable securities in
domestic and offshore portfolios. Eurodollar bonds, floating-rate notes, time
deposits and commercial paper are the primary instruments held. Cash equivalents
and marketable securities had fair values of $2,301 and $1,762. Of these
balances, $1,567 and $1,075 classified as cash equivalents had average
maturities under 90 days, while the remainder, classified as marketable
securities, had average maturities of approximately three years.
For other derivatives the contract or notional values were as follows:
Crude oil and products futures had net contract values of $10 and $143. Forward
exchange contracts had contract values of $154 and $123. Gas swap contracts are
based on notional gas volumes of approximately 39 and 44 billion cubic feet.
Crude oil swap contracts are based on notional crude volumes of approximately 11
million barrels. Fair values for all of these derivatives were not material in
2000 and 1999. Deferred gains and losses that were accrued on the consolidated
balance sheet were not material.
Note 10. OPERATING SEGMENTS AND GEOGRAPHIC DATA
Chevron manages its exploration and production; refining, marketing and
transportation; and chemicals businesses separately. The company's primary
country of operation is the United States, its country of domicile. The
remainder of the company's operations is reported as International (outside the
United States), since its activities in no other country meet the requirements
for separate disclosure.
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 corporation on a
worldwide basis. Corporate administrative costs and assets are not allocated to
the operating segments; instead, operating segments are billed only for direct
corporate services. Nonbillable costs remain as corporate center expenses.
After-tax segment operating earnings are presented in the following table.
<TABLE>
<CAPTION>
Year ended December 31
------------------------------
2000 1999 1998
---------------------------------------------------------
<S> <C> <C> <C>
EXPLORATION AND PRODUCTION
United States* ......... $ 1,889 $ 482 $ 330
International .......... 2,602 1,093 707
------------------------------
TOTAL EXPLORATION
AND PRODUCTION ......... 4,491 1,575 1,037
------------------------------
REFINING, MARKETING
AND TRANSPORTATION
United States .......... 549 357 572
International .......... 104 74 28
------------------------------
TOTAL REFINING, MARKETING
AND TRANSPORTATION ..... 653 431 600
------------------------------
CHEMICALS
United States .......... (31) 44 79
International .......... 71 65 43
------------------------------
TOTAL CHEMICALS ......... 40 109 122
------------------------------
TOTAL SEGMENT INCOME .... 5,184 2,115 1,759
------------------------------
Interest Expense ........ (317) (333) (270)
Interest Income ......... 89 21 63
Other * ................. 229 267 (213)
------------------------------
NET INCOME .............. $ 5,185 $ 2,070 $ 1,339
==============================
NET INCOME - UNITED STATES $ 2,469 $ 976 $ 642
NET INCOME - INTERNATIONAL $ 2,716 $ 1,094 $ 697
------------------------------
TOTAL NET INCOME ....... $ 5,185 $ 2,070 $ 1,339
==============================
<FN>
*1999 and 1998 conformed to reflect change to Other for equity earnings in
Dynegy Inc.
</FN>
</TABLE>
FS-21
<PAGE>
Note 10. OPERATING SEGMENTS AND GEOGRAPHIC DATA - Continued
Segment Assets
Segment assets do not include intercompany investments or intercompany
receivables. "All Other" assets consist primarily of worldwide cash and
marketable securities, company real estate, information systems, Dynegy Inc.
investment and coal mining operations. Segment assets at year-end 2000 and 1999
follow:
<TABLE>
<CAPTION>
At December 31
-------------------
2000 1999
------------------------------------------------
<S> <C> <C>
EXPLORATION AND PRODUCTION
United States* .......... $ 5,568 $ 5,215
International ........... 14,493 13,748
-------------------
TOTAL EXPLORATION
AND PRODUCTION .......... 20,061 18,963
-------------------
REFINING, MARKETING
AND TRANSPORTATION
United States ........... 8,365 8,178
International ........... 3,941 3,609
-------------------
TOTAL REFINING, MARKETING
AND TRANSPORTATION ...... 12,306 11,787
-------------------
CHEMICALS
United States ........... 2,342 3,303
International ........... 728 923
-------------------
TOTAL CHEMICALS .......... 3,070 4,226
-------------------
TOTAL SEGMENT ASSETS ..... 35,437 34,976
-------------------
ALL OTHER
United States* .......... 4,398 3,825
International ........... 1,429 1,867
-------------------
TOTAL All OTHER .......... 5,827 5,692
-------------------
TOTAL ASSETS - UNITED STATES 20,673 20,521
TOTAL ASSETS - INTERNATIONAL 20,591 20,147
-------------------
TOTAL ASSETS ............ $41,264 $40,668
===================
<FN>
*Conformed to 2000 presentation of the company's investment in Dynegy Inc.
in All Other.
</FN>
</TABLE>
Segment Sales and Other Operating Revenues
Revenues for the exploration and production segment are derived primarily from
the production of crude oil and natural gas. Revenues for the refining,
marketing and transportation segment are derived from the refining and marketing
of petroleum products such as gasoline, jet fuel, gas oils, kerosene, 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.
Prior to the July 2000 formation of the Chevron Phillips joint venture,
chemicals segment revenues were derived from the manufacture and sale of
petrochemicals, plastic resins, and lube oil and fuel additives. Subsequently,
only revenues from the manufacture and sale of lube oil and fuel additives were
included.
"All Other" activities include corporate administrative costs, worldwide
cash management and debt financing activities, coal mining operations, insurance
operations, and real estate activities.
Reportable operating segment sales and other operating revenues, including
internal transfers, for the years 2000, 1999 and 1998 are presented in the
following table. Sales from the transfer of products between segments are at
estimated market prices.
<TABLE>
<CAPTION>
Year ended December 31
---------------------------------
2000 1999 1998
------------------------------------------------------------------
<S> <C> <C> <C>
EXPLORATION AND PRODUCTION
United States
Natural gas .................. $ 2,701 $ 1,578 $ 1,599
Natural gas liquids .......... 266 159 128
Other ........................ 12 8 12
Intersegment ................. 3,213 1,985 1,453
--------------------------------
Total United States .......... 6,192 3,730 3,192
--------------------------------
International
Crude oil .................... 4,285 2,586 1,761
Natural gas .................. 914 678 505
Natural gas liquids .......... 234 116 89
Other ........................ 296 207 131
Intersegment ................. 4,685 2,876 1,984
--------------------------------
Total International .......... 10,414 6,463 4,470
--------------------------------
TOTAL EXPLORATION
AND PRODUCTION ............ 16,606 10,193 7,662
--------------------------------
REFINING, MARKETING
AND TRANSPORTATION
United States
Refined products ............. 19,095 12,765 10,148
Crude oil .................... 6,088 3,618 2,971
Natural gas liquids .......... 274 133 100
Other ........................ 770 654 622
Excise taxes ................. 3,837 3,702 3,503
Intersegment ................. 341 366 216
--------------------------------
Total United States .......... 30,405 21,238 17,560
--------------------------------
International
Refined products ............. 1,386 975 1,312
Crude oil .................... 6,702 3,874 3,049
Natural gas liquids .......... 39 24 5
Other ........................ 385 248 299
Excise taxes ................. 196 178 213
Intersegment ................. 18 16 20
--------------------------------
Total International .......... 8,726 5,315 4,898
--------------------------------
TOTAL REFINING, MARKETING
AND TRANSPORTATION ........ 39,131 26,553 22,458
--------------------------------
CHEMICALS
United States
Products ..................... 1,986 2,794 2,468
Excise taxes ................. 1 2 2
Intersegment ................. 137 162 121
--------------------------------
Total United States .......... 2,124 2,958 2,591
--------------------------------
International
Products ..................... 735 715 568
Other ........................ 36 35 18
Excise taxes ................. 26 28 38
Intersegment ................. - 1 1
--------------------------------
Total International .......... 797 779 625
--------------------------------
TOTAL CHEMICALS ............ 2,921 3,737 3,216
--------------------------------
ALL OTHER
United States - Coal .......... 279 360 399
United States - Other ......... 43 8 (1)
International ................. 6 3 4
Intersegment - United States .. 90 55 52
Intersegment - International .. 10 4 2
--------------------------------
TOTAL ALL OTHER ............ 428 430 456
--------------------------------
Segment Sales and
Other Operating Revenues
- United States .... 39,133 28,349 23,793
- International .... 19,953 12,564 9,999
--------------------------------
Total Segment Sales and
Other Operating Revenues ..... 59,086 40,913 33,792
--------------------------------
Elimination of Intersegment Sales (8,494) (5,465) (3,849)
--------------------------------
Total Sales and
Other Operating Revenues ..... $ 50,592 $ 35,448 $ 29,943
================================
</TABLE>
FS-22
<PAGE>
Segment Income Taxes
Segment income tax expenses for the years 2000, 1999 and 1998 are as follows:
<TABLE>
<CAPTION>
Year ended December 31
-----------------------------
2000 1999 1998
--------------------------------------------------------
<S> <C> <C> <C>
EXPLORATION AND PRODUCTION
United States* ........ $ 1,074 $ 260 $ 161
International ......... 2,701 1,341 595
-----------------------------
TOTAL EXPLORATION
AND PRODUCTION ........ 3,775 1,601 756
-----------------------------
REFINING, MARKETING
AND TRANSPORTATION
United States ......... 248 135 309
International ......... 19 41 54
-----------------------------
TOTAL REFINING, MARKETING
AND TRANSPORTATION .... 267 176 363
-----------------------------
CHEMICALS
United States ......... 31 (13) 25
International ......... 30 45 14
-----------------------------
TOTAL CHEMICALS ........ 61 32 39
-----------------------------
All Other* ............ (18) (231) (663)
-----------------------------
TOTAL INCOME TAX EXPENSE $ 4,085 $ 1,578 $ 495
=============================
<FN>
*1999 and 1998 conformed to reflect change to All Other for the company's
investment in Dynegy Inc.
</FN>
</TABLE>
Other Segment Information
Major equity affiliates are aligned for segment reporting as follows: P.T.
Caltex Pacific Indonesia (CPI) and Tengizchevroil (TCO) - International
exploration and production; Caltex Corporation - International refining,
marketing and transportation; Chevron Phillips Chemical Company LLC - U.S.
Chemicals; and Dynegy Inc. - All Other. Additional information for equity
affiliates is in Note 13. Information related to properties, plant and equipment
by segment is in Note 14.
Note 11. LITIGATION
Chevron and five other oil companies filed suit in 1995 contesting the validity
of a patent granted to Unocal Corporation for reformulated gasoline, which
Chevron sells in California in certain months of the year. In March 2000, the
U.S. Court of Appeals for the Federal Circuit upheld a September 1998 District
Court decision that Unocal's patent was valid and enforceable and assessed
damages of 5.75 cents per gallon for gasoline produced in infringement of the
patent. In May 2000, the Federal Circuit Court denied a petition for rehearing
with the U.S. Court of Appeals for the Federal Circuit filed by Chevron and the
five other defendants in this case. The defendant companies petitioned the U.S.
Supreme Court in August 2000 for the case to be heard. In February 2001, the
Supreme Court denied the petition to review the lower court's ruling. The
defendants are pursuing other legal alternatives to have Unocal's patent ruled
invalid.
If Unocal's patent ultimately is upheld, the company's financial exposure
includes royalties, plus interest, for production of gasoline that is proven to
have infringed the patent. As a result of the March 2000 ruling, the company
recorded a special after-tax charge of $62. The majority of this charge
pertained to the estimated royalty on gasoline production in the early part of a
four-year period ending December 31, 1999, before Chevron modified its
manufacturing processes to minimize the production of gasoline that allegedly
infringed on Unocal's patented formulations. Subsequently, the company has been
accruing in the normal course of business any future estimated liability for
potential infringement of the patent covered by the trial court's ruling. In
June 2000, Chevron paid $22.7 to Unocal - $17.2 for the original court judgment
for California gasoline produced in violation of Unocal's patent from March
through July 1996 and $5.5 of interest and fees. Unocal has obtained additional
patents for alternate formulations that could affect a larger share of U.S.
gasoline production. Chevron believes these additional patents are invalid and
unenforceable. However, if such patents are ultimately upheld, the competitive
and financial effects on the company's refining and marketing operations, while
presently indeterminable, could be material.
Note 12. LEASE COMMITMENTS
Certain noncancelable leases are classified as capital leases, and the leased
assets are included as part of "Properties, plant and equipment. "Other leases
are classified as operating leases and are not capitalized. Details of the
capitalized leased assets are as follows:
<TABLE>
<CAPTION>
At December 31
-------------------------
2000 1999
---------------------------------------------------------------
<S> <C> <C>
Exploration and Production ......... $ 93 $ 86
Refining, Marketing and Transportation 754 779
-------------------------
Total ............................. 847 865
Less: accumulated amortization ..... 429 425
-------------------------
Net capitalized leased assets ...... $418 $440
=========================
</TABLE>
Rental expenses incurred for operating leases during 2000, 1999 and 1998
were as follows:
<TABLE>
<CAPTION>
Year ended December 31
---------------------------------
2000 1999 1998
--------------------------------------------------------------
<S> <C> <C> <C>
Minimum rentals ......... $702 $465 $503
Contingent rentals ...... 3 3 5
---------------------------------
Total .................. 705 468 508
Less: sublease rental income 2 3 3
---------------------------------
Net rental expense ...... $703 $465 $505
=================================
</TABLE>
Contingent rentals are based on factors other than the passage of time,
principally sales volumes at leased service stations. Certain leases include
escalation clauses for adjusting rentals to reflect changes in price indices,
renewal options ranging from 1 to 25 years, and/or options to purchase the
leased property during or at the end of the initial lease period for the fair
market value at that time.
At December 31, 2000, the future minimum lease payments under operating and
capital leases were as follows:
FS-23
<PAGE>
<TABLE>
<CAPTION>
At December 31
---------------------------
Operating Capital
Leases Leases
----------------------------------------------------------------------
<S> <C> <C>
Year: 2001 ............................. $ 220 $ 77
2002 ............................. 247 72
2003 ............................. 218 103
2004 ............................. 213 46
2005 ............................. 207 41
Thereafter ....................... 424 762
---------------------------
Total ................................. $1,529 $1,101
=============================================================---------
Less: amounts representing interest
and executory costs ................... 483
---------------------------
Net present values ..................... 618
Less: capital lease obligations
included in short-term debt ........... 337
---------------------------
Long-term capital lease obligations .... $ 281
---------------------------
Future sublease rental income .......... $ 32 $ -
===========================
</TABLE>
Note 13. INVESTMENTS AND ADVANCES
Chevron owns 50 percent each of P.T. Caltex Pacific Indonesia (CPI), an
exploration and production company operating in Indonesia; Caltex Corporation,
which, through its subsidiaries and affiliates, conducts refining and marketing
activities in Asia, Africa, the Middle East, Australia and New Zealand; and
American Overseas Petroleum Limited, which, through its subsidiary, manages
certain of the company's operations in Indonesia. These companies and their
subsidiaries and affiliates are collectively called the Caltex Group.
The company received dividends and distributions of $596, $268 and $254 in
2000, 1999 and 1998, respectively, including $244, $212 and $167 from the Caltex
group.
Tengizchevroil (TCO) is a joint venture formed in 1993 to develop the
Tengiz and Korolev oil fields in Kazakhstan over a 40-year period. Chevron's
ownership was 45 percent for the 1998 to 2000 period. Upon formation of the
joint venture, the company incurred an obligation of $420, payable to the
Republic of Kazakhstan upon attainment of a dedicated export system with the
capability of the greater of 260,000 barrels of oil per day or TCO's production
capacity. In January 2001, the company purchased an additional 5 percent of TCO.
As a part of that transaction, the company paid $210 of the $420 obligation. The
$420 was also included in the carrying value of the original investment, as the
company believed, beyond a reasonable doubt, that its full payment would be
made.
At year-end 2000, Chevron owned 26.5 percent of Dynegy Inc., a gatherer,
processor, transporter and marketer of energy products in North America and the
United Kingdom. These products include natural gas, natural gas liquids, crude
oil and electricity. Chevron's percentage ownership in Dynegy was reduced from
about 28 percent during 2000, as a result of a Dynegy 10 million-share equity
offering (at about $53 per share), in which Chevron did not participate. The
market value of Chevron's share of Dynegy common stock at December 31, 2000, was
$4,784, based on closing market prices.
Chevron owns 50 percent of Chevron Phillips Chemical Company LLC, formed in
July 2000 when the company merged most of its petrochemicals businesses with
those of Phillips Petroleum Company. This business is described in more detail
in Note 2.
The company's transactions with affiliated companies are summarized in the
table that follows. These are primarily for the purchase of Indonesian crude oil
from CPI, the sale of crude oil and products to Caltex Corporation's refining
and marketing companies, the sale of natural gas to Dynegy, and the purchase of
natural gas and natural gas liquids from Dynegy.
<TABLE>
<CAPTION>
Year ended December 31
-------------------------
2000 1999 1998
-----------------------------------------------------------------
<S> <C> <C> <C>
Sales to Caltex Group ................ $1,452 $ 687 $ 772
Sales to Dynegy Inc. ................. 2,451 1,407 1,307
Sales to Fuel & Marine Marketing LLC* 250 234 22
Sales to Chevron Phillips ............ 158 - -
Sales to other affiliates ............ 21 12 4
-------------------------
Total sales to affiliates ........... $4,332 $2,340 $2,105
=========================
Purchases from Caltex Group .......... $1,247 $ 867 $ 681
Purchases from Dynegy Inc. ........... 524 785 642
Purchases from Chevron Phillips ...... 111 - -
Purchases from other affiliates ...... 35 6 2
-------------------------
Total purchases from affiliates $1,917 $1,658 $1,325
=========================
<FN>
*Affiliate formed in November 1998; owned 31 percent by Chevron.
</FN>
</TABLE>
Equity in earnings, together with investments in and advances to companies
accounted for using the equity method, and other investments accounted for at or
below cost, are as follows:
<TABLE>
<CAPTION>
Investments and Advances Equity in Earnings
-------------------------------------------------------
At December 31 Year ended December 31
-------------------------------------------------------
2000 1999* 2000 1999* 1998*
- ------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Exploration and Production
Tengizchevroil ........ $1,857 $1,722 $ 376 $ 177 $ 60
Caltex Group .......... 465 455 255 139 107
Other ................. 246 198 48 32 4
-------------------------------------------------------
Total Exploration
and Production ....... 2,568 2,375 679 348 171
-------------------------------------------------------
Refining, Marketing
and Transportation
Caltex Group .......... 1,681 1,683 4 56 (36)
Other ................. 771 379 86 70 24
-------------------------------------------------------
Total Refining,
Marketing and
Transportation ....... 2,452 2,062 90 126 (12)
-------------------------------------------------------
Chemicals
Chevron Phillips ........ 1,830 - (114) - -
Other Chemical .......... 15 145 (9) 1 -
-------------------------------------------------------
Total Chemicals ......... 1,845 145 (123) 1 -
-------------------------------------------------------
Dynegy Inc. .............. 929 351 127 51 49
All Other ................ 24 31 (23) - 20
-------------------------------------------------------
Total Equity Method ..... $7,818 $4,964 $ 750 $ 526 $ 228
----------------------------
Other at or Below Cost 289 267
-------------------------
Total Investments and
Advances $8,107 $5,231
-------------------------------------------------------
Total U.S. $3,249 $ 817 $ 73 $ 130 $ 91
Total International $4,858 $4,414 $ 677 $ 396 $ 137
=======================================================
<FN>
*1999 and 1998 reclassified to conform to the 2000 presentation.
</FN>
</TABLE>
"Accounts and notes receivable" in the consolidated balance sheet include
$494 and $277 at December 31, 2000 and 1999, respectively, of amounts due from
affiliated companies. "Accounts payable" include $139 and $53 at December 31,
2000 and 1999, respectively, of amounts due to affiliated companies.
FS-24
<PAGE>
<TABLE>
<CAPTION>
Caltex Group Other Affiliates Chevron's Share
-------------------------------------------------------------------------------------
Year ended December 31 2000 1999(1) 1998(1) 2000 1999 1998 2000 1999(1) 1998(1)
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Total revenues $20,372 $15,274 $11,727 $40,812 $20,645 $16,842 $22,526 $13,840 $ 11,305
Total costs and other deductions 19,284 14,494 11,208 38,951 19,805 16,430 21,287 13,043 10,783
Net income 519 390 143 1,280 610 295 750 526 228
===========================================================================================================================
</TABLE>
<TABLE>
<CAPTION>
Caltex Group Other Affiliates Chevron's Share
--------------------------------------------------------------------------------------
At December 31 2000 1999(2) 1998 2000 1999 1998 2000 1999(2) 1998
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Current assets $ 2,544 $ 2,705 $ 1,974 $14,153 $ 4,640 $ 3,326 $ 5,761 $ 2,850 $ 2,015
Other assets 7,678 7,632 7,683 24,124 10,255 8,868 11,914 7,135 6,663
Current liabilities 3,385 3,395 2,840 11,870 3,709 2,723 4,971 2,665 2,162
Other liabilities 2,543 2,667 2,420 17,161 8,362 7,147 4,886 2,356 2,126
Net equity 4,294 4,275 4,397 9,246 2,824 2,324 7,818 4,964 4,390
===========================================================================================================================
<FN>
(1)Total revenues and costs and other deductions have been restated to conform with 2000 presentation.
(2)Classification of current and other assets restated. Total assets unchanged.
</FN>
</TABLE>
NOTE 14. PROPERTIES, PLANT AND EQUIPMENT
<TABLE>
<CAPTION>
At December 31 Year ended December 31
---------------------------------------------------- -------------------------------------------
Gross Investment at Cost Net Investment : Additions at Cost(1) Depreciation Expense
------------------------- ------------------------ ------------------- ---------------------
2000 1999 1998 2000 1999 1998 : 2000 1999 1998 2000 1999 1998
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Exploration and Production
United States $17,909 $17,947 $18,372 $ 4,699 $ 4,709 $ 5,237 :$ 972 $ 710 $1,000 $ 985 $1,130 $ 818
International 16,901 15,876 12,755 9,509 9,465 7,148 : 1,166 3,251 1,221 1,093 851 730
- -----------------------------------------------------------------------------------------------------------------------------------
Total Exploration :
and Production 34,810 33,823 31,127 14,208 14,174 12,385 : 2,138 3,961 2,221 2,078 1,981 1,548
- -----------------------------------------------------------------------------------------------------------------------------------
Refining, Marketing :
and Transportation :
United States 12,044 12,025 11,793 5,974 6,196 6,268 : 467 515 665 504 478 483
International 1,662 1,838 2,005 900 1,030 1,139 : 36 30 50 64 79 81
- -----------------------------------------------------------------------------------------------------------------------------------
Total Refining, Marketing :
and Transportation 13,706 13,863 13,798 6,874 7,226 7,407 : 503 545 715 568 557 564
- -----------------------------------------------------------------------------------------------------------------------------------
Chemicals(2)
United States 604 3,689 3,436 339 2,354 2,211 : 78 326 385 76 174 109
International 671 714 662 394 453 414 : 42 59 116 19 19 10
- -----------------------------------------------------------------------------------------------------------------------------------
Total Chemicals 1,275 4,403 4,098 733 2,807 2,625 : 120 385 501 95 193 119
- -----------------------------------------------------------------------------------------------------------------------------------
All Other(3) 2,117 2,123 2,314 1,079 1,110 1,312 : 121 103 202 107 135 89
- -----------------------------------------------------------------------------------------------------------------------------------
Total United States 32,673 35,783 35,915 12,091 14,369 15,028 : 1,638 1,654 2,252 1,672 1,917 1,499
Total International 19,235 18,429 15,422 10,803 10,948 8,701 : 1,244 3,340 1,387 1,176 949 821
- -----------------------------------------------------------------------------------------------------------------------------------
Total $51,908 $54,212 $51,337 $22,894 $25,317 $23,729 :$2,882 $4,994 $3,639 $2,848 $2,866 $2,320
===================================================================================================================================
<FN>
(1)Net of dry hole expense related to prior years' expenditures of $52, $125 and
$40 in 2000, 1999 and 1998, respectively.
(2)See Note 2 regarding the 2000 formation of the Chevron Phillips joint
venture.
(3)Primarily coal and real estate assets and management information systems.
</FN>
</TABLE>
FS-25
<PAGE>
Note 15. TAXES
U.S. federal income tax expense was reduced by $103, $89, $84 in 2000, 1999 and
1998, respectively, for low-income housing and other business tax credits.
In 2000, before-tax income, including related corporate and other charges,
for U.S. operations was $3,924, compared with $1,254 in 1999 and $728 in 1998.
For international operations, before-tax income was $5,346, $2,394 and $1,106 in
2000, 1999 and 1998, respectively.
<TABLE>
<CAPTION>
Year ended December 31
-----------------------------
2000 1999 1998
------------------------------------------------------
<S> <C> <C> <C>
Taxes on income
U.S. federal
Current ............ $ 957 $ 135 $ (176)
Deferred ........... 276 145 71
State and local ...... 186 (14) 20
-----------------------------
Total United States 1,419 266 (85)
-----------------------------
International
Current ............ 2,534 1,231 385
Deferred ........... 132 81 195
-----------------------------
Total International 2,666 1,312 580
-----------------------------
Total taxes on income $ 4,085 $ 1,578 $ 495
=============================
</TABLE>
The company's effective income tax rate varied from the U.S. statutory
federal income tax rate because of the following:
<TABLE>
<CAPTION>
Year ended December 31
-------------------------------
2000 1999 1998
-------------------------------------------------------------------------
<S> <C> <C> <C>
U.S. statutory federal income tax rate 35.0% 35.0% 35.0%
Effect of income taxes from international
operations in excess of taxes at the
U.S. statutory rate ................. 8.9 15.6 7.6
State and local taxes on income, net
of U.S. federal income tax benefit... 1.3 (0.2) 0.2
Prior-year tax adjustments ............ 0.6 - (4.5)
Tax credits ........................... (1.1) (2.4) (4.6)
Other ................................. (0.6) (2.2) (6.4)
------------------------------
Consolidated companies ............. 44.1 45.8 27.3
Effect of recording equity in income
of certain affiliated companies
on an after-tax basis ............... - (2.5) (0.3)
------------------------------
Effective tax rate ................. 44.1% 43.3% 27.0%
========================================================================
</TABLE>
The increase in the 1999 effective tax rate from 1998 was due primarily to
increased foreign taxes on higher foreign earnings in 1999 compared with 1998.
Additional increases in the effective tax rate in 1999 were from tax credits as
a smaller proportion of before-tax income in 1999 than in 1998. The other
effects on the 1999 effective tax rate included settlement of outstanding
issues, utilization of additional capital loss benefits and permanent
differences, slightly offset by the effect of lower taxable income received from
equity affiliates in 1999.
The company records its deferred taxes on a tax-jurisdiction basis and
classifies those net amounts as current or noncurrent based on the balance sheet
classification of the related assets or liabilities.
The reported deferred tax balances are composed of the following deferred
tax liabilities (assets).
<TABLE>
<CAPTION>
At December 31
--------------------
2000 1999
----------------------------------------------------------
<S> <C> <C>
Properties, plant and equipment ..... $ 5,230 $ 5,800
Inventory ........................... 43 149
Investments and other ............... 1,020 190
--------------------
Total deferred tax liabilities ..... 6,293 6,139
--------------------
Abandonment/environmental reserves .. (791) (611)
Employee benefits ................... (548) (611)
AMT/other tax credits ............... (314) (588)
Other accrued liabilities ........... (43) (195)
Miscellaneous ....................... (421) (316)
--------------------
Total deferred tax assets .......... (2,117) (2,321)
--------------------
Deferred tax assets valuation
allowance ......................... 315 452
--------------------
Total deferred taxes, net .......... $ 4,491 $ 4,270
============================================================
</TABLE>
Investments and other for 2000 in the table above include deferred tax
liabilities of $805 for investments, of which $482 is associated with the
company's investment in Chevron Phillips Chemical Company. In 1999, most of the
deferred tax liabilities associated with the company's assets contributed to the
joint venture were reported as properties, plant and equipment.
At December 31, 2000 and 1999, deferred taxes were classified in the
consolidated balance sheet as follows:
<TABLE>
<CAPTION>
At December 31
--------------------
2000 1999
------------------------------------------------------------
<S> <C> <C>
Prepaid expenses and other current assets $ (118) $ (546)
Deferred charges and other assets ..... (299) (195)
Federal and other taxes on income ..... - 1
Noncurrent deferred income taxes ...... 4,908 5,010
--------------------
Total deferred income taxes, net ..... $ 4,491 $ 4,270
============================================================
</TABLE>
It is the company's policy for subsidiaries included in the U.S.
consolidated tax return to record income tax expense as though they filed
separately, with the parent recording the adjustment to income tax expense for
the effects of consolidation.
Undistributed earnings of international consolidated subsidiaries and
affiliates for which no deferred income tax provision has been made for possible
future remittances totaled approximately $5,244 at December 31, 2000.
Substantially all of this amount represents earnings reinvested as part of the
company's ongoing business. It is not practical to estimate the amount of taxes
that might be payable on the eventual remit-
FS-26
<PAGE>
tance of such earnings. On remittance, certain countries impose withholding
taxes that, subject to certain limitations, are then available for use as tax
credits against a U.S. tax liability, if any. The company estimates withholding
taxes of approximately $226 would be payable upon remittance of these earnings.
<TABLE>
<CAPTION>
Year ended December 31
--------------------------
2000 1999 1998
-------------------------------------------------------
<S> <C> <C> <C>
Taxes other than on income
United States
Excise taxes on products
and merchandise $3,838 $3,704 $3,505
Property and other
miscellaneous taxes 269 272 262
Payroll taxes 98 119 129
Taxes on production 121 94 92
--------------------------
Total United States 4,326 4,189 3,988
--------------------------
International
Excise taxes on products
and merchandise 222 206 251
Property and other
miscellaneous taxes 150 145 137
Payroll taxes 29 32 26
Taxes on production 66 14 9
--------------------------
Total International 467 397 423
--------------------------
Total taxes other
than on income $4,793 $4,586 $4,411
======================================================
</TABLE>
Note 16. SHORT-TERM DEBT
Redeemable long-term obligations consist primarily of tax-exempt variable-rate
put bonds that are included as current liabilities because they become
redeemable at the option of the bondholders during the year following the
balance sheet date.
The company periodically enters into interest rate swaps on a portion of
its short-term debt. At December 31, 2000, there were no outstanding contracts.
At December 31, 1999, the company had swapped notional amounts of $350 of
floating rate debt to fixed rates. The effect of these swaps on the company's
interest expense was not material.
<TABLE>
<CAPTION>
At December 31
--------------------
2000 1999
-----------------------------------------------------------------
<S> <C> <C>
Commercial paper(1) ........................ $ 2,819 $ 5,265
Current maturities of long-term debt ....... 267 127
Current maturities of long-term
capital leases ........................... 35 35
Redeemable long-term obligations
Long-term debt ............................ 301 301
Capital leases ............................ 302 297
Notes payable .............................. 80 134
--------------------
Subtotal(2)................................ 3,804 6,159
Reclassified to long-term debt ............. (2,725) (2,725)
--------------------
Total short-term debt ..................... $ 1,079 $ 3,434
=================================================================
<FN>
(1)Weighted-average interest rates at December 31, 2000 and 1999, were 6.6
percent and 6.0 percent, respectively,including the effect of interest rate
swaps.
(2)Weighted-average interest rates at December 31, 2000 and 1999, were 6.4
percent and 5.8 percent respectively,including the effect of interest rate
swaps.
</FN>
</TABLE>
Note 17. LONG-TERM DEBT
Chevron has three "shelf" registrations on file with the Securities and Exchange
Commission that together would permit the issuance of $2,800 of debt securities
pursuant to Rule 415 of the Securities Act of 1933.
At year-end 2000, the company had $3,250 of committed credit facilities
with banks worldwide, $2,725 of which had termination dates beyond one year. The
facilities support the company's commercial paper borrowings. Interest on
borrowings under the terms of specific agreements may be based on the London
Interbank Offered Rate, the Reserve Adjusted Domestic Certificate of Deposit
Rate or bank prime rate. No amounts were outstanding under these credit
agreements during the year or at year-end.
<TABLE>
<CAPTION>
At December 31
--------------------------
2000 1999
--------------------------------------------------------------------
<S> <C> <C>
8.11% amortizing notes due 2004(1) $ 540 $ 620
6.625% notes due 2004 499 495
7.327% amortizing notes due 2014(2) 430 430
7.45% notes due 2004 349 349
7.61% amortizing bank loans due 2003 111 143
7.677% notes due 2016(2) 90 90
LIBOR-based bank loan due 2002 59 84
LIBOR-based bank loan due 2001 25 50
7.627% notes due 2015(2) 80 80
6.92% bank loans due 2005 51 51
6.98% bank loans due 2004(2) 25 25
6.22% notes due 2001(2) 10 10
Other foreign currency obligations (5.9%)(3) 69 75
Other long-term debt (7.0%)(3) 76 74
--------------------------
Total including debt due within one year 2,414 2,576
Debt due within one year (267) (127)
Reclassified from short-term debt 2,725 2,725
--------------------------
Total long-term debt $4,872 $5,174
====================================================================
<FN>
(1) Debt assumed from ESOP in 1999.
(2) Guarantee of ESOP debt.
(3) Less than $50 individually; weighted-average interest rates at December 31,
2000.
</FN>
</TABLE>
At December 31, 2000 and 1999, the company classified $2,725 of short-term
debt as long-term. Settlement of these obligations is not expected to require
the use of working capital in 2001, as the company has both the intent and
ability to refinance this debt on a long-term basis.
Consolidated long-term debt maturing in each of the five years after
December 31, 2000, is as follows: 2001-$267, 2002-$231, 2003-$182, 2004-$1,153
and 2005-$29.
In early February 2001, the company announced a public offering to
repurchase all of its 7.45 percent guaranteed notes maturing in 2004. At the
expiration of the offering in mid-February, about $230 had been acquired.
FS-27
<PAGE>
Note 18. OTHER COMPREHENSIVE INCOME
The components of changes in other comprehensive income and the related tax
effects are shown below.
<TABLE>
<CAPTION>
Year ended December 31
------------------------
2000 1999 1998
--------------------------------------------------------------------
<S> <C> <C> <C>
Currency translation adjustment
Before-tax change ....................... $ (7) $(43) $ (1)
Tax benefit ............................. - - -
------------------------
Change, net of tax ...................... (7) (43) (1)
Unrealized holding (loss) gain on securities
Before-tax change ....................... (72) 60 3
Tax benefit (expense) ................... 29 (31) -
------------------------
Change, net of tax ...................... (43) 29 3
Minimum pension liability adjustment
Before-tax change ....................... (23) (16) (24)
Tax benefit ............................. 8 5 9
------------------------
Change, net of tax ...................... (15) (11) (15)
--------------------------------------------------------------------
TOTAL OTHER COMPREHENSIVE INCOME
Before-tax change ....................... $(102) $ 1 $(22)
Tax benefit (expense) ................... 37 (26) 9
------------------------
Change, net of tax ...................... $ (65) $ (25) $(13)
====================================================================
</TABLE>
NOTE 19. EMPLOYEE BENEFIT PLANS
Pension Plans
The company has defined benefit pension plans for most employees and provides
for certain health care and life insurance plans for active and qualifying
retired employees. The company's policy is to fund the minimum necessary to
satisfy requirements of the Employee Retirement Income Security Act for the
company's pension plans.
The company's annual contributions for medical and dental benefits are
limited to the lesser of actual medical claims or a defined fixed per-capita
amount. Life insurance benefits are paid by the company, and annual
contributions are based on actual plan experience. Nonfunded pension and
postretirement benefits are paid directly when incurred; accordingly, these
payments are not reflected as changes in Plan assets in the following table.
The status of the company's pension plans and other postretirement benefit
plans for 2000 and 1999 is as follows:
<TABLE>
<CAPTION>
Pension Benefits Other Benefits
----------------------------------------
2000 1999 2000 1999
-----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Change in benefit obligation
Benefit obligation at January 1 $3,977 $4,278 $ 1,392 $ 1,468
Service cost ..................................... 93 99 14 21
Interest cost .................................... 280 274 105 96
Plan participants' contributions ................. 1 1 - -
Plan amendments .................................. 5 60 - -
Actuarial loss (gain) ............................ 73 (106) 27 (112)
Foreign currency exchange
rate changes .................................... (47) (33) - -
Benefits paid .................................... (545) (801) (105) (81)
Special termination
benefits(1) ..................................... - 205 - -
Plan divestiture ................................. (1) - - -
-----------------------------------------
Benefit obligation
at December 31 ................................... 3,836 3,977 1,433 1,392
-----------------------------------------
Change in plan assets
Fair value of plan assets
at January 1 ..................................... 4,673 4,741 - -
Actual return on plan assets ..................... 110 720 - -
Foreign currency exchange
rate changes .................................... (46) (25) - -
Employer contribution ............................ 2 10 - -
Plan participants' contribution .................. 1 1 - -
Benefits paid .................................... (513) (774) - -
Plan divestiture ................................. (2) - - -
-----------------------------------------
Fair value of plan assets
at December 31 ................................... 4,225 4,673 - -
-----------------------------------------
Funded status ..................................... 389 696 (1,433) (1,392)
Unrecognized net actuarial gain .................. (37) (480) (130) (160)
Unrecognized prior-service cost .................. 113 124 - -
Unrecognized net transitional
assets .......................................... (12) (44) - -
-----------------------------------------
Total recognized at December 31 $ 453 $ 296 $(1,563) $(1,552)
=========================================
Amounts recognized in the
consolidated balance sheet
at December 31
Prepaid benefit cost ............................ $ 671 $ 495 $ - $ -
Accrued benefit liability ....................... (334) (298) (1,563) (1,552)
Intangible asset ................................ 4 10 - -
Accumulated other
comprehensive income(2) ......................... 112 89 - -
-----------------------------------------
Net amount recognized ............................. $ 453 $ 296 $(1,563) $(1,552)
=========================================
Weighted-average assumptions
as of December 31
Discount rate 7.4% 7.6% 7.5% 7.8%
Expected return on plan assets 9.8% 9.7% - -
Rate of compensation increase 4.2% 4.5% 4.5% 4.5%
===============================================================================================
<FN>
(1)Relates to a special involuntary termination enhancement to pension benefits
under a companywide restructuring program.
(2)Accumulated other comprehensive income includes deferred income tax of $39
and $31 in 2000 and 1999, respectively.
</FN>
</TABLE>
FS-28
<PAGE>
For measurement purposes, separate health care cost-trend rates were used
for pre-age 65 and post-age 65 retirees. The 2001 annual rates of change were
assumed to be 7.2 percent and 16.2 percent, respectively, before gradually
converging to the average ultimate rate of 5.0 percent in 2021 for both pre-age
65 and post-age 65. A one-percentage-point change in the assumed health care
rates would have had the following effects:
<TABLE>
<CAPTION>
One-Percentage- One-Percentage-
Point Increase Point Decrease
------------------------------------------------------------------------
<S> <C> <C>
Effect on total service and interest
cost components $ 13 $ (19)
Effect on postretirement benefit
obligation $133 $(111)
========================================================================
</TABLE>
The components of net periodic benefit cost for 2000, 1999 and 1998 were:
<TABLE>
<CAPTION>
Pension Benefits Other Benefits
----------------------------------------------
2000 1999 1998 2000 1999 1998
- ------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Service cost ................. $ 93 $ 99 $113 $ 14 $ 21 $ 19
Interest cost ................ 280 274 275 105 96 93
Expected return on
plan assets ................. (418) (394) (397) - - -
Amortization of
transitional assets ......... (31) (35) (38) - - -
Amortization of prior-
service costs ............... 16 16 14 - - -
Recognized actuarial
losses (gains) .............. 9 1 4 (3) 2 (5)
Settlement gains ............. (54) (104) (11) - - -
Curtailment (gains) losses ... (20) 7 - (15) - -
Special termination
benefit recognition* ........ - 205 - - - -
----------------------------------------------
Net periodic benefit cost $(125) $ 69 $(40) $101 $119 $107
==============================================================================
<FN>
*Relates to a special involuntary termination enhancement to pension benefits
under a companywide restructuring program.
</FN>
</TABLE>
The projected benefit obligation, accumulated benefit obligation and fair
value of plan assets for pension plans with accumulated benefit obligations in
excess of plan assets were $416, $334 and $33, respectively, at December 31,
2000, and $428, $368 and $80, respectively, at December 31, 1999.
Profit Sharing/Savings Plan
Eligible employees of the company and certain of its subsidiaries who have
completed one year of service may participate in the Profit Sharing/Savings
Plan. Charges to expense for the profit sharing part of the Profit
Sharing/Savings Plan were $62, $61 and $60 in 2000, 1999 and 1998, respectively.
The company's Savings Plus Plan contributions were funded with leveraged ESOP
shares.
Employee Stock Ownership Plan (ESOP)
In December 1989, the company established a leveraged ESOP as part of the Profit
Sharing/Savings Plan. The ESOP Trust Fund borrowed $1,000 and purchased 28.2
million previously unissued shares of the company's common stock. In June 1999,
the ESOP borrowed $25 at 6.98 percent interest, using the proceeds to pay
interest due on the existing ESOP debt. In July 1999, the company's leveraged
ESOP issued notes of $620 at an average interest rate of 7.42 percent,
guaranteed by Chevron Corporation. The debt proceeds were paid to Chevron
Corporation in exchange for Chevron's assumption of the existing 8.11 percent
ESOP long-term debt of $620. The ESOP provides a partial prefunding of the
company's future commitments to the Profit Sharing/Savings Plan, which will
result in annual income tax savings for the company.
As permitted by AICPA Statement of Position 93-6, "Employers' Accounting
for Employee Stock Ownership Plans," the company has elected to continue its
practices, which are based on Statement of Position 76-3, "Accounting Practices
for Certain Employee Stock Ownership Plans" and subsequent consensus of the
Emerging Issues Task Force of the Financial Accounting Standards Board.
Accordingly, the debt of the ESOP is recorded as debt, and shares pledged as
collateral are reported as deferred compensation in the consolidated balance
sheet and statement of stockholders' equity. The company reports compensation
expense equal to the ESOP debt principal repayments less dividends received by
the ESOP. Interest incurred on the ESOP debt is recorded as interest expense.
Dividends paid on ESOP shares are reflected as a reduction of retained earnings.
All ESOP shares are considered outstanding for earnings-per-share computations.
The company recorded expense for the ESOP of $25, $59 and $58 in 2000, 1999
and 1998, respectively, including $47, $49 and $56 of interest expense related
to the ESOP debt. All dividends paid on the shares held by the ESOP are used to
service the ESOP debt. The dividends used were $54, $33 and $57 in 2000, 1999
and 1998, respectively.
The company made contributions to the ESOP of $64 and $60 in 1999 and 1998,
respectively, to satisfy ESOP debt service in excess of dividends received by
the ESOP. No contributions were required in 2000. The ESOP shares were pledged
as collateral for its debt. Shares are released from a suspense account and
allocated to the accounts of Plan participants, based on the debt service deemed
to be paid in the
FS-29
<PAGE>
year in proportion to the total of current year and remaining debt service. The
(credit) charge to compensation expense was $(22), $10 and $2 in 2000, 1999 and
1998, respectively. The ESOP shares as of December 31, 2000 and 1999, were as
follows:
<TABLE>
<CAPTION>
Thousands 2000 1999
- ------------------------------------------------------------
<S> <C> <C>
Allocated shares 11,969 10,785
Unallocated shares 10,823 12,963
- ------------------------------------------------------------
Total ESOP shares 22,792 23,748
============================================================
</TABLE>
Management Incentive Plans
The company has two incentive plans, the Management Incentive Plan (MIP) and the
Long-Term Incentive Plan (LTIP) for officers and other regular salaried
employees of the company and its subsidiaries who hold positions of significant
responsibility. The MIP is an annual cash incentive plan that links awards to
performance results of the prior year. The cash awards may be deferred by
conversion to stock units or other investment fund alternatives. Awards under
the LTIP may take the form of, but are not limited to, stock options, restricted
stock, stock units and nonstock grants. Charges to expense for the combined
management incentive plans, excluding expense related to LTIP stock options,
which is discussed in Note 20, were $49, $41 and $28 in 2000, 1999 and 1998,
respectively.
Chevron Success Sharing
The company has a program that provides eligible employees with an annual cash
bonus if the company achieves certain financial and safety goals. Until 2000,
the total maximum payout under the program was 8 percent of the employee's
annual salary. Charges for the program were $146, $47 and $51 in 2000, 1999 and
1998, respectively. In 2000, the maximum payout under the program increased to
10 percent.
NOTE 20. STOCK OPTIONS
The company applies APB Opinion No. 25 and related interpretations in accounting
for stock options awarded under its Broad-Based Employee Stock Option Programs
and its Long-Term Incentive Plan, which are described below.
Had compensation cost for the company's stock options been determined based
on the fair market value at the grant dates of the awards consistent with the
methodology prescribed by FAS No. 123, the company's net income and earnings per
share for 2000, 1999 and 1998 would have been the pro forma amounts shown below.
<TABLE>
<CAPTION>
2000 1999 1998
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Net Income As reported ............. $ 5,185 $ 2,070 $ 1,339
Pro forma ............... $ 5,162 $ 2,027 $ 1,294
Earnings per share As reported ............. $ 7.98 $ 3.16 $ 2.05
- diluted $ 7.97 $ 3.14 $ 2.04
Pro forma - basic ............ $ 7.95 $ 3.09 $ 1.98
- diluted .......... $ 7.93 $ 3.08 $ 1.97
=============================================================================
</TABLE>
The effects of applying FAS No. 123 in this pro forma disclosure are not
indicative of future amounts. FAS No. 123 does not apply to awards granted prior
to 1995. In addition, certain options vest over several years, and awards in
future years, whose terms and conditions may vary, are anticipated.
Broad-Based Employee Stock Options
In 1996, the company granted to all eligible employees an option for 150 shares
of stock or equivalents at an exercise price of $51.875 per share. In addition,
a portion of the awards granted under the LTIP had terms similar to the
broad-based employee stock options. The options vested in June 1997 when
Chevron's share price closed above $75.00 for three consecutive days.
Options for 7,204,800 shares, including similar-termed LTIP awards, were
granted for this program in 1996. Outstanding option shares were 2,213,450 at
December 31, 1997. In 1998, exercises of 1,361,000 and forfeitures of 10,800 had
reduced the outstanding option shares to 841,650 at year-end 1998. In 1999,
exercises of 740,725, forfeitures of 61,850 and expirations of 39,075 reduced
the outstanding option shares to zero at March 31, 1999, the date of expiration.
Under APB Opinion No. 25, the company recorded gains of $2 for these options in
1999. No gains or expenses for this program were recorded in 2000 and 1998.
The fair market value of each option share on the date
of grant under FAS No. 123 was estimated at $5.66 using a binomial
option-pricing model with the following assumptions: risk-free interest rate of
5.1 percent, dividend yield of 4.2 percent, expected life of three years and a
volatility of 20.9 percent.
In 1998, the company announced another broad-based Employee Stock Option
Program that granted to all eligible employees an option that varied from 100 to
300 shares of stock or equivalents, dependent on the employee's salary or job
grade. These options vested after two years in February 2000. Options for
4,820,800 shares were awarded at an exercise price of $76.3125 per share.
Forfeitures of options for 854,550 shares reduced the outstanding option shares
to 3,966,250 at December 31, 1999. In 2000, exercises of 611,201 and forfeitures
of 290,682 had reduced the outstanding option balance to 3,064,367 at the end of
the year. The options expire February 11, 2008. Under APB Opinion No. 25, the
company recorded expenses of $(2), $4 and $2 for these options in 2000, 1999 and
1998, respectively.
The fair value of each option share on the date of grant under FAS No. 123
was estimated at $19.08 using the average results of Black-Scholes models for
the preceding 10 years. The 10-year averages of each assumption used by the
Black-Scholes models were: risk-free interest rate of 7.0 percent, dividend
yield of 4.2 percent, expected life of seven years and a volatility of 24.7
percent.
FS-30
<PAGE>
NOTE 20. STOCK OPTIONS - Continued
Long-Term Incentive Plan
Stock options granted under the LTIP are generally awarded at market price on
the date of grant and are exercisable not earlier than one year and not later
than 10 years from the date of grant. However, a portion of the LTIP options
granted in 1996 had terms similar to the broad-based employee stock options. The
maximum number of shares of common stock that may be granted each year is 1
percent of the total outstanding shares of common stock as of January 1 of such
year.
The weighted-average fair market value of options granted in 2000, 1999 and
1998 was $22.34, $20.40 and $21.10 per share, respectively. The fair market
value of each option on the date of grant was estimated using the Black-Scholes
option-pricing model with the following assumptions for 2000, 1999 and 1998,
respectively: risk-free interest rate of 5.8, 5.5 and 4.5 percent; dividend
yield of 3.0, 3.0 and 3.1 percent; volatility of 25.6, 20.1 and 28.6 percent and
expected life of seven years in all years.
As of December 31, 2000, 10,311,802 shares were under option at exercise
prices ranging from $31.9375 to $99.75 per share. The following table summarizes
information about stock options outstanding under the LTIP, excluding awards
granted with terms similar to the broad-based employee stock options, at
December 31, 2000.
<TABLE>
<CAPTION>
Options Outstanding Options Exercisable
--------------------------------------------------------------
Weighted-
Average Weighted- Weighted-
Range of Number Remaining Average Number Average
Exercise Outstanding Contractual Exercise Exercisable Exercise
Prices (000s) Life(Years) Price (000s) Price
--------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
$31 to $ 41 314 1.24 $34.53 314 $34.53
41 to 51 2,574 3.81 45.38 2,574 45.38
51 to 61 14 5.32 56.81 14 56.81
61 to 71 752 5.83 66.25 752 66.25
71 to 81 3,250 7.35 79.91 3,244 79.91
81 to 91 3,385 9.31 85.61 1,669 89.79
91 to 101 23 8.55 92.14 23 92.14
- -----------------------------------------------------------------------------
$31 to $101 10,312 6.81 $70.78 8,590 $68.63
=============================================================================
</TABLE>
A summary of the status of stock options awarded under the company's LTIP,
excluding awards granted with terms similar to the broad-based employee stock
options, for 2000, 1999 and 1998 follows.
<TABLE>
<CAPTION>
Weighted-
Average
Options Exercise
(000s) Price
-------------------------------------------------------------
<S> <C> <C>
Outstanding at December 31, 1997 8,253 $52.83
-------------------------------------------------------------
Granted 1,872 79.13
Exercised (796) 40.47
Forfeited (106) 80.72
-------------------------------------------------------------
Outstanding at December 31, 1998 9,223 $58.91
- --------------------------------------------------------------
Granted 1,836 89.88
Exercised (1,298) 44.29
Forfeited (152) 83.12
- --------------------------------------------------------------
Outstanding at December 31, 1999 9,609 $66.42
- --------------------------------------------------------------
Granted 1,752 81.54
Exercised (924) 43.56
Forfeited (125) 87.70
- --------------------------------------------------------------
Outstanding at December 31, 2000 10,312 $70.78
- --------------------------------------------------------------
Exercisable at December 31
1998 7,367 $53.82
1999 7,839 $61.13
2000 8,590 $68.63
==============================================================
</TABLE>
NOTE 21. OTHER CONTINGENCIES AND COMMITMENTS
The U.S. federal income tax liabilities have been settled through 1993. The
company's California franchise tax liabilities have been settled through 1991.
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.
At December 31, 2000, the company and its subsidiaries, as direct or
indirect guarantors, had contingent liabilities of $25 for notes of affiliated
companies and $179 for notes of others.
The company and its subsidiaries have certain contingent liabilities
relating to long-term unconditional purchase obligations and commitments,
throughput agreements and take-or-pay agreements, some of which relate to
suppliers' financing arrangements. The aggregate amounts of required payments
under these various commitments are: 2001 - $375; 2002-$354; 2003-$333;
2004-$310; 2005-$252; 2006 and after-$946. Total payments under the agreements
were $281 in 2000, $258 in 1999 and $201 in 1998.
FS-31
<PAGE>
Note 21. OTHER CONTINGENCIES AND COMMITMENTS - Continued
The company is subject to loss contingencies pursuant to environmental laws
and regulations that in the future may require the company to take action to
correct or ameliorate the effects on the environment of prior disposal or
release of chemical or petroleum substances, including MTBE, by the company or
other parties. Such contingencies may exist for various sites including, but not
limited to: Superfund sites and refineries, oil fields, service stations,
terminals and land development areas, whether operating, closed or sold. The
amount of such future cost is indeterminable 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. While the company has provided
for known environmental obligations that are probable and reasonably estimable,
the amount of future costs may be material to results of operations in the
period in which they are recognized. The company does not expect these costs to
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 domestic or international petroleum or chemical
concerns.
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. However, the results of operations and financial
position of certain equity affiliates may be affected by their business
activities involving the use of derivative instruments.
The company's operations, particularly oil and gas exploration and
production, can be affected by changing economic, regulatory and political
environments in the various countries, including the United States, in which it
operates. In certain locations, host governments have imposed restrictions,
controls and taxes, and in others, political conditions have existed that may
threaten the safety of employees and the company's continued presence in those
countries. Internal unrest or strained relations between a host government and
the company or other governments may affect the company's operations. Those
developments have, at times, significantly affected the company's operations and
related results and are carefully considered by management when evaluating the
level of current and future activity in such countries.
Also for oil and gas producing operations, ownership agreements may provide
for periodic reassessments of equity interests in estimated oil and gas
reserves. These activities, individually or together, may result in gains or
losses that could be material to earnings in any given period.
Areas in which the company has significant operations include the United
States, Canada, Australia, the United Kingdom, Norway, Congo, Angola, Nigeria,
Chad, Equatorial Guinea, Democratic Republic of Congo, Papua New Guinea, China,
Venezuela, Thailand, Argentina and Brazil. The company's Caltex affiliates have
significant operations in Indonesia, Korea, Australia, Thailand, the
Philippines, Singapore and South Africa. The company's Tengizchevroil affiliate
operates in Kazakhstan. The company's Dynegy affiliate has operations in the
United States, Canada, the United Kingdom and other European countries.
NOTE 22. EARNINGS PER SHARE (EPS)
Basic EPS includes the effects of deferrals of salary and other compensation
awards that are invested in Chevron stock units by certain officers and
employees of the company. Diluted EPS includes the effects of these deferrals as
well as the dilutive effects of outstanding stock options awarded under the LTIP
and Broad-Based Employee Stock Option Program (see Note 20, "Stock Options").
The following table sets forth the computation of basic and diluted EPS.
<TABLE>
<CAPTION>
2000 1999 1998
------------------------------------------------------------------------------------
Net Shares Per-Share Net Shares Per-Share Net Shares Per-Share
Income (millions) Amount Income (millions) Amount Income (millions) Amount
--------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Net income $5,185 $2,070 $1,339
Weighted-average common shares outstanding 649.0 655.5 653.7
Dividend equivalents paid on Chevron
stock units 2 3 3
Deferred awards held as Chevron stock units 0.9 1.0 1.2
--------------------------------------------------------------------------------------------------------------------------------
Basic EPS COMPUTATION $5,187 649.9 $7.98 $2,073 656.5 $3.16 $1,342 654.9 $2.05
Dilutive effects of stock options 1.2 3.0 2.2
--------------------------------------------------------------------------------------------------------------------------------
Diluted EPS COMPUTATION $5,187 651.1 $7.97 $2,073 659.5 $3.14 $1,342 657.1 $2.04
================================================================================================================================
</TABLE>
FS-32
<PAGE>
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES
Unaudited
In accordance with Statement of Financial Accounting Standards No. 69,
"Disclosures About Oil and Gas Producing Activities" (FAS No. 69), this section
provides supplemental information on oil and gas exploration and producing
activities of the company in six separate tables. Tables I through III provide
historical cost information pertaining to costs incurred in exploration,
property acquisitions and development; capitalized costs; and results of
operations. Tables IV through VI present information on the company's estimated
net proved reserve quantities, standardized measure of estimated discounted
future net cash flows related to proved reserves, and changes in estimated
discounted future net cash flows. The Africa geographic area includes activities
principally in Nigeria, Angola, Chad, Congo and Democratic Republic of Congo.
The "Other" geographic category includes activities in Australia, Argentina, the
United Kingdom North Sea, Canada, Papua New Guinea, Venezuela, Brazil, China,
Thailand and other countries. Amounts shown for affiliated companies are
Chevron's 50 percent equity share in P.T. Caltex Pacific Indonesia (CPI), an
exploration and production company operating in Indonesia, and its 45 percent
equity share of Tengizchevroil (TCO), an exploration and production partnership
operating in the Republic of Kazakhstan.
<TABLE>
<CAPTION>
TABLE 1 - COSTS INCURRED IN EXPLORATION, PROPERTY ACQUISITIONS
AND DEVELOPMENT (1)
Consolidated Companies Affiliated Companies
--------------------------------- --------------------
Millions of dollars U.S. Africa Other Total CPI TCO Worldwide
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31, 2000
Exploration
Wells $ 366 $ 40 $ 129 $ 535 $ 5 $ - $ 540
Geological and geophysical 30 25 94 149 14 - 163
Rentals and other 36 11 65 112 - - 112
- ---------------------------------------------------------------------------------------------------------------------------
Total exploration 432 76 288 796 19 - 815
- ---------------------------------------------------------------------------------------------------------------------------
Property acquisitions(2)
Proved(4) 24 1 - 25 - - 25
Unproved 61 9 175 245 - - 245
- ---------------------------------------------------------------------------------------------------------------------------
Total property acquisitions 85 10 175 270 - - 270
- ---------------------------------------------------------------------------------------------------------------------------
Development 737 395 356 1,488 168 240 1,896
- --------------------------------------------------------------------------------------------------------------------------
TOTAL COSTS INCURRED $1,254 $ 481 $ 819 $2,554 $187 $240 $2,981
==========================================================================================================================
YEAR ENDED DECEMBER 31, 1999
Exploration
Wells $ 258 $ 40 $ 120 $ 418 $ 3 $ - $ 421
Geological and geophysical 37 25 85 147 17 - 164
Rentals and other 30 7 60 97 - - 97
- ---------------------------------------------------------------------------------------------------------------------------
Total exploration 325 72 265 662 20 - 682
- ---------------------------------------------------------------------------------------------------------------------------
Property acquisitions(2),(3)
Proved(4) 9 - 1,070 1,079 - - 1,079
Unproved 27 11 1,202 1,240 - - 1,240
- ---------------------------------------------------------------------------------------------------------------------------
Total property acquisitions 36 11 2,272 2,319 - - 2,319
- ---------------------------------------------------------------------------------------------------------------------------
Development 532 518 375 1,425 182 148 1,755
- --------------------------------------------------------------------------------------------------------------------------
TOTAL COSTS INCURRED $ 893 $ 601 $2,912 $4,406 $202 $148 $4,756
==========================================================================================================================
YEAR ENDED DECEMBER 31, 1998
Exploration
Wells $ 350 $ 108 $ 101 $ 559 $ 3 $ - $ 562
Geological and geophysical 49 31 112 192 16 - 208
Rentals and other 44 23 53 120 - - 120
- ---------------------------------------------------------------------------------------------------------------------------
Total exploration 443 162 266 871 19 - 890
- ---------------------------------------------------------------------------------------------------------------------------
Property acquisitions(2)
Proved(4) 12 - - 12 - - 12
Unproved 58 - 14 72 - - 72
- ---------------------------------------------------------------------------------------------------------------------------
Total property acquisitions 70 - 14 84 - - 84
- ---------------------------------------------------------------------------------------------------------------------------
Development 680 561 411 1,652 156 120 1,928
- ---------------------------------------------------------------------------------------------------------------------------
Total Costs Incurred $1,193 $ 723 $ 691 $2,607 $175 $120 $2,902
===========================================================================================================================
<FN>
(1) Includes costs incurred whether capitalized or expensed. Excludes support
equipment expenditures.
(2) Proved amounts include wells, equipment and facilities associated with
proved reserves.
(3)Includes acquisition costs and related deferred income taxes for purchases of
Rutherford-Moran Oil Corporation and Petrolera Argentina San Jorge S.A.
(4)Does not include properties acquired through property exchanges.
</FN>
</TABLE>
FS-33
<PAGE>
<TABLE>
<CAPTION>
TABLE II - CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES
Consolidated Companies Affiliated Companies
--------------------------------------- --------------------
Millions of dollars U.S. Africa Other Total CPI TCO Worldwide
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
AT DECEMBER 31, 2000
Unproved properties $ 337 $ 78 $ 1,459 $ 1,874 $ - $ 378 $ 2,252
Proved properties and related producing
assets 16,713 4,621 8,346 29,680 1,370 1,158 32,208
Support equipment 469 308 280 1,057 906 254 2,217
Deferred exploratory wells 101 204 95 400 - - 400
Other uncompleted projects 348 640 476 1,464 265 136 1,865
- --------------------------------------------------------------------------------------------------------------------------
GROSS CAPITALIZED COSTS 17,968 5,851 10,656 34,475 2,541 1,926 38,942
- --------------------------------------------------------------------------------------------------------------------------
Unproved properties valuation 128 59 219 406 - - 406
Proved producing properties -
Depreciation and depletion 11,991 2,363 3,774 18,128 751 131 19,010
Future abandonment and restoration 778 400 227 1,405 63 13 1,481
Support equipment depreciation 315 127 172 614 535 97 1,246
- --------------------------------------------------------------------------------------------------------------------------
Accumulated provisions 13,212 2,949 4,392 20,553 1,349 241 22,143
- --------------------------------------------------------------------------------------------------------------------------
NET CAPITALIZED COSTS $ 4,756 $2,902 $ 6,264 $13,922 $ 1,192 $1,685 $ 16,799
- --------------------------------------------------------------------------------------------------------------------------
AT DECEMBER 31, 1999
Unproved properties $ 317 $ 69 $ 1,441 $ 1,827 $ - $ 378 $ 2,205
Proved properties and related producing
assets 16,662 4,034 7,318 28,014 1,158 689 29,861
Support equipment 478 268 321 1,067 902 243 2,212
Deferred exploratory wells 136 172 66 374 - - 374
Other uncompleted projects 354 758 664 1,776 335 405 2,516
- --------------------------------------------------------------------------------------------------------------------------
GROSS CAPITALIZED COSTS 17,947 5,301 9,810 33,058 2,395 1,715 37,168
- --------------------------------------------------------------------------------------------------------------------------
Unproved properties valuation 133 53 157 343 - - 343
Proved producing properties -
Depreciation and depletion 11,953 1,993 3,071 17,017 681 99 17,797
Future abandonment and restoration 835 371 208 1,414 60 10 1,484
Support equipment depreciation 317 104 142 563 476 80 1,119
- --------------------------------------------------------------------------------------------------------------------------
Accumulated provisions 13,238 2,521 3,578 19,337 1,217 189 20,743
- --------------------------------------------------------------------------------------------------------------------------
NET CAPITALIZED COSTS $ 4,709 $2,780 $ 6,232 $13,721 $ 1,178 $1,526 $ 16,425
==========================================================================================================================
AT DECEMBER 31, 1998
Unproved properties $ 390 $ 58 $ 235 $ 683 $ - $ 378 $ 1,061
Proved properties and related producing
assets 16,759 3,672 6,253 26,684 1,015 629 28,328
Support equipment 472 182 307 961 768 232 1,961
Deferred exploratory wells 51 51 91 193 - - 193
Other uncompleted projects 700 893 383 1,976 408 245 2,629
- --------------------------------------------------------------------------------------------------------------------------
GROSS CAPITALIZED COSTS 18,372 4,856 7,269 30,497 2,191 1,484 34,172
- --------------------------------------------------------------------------------------------------------------------------
Unproved properties valuation 151 49 110 310 - - 310
Proved producing properties -
Depreciation and depletion 11,808 1,719 2,705 16,232 689 72 16,993
Future abandonment and restoration 861 337 187 1,385 57 8 1,450
Support equipment depreciation 315 90 127 532 373 67 972
- --------------------------------------------------------------------------------------------------------------------------
Accumulated provisions 13,135 2,195 3,129 18,459 1,119 147 19,725
- --------------------------------------------------------------------------------------------------------------------------
NET CAPITALIZED COSTS $ 5,237 $2,661 $ 4,140 $12,038 $ 1,072 $1,337 $ 14,447
==========================================================================================================================
</TABLE>
TABLE III - RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES(1)
The company's results of operations from oil and gas producing activities for
the years 2000, 1999 and 1998 are shown in the following table.
Net income from exploration and production activities as reported on page
FS-7 reflects income taxes computed on an effective rate basis. In accordance
with FAS No. 69, income taxes in Table III are based on statutory tax rates,
reflecting allowable deductions and tax credits. Interest income and expense are
excluded from the results reported in Table III and from the net income amounts
on page FS-7.
FS-34
<PAGE>
<TABLE>
<CAPTION>
TABLE III - RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES(1)
- Continued
Consolidated Companies Affiliated Companies
------------------------------------------- --------------------
Millions of dollars U.S. Africa Other Total CPI TCO Worldwide
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31, 2000
Revenues from net production
Sales $ 2,498 $ 2,804 $2,351 $ 7,653 $ 50 $ 710 $ 8,413
Transfers 2,762 506 952 4,220 831 - 5,051
- ---------------------------------------------------------------------------------------------------------------------------
Total 5,260 3,310 3,303 11,873 881 710 13,464
Production expenses (1,112) (378) (520) (2,010) (223) (114) (2,347)
Proved producing properties: depreciation,
depletion and abandonment provision (862) (316) (619) (1,797) (129) (53) (1,979)
Exploration expenses (265) (62) (237) (564) (14) - (578)
Unproved properties valuation (22) (6) (82) (110) - - (110)
Other income (expense)(2) (26) 61 243 278 (2) (56) 220
- ---------------------------------------------------------------------------------------------------------------------------
Results before income taxes 2,973 2,609 2,088 7,670 513 487 8,670
Income tax expense (1,100) (1,942) (924) (3,966) (258) (146) (4,370)
- ---------------------------------------------------------------------------------------------------------------------------
RESULTS OF PRODUCING OPERATIONS $ 1,873 $ 667 $1,164 $ 3,704 $ 255 $ 341 $ 4,300
===========================================================================================================================
YEAR ENDED DECEMBER 31, 1999
Revenues from net production
Sales $ 1,449 $ 1,756 $1,415 $ 4,620 $ 24 $ 356 $ 5,000
Transfers 1,626 299 597 2,522 592 - 3,114
- ---------------------------------------------------------------------------------------------------------------------------
Total 3,075 2,055 2,012 7,142 616 356 8,114
Production expenses (1,005) (340) (411) (1,756) (206) (88) (2,050)
Proved producing properties: depreciation,
depletion and abandonment provision (764) (311) (433) (1,508) (109) (47) (1,664)
Exploration expenses (167) (97) (274) (538) (17) - (555)
Unproved properties valuation (22) (5) (36) (63) - - (63)
Other income (expense)(2),(3) (358) (53) 5 (406) (2) (9) (417)
- ---------------------------------------------------------------------------------------------------------------------------
Results before income taxes 759 1,249 863 2,871 282 212 3,365
Income tax expense (257) (848) (416) (1,521) (143) (63) (1,727)
- ---------------------------------------------------------------------------------------------------------------------------
RESULTS OF PRODUCING OPERATIONS $ 502 $ 401 $ 447 $ 1,350 $ 139 $ 149 $ 1,638
===========================================================================================================================
YEAR ENDED DECEMBER 31, 1998
Revenues from net production
Sales $ 1,386 $ 1,118 $ 757 $ 3,261 $ 28 $ 176 $ 3,465
Transfers 1,185 212 458 1,855 454 - 2,309
- ---------------------------------------------------------------------------------------------------------------------------
Total 2,571 1,330 1,215 5,116 482 176 5,774
Production expenses (1,172) (346) (304) (1,822) (153) (76) (2,051)
Proved producing properties: depreciation,
depletion and abandonment provision (714) (301) (316) (1,331) (106) (40) (1,477)
Exploration expenses (213) (53) (212) (478) (16) - (494)
Unproved properties valuation (20) (8) (16) (44) - - (44)
Other income (expense)(2),(3) 54 48 85 187 2 (7) 182
- ---------------------------------------------------------------------------------------------------------------------------
Results before income taxes 506 670 452 1,628 209 53 1,890
Income tax expense (163) (328) (323) (814) (102) (16) (932)
- ---------------------------------------------------------------------------------------------------------------------------
RESULTS OF PRODUCING OPERATIONS $ 343 $ 342 $ 129 $ 814 $ 107 $ 37 $ 958
===========================================================================================================================
<FN>
(1)The value of owned production consumed as fuel has been eliminated from
revenues and production expenses, and the related volumes have been deducted
from net production in calculating the unit average sales price and production
cost; this has no effect on the results of producing operations.
(2)Includes gas processing fees, net sulfur income, currency transaction gains
and losses, certain significant impairment write-downs, miscellaneous expenses,
etc. Also includes net income from related oil and gas activities that do not
have oil and gas reserves attributed to them (e.g., net income from technical
and operating service agreements) and items identified in the Management's
Discussion and Analysis on page FS-7.
(3)Conformed to 2000 presentation; removed equity earnings for Dynegy Inc.
</FN>
</TABLE>
FS-35
<PAGE>
<TABLE>
<CAPTION>
TABLE III - RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES (1)(2)
- Continued
Consolidated Companies Affiliated Companies
-------------------------------- --------------------
Per-unit average sales price and production cost(1),(2) U.S. Africa Other Total CPI TCO Worldwide
- -------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31, 2000
Average sales prices
Liquids, per barrel $26.35 $26.75 $26.67 $26.59 $22.41 $20.14 $25.63
Natural gas, per thousand cubic feet 4.04 0.03 2.98 3.65 - 0.13 3.55
Average production costs, per barrel 5.37 2.99 3.80 4.27 5.67 2.91 4.28
===============================================================================================================================
YEAR ENDED DECEMBER 31, 1999
Average sales prices
Liquids, per barrel $15.73 $17.27 $17.69 $16.82 $13.40 $10.53 $15.90
Natural gas, per thousand cubic feet 2.17 0.05 2.21 2.14 - 0.38 2.10
Average production costs, per barrel 4.73 2.81 3.32 3.84 4.47 2.39 3.79
===============================================================================================================================
YEAR ENDED DECEMBER 31, 1998
Average sales prices
Liquids, per barrel $11.27 $11.49 $11.21 $11.34 $ 9.73 $ 5.53 $10.68
Natural gas, per thousand cubic feet 2.02 0.07 2.26 2.04 - 0.57 2.01
Average production costs, per barrel 5.30 2.94 2.93 4.12 3.10 2.32 3.91
===============================================================================================================================
Average sales price for liquids ($/Bbl)
December 2000 $25.41 $23.23 $24.87 $24.43 $22.33 $24.39 $24.21
December 1999 22.25 24.88 24.06 23.68 23.68 11.55 22.65
December 1998 8.86 9.55 9.04 9.17 8.33 3.69 8.58
===============================================================================================================================
Average sales price for natural gas ($/MCF)
December 2000 $ 7.70 $ 0.04 $ 4.16 $ 6.47 $ - $ 0.25 $ 6.19
December 1999 2.20 0.04 2.41 2.23 - 0.38 2.18
December 1998 2.23 - 2.47 2.29 - 0.57 2.26
===============================================================================================================================
<FN>
(1)The value of owned production consumed as fuel has been eliminated from
revenues and production expenses, and the related volumes have been deducted
from net production in calculating the unit average sales price and production
cost; this has no effect on the results of producing operations.
(2)Natural gas converted to crude oil-equivalent gas (OEG) barrels at a rate of
6 MCF=1 OEG barrel.
</FN>
</TABLE>
TABLE IV - RESERVE QUANTITY INFORMATION
The company's estimated net proved underground oil and gas reserves and changes
thereto for the years 2000, 1999 and 1998 are shown in the following table.
Proved reserves are estimated by company asset teams composed of earth
scientists and reservoir engineers. These proved reserve estimates are reviewed
annually by the corporation's Reserves Advisory Committee to ensure that
rigorous professional standards and the reserves definitions prescribed by the
U.S. Securities and Exchange Commission are consistently applied throughout the
company.
Proved reserves are the estimated quantities that geologic and engineering
data demonstrate with reasonable certainty to be recoverable in future years
from known reservoirs under existing economic and operating conditions. Due to
the inherent uncertainties and the limited nature of reservoir data, estimates
of underground reserves are subject to change as additional information becomes
available.
Proved reserves do not include additional quantities recoverable beyond the
term of the lease or concession agreement or that may result from extensions of
currently proved areas or from applying secondary or tertiary recovery processes
not yet tested and determined to be economic.
Proved developed reserves are the quantities expected to be recovered
through existing wells with existing equipment and operating methods.
"Net" reserves exclude royalties and interests owned by others and reflect
contractual arrangements and royalty obligations in effect at the time of the
estimate.
Chevron operates under a risked service agreement Venezuela's Block LL-652,
located in the northeast section of Lake Maracaibo. Chevron is accounting for
LL-652 as an oil and gas activity and, at December 31, 2000, had recorded 57
million barrels of proved crude oil reserves.
No reserve quantities have been recorded for the company's other service
agreement in Venezuela, the Boscan Field.
FS-36
<PAGE>
<TABLE>
<CAPTION>
TABLE IV - RESERVE QUANTITY INFORMATION - Continued
NET PROVED RESERVES OF CRUDE OIL, CONDENSATE NET PROVED RESERVES OF NATURAL GAS
AND NATURAL GAS LIQUIDS Millions of barrels Billions of cubic feet
------------------------------------------------- ---------------------------------------------------
Consolidated Companies Affiliates Consolidated Companies Affiliates
---------------------------- -------------- World- ---------------------------- -------------- World-
U.S. Africa Other Total CPI TCO wide U.S. Africa Other Total CPI TCO wide
- ---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
RESERVES AT
JANUARY 1, 1998 1,196 1,131 519 2,846 578 1,082 4,506 4,991 223 3,187 8,401 161 1,401 9,963
Changes attributable to:
Revisions (1) 106 28 133 110 (3) 7 250 (151) 77 13 (61) 7 (17) (71)
Improved recovery 36 88 36 160 25 - 185 7 - - 7 12 - 19
Extensions
and discoveries 43 92 7 142 2 16 160 372 - 3 375 1 21 397
Purchases(1) 5 - 30 35 - - 35 32 - 5 37 - - 37
Sales(2) (12) - (22) (34) - - (34) (119) - (50) (169) - - (169)
Production (119) (117) (77) (313) (62) (30) (405) (635) (12) (175) (822) (30) (21) (873)
- --------------------------------------------------------------------------- ---------------------------------------------------
RESERVES AT
DECEMBER 31, 1998 1,148 1,300 521 2,969 653 1,075 4,697 4,497 288 2,983 7,768 151 1,384 9,303
Changes attributable to:
Revisions (23) 3 (24) (44) (98)(3) 115 (27) (426) 49 30 (347) 2 126 (219)
Improved recovery 44 62 20 126 30 - 156 7 - 8 15 1 - 16
Extensions
and discoveries 50 45 17 112 2 76 190 347 - 86 433 5 98 536
Purchases(1) 1 - 213 214 - - 214 35 - 372 407 - - 407
Sales(2) (33) - (2) (35) - - (35) (74) - - (74) - - (74)
Production (115) (120) (84) (319) (59) (33) (411) (598) (15) (248) (861) (25) (27) (913)
- --------------------------------------------------------------------------- ---------------------------------------------------
RESERVES AT
DECEMBER 31, 1999 1,072 1,290 661 3,023 528 1,233 4,784 3,788 322 3,231 7,341 134 1,581 9,056
Changes attributable to:
Revisions (5) 56 4 55 35 105 195 (29) 450 140 561 8 126 695
Improved recovery 58 20 9 87 16 - 103 12 - 5 17 - - 17
Extensions
and discoveries 46 92 65 203 2 7 212 405 1 371 777 4 9 790
Purchases(1) 5 131 3 139 - - 139 18 12 - 30 - - 30
Sales(2) (8) - - (8) - - (8) (131) - (1) (132) - - (132)
Production (114) (124) (98) (336) (53) (35) (424) (570) (17) (260) (847) (24) (33) (904)
- --------------------------------------------------------------------------- ---------------------------------------------------
RESERVES AT
DECEMBER 31, 2000 1,054 1,465 644 3,163 528 1,310 5,001 3,493 768 3,486 7,747 122 1,683 9,552
=========================================================================== ===================================================
Developed reserves
- --------------------------------------------------------------------------- ---------------------------------------------------
At January 1, 1998 1,025 721 293 2,039 435 532 3,006 4,391 223 1,695 6,309 145 688 7,142
At December 31, 1998 982 891 342 2,215 436 646 3,297 3,918 263 2,074 6,255 135 832 7,222
At December 31, 1999 905 940 489 2,334 340 790 3,464 3,345 272 2,243 5,860 131 1,011 7,002
At December 31, 2000 881 943 460 2,284 327 795 3,406 3,109 290 2,929 6,328 121 1,019 7,468
=================================================================================================================================
<FN>
(1)Includes reserves acquired through property exchanges.
(2)Includes reserves disposed of through property exchanges.
(3)Mainly includes crude reserves revisions associated with CPI's cost-recovery
formula.
</FN>
</TABLE>
TABLE V - STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO
PROVED OIL AND GAS RESERVES
The standardized measure of discounted future net cash flows, related to the
above proved oil and gas reserves, is calculated in accordance with the
requirements of FAS No. 69. Estimated future cash inflows from production are
computed by applying year-end prices for oil and gas to year-end quantities of
estimated net proved reserves. Future price changes are limited to those
provided by contractual arrangements in existence at the end of each reporting
year. Future development and production costs are those estimated future
expenditures necessary to develop and produce year-end estimated proved reserves
based on year-end cost indices, assuming continuation of year-end economic
conditions. Estimated future income taxes are calculated by applying appropriate
year-end statutory tax rates. These rates reflect allowable deductions and tax
credits and are applied to estimated future pretax net cash flows, less the tax
basis of related assets. Discounted future net cash flows are calculated using
10 percent midperiod discount factors. Discounting requires a year-by-year
estimate of when future expenditures will be incurred and when reserves will be
produced.
The information provided does not represent management's estimate of the
company's expected future cash flows or value of proved oil and gas reserves.
Estimates of proved reserve quantities are imprecise and change over time as new
information becomes available. Moreover, probable and possible reserves, which
may become proved in the future, are excluded from the calculations. The
arbitrary valuation prescribed under FAS No. 69 requires assumptions as to the
timing and amount of future development and production costs. The calculations
are made as of December 31 each year and should not be relied upon as an
indication of the company's future cash flows or value of its oil and gas
reserves.
FS-37
<PAGE>
<TABLE>
<CAPTION>
TABLE V - STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO
PROVED OIL AND GAS RESERVES - Continued
Consolidated Companies Affiliated Companies
---------------------------------------- ---------------------
Millions of dollars U.S. Africa Other Total CPI TCO Worldwide
- -------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
AT DECEMBER 31, 2000
Future cash inflows from production $ 60,830 $ 33,950 $ 27,490 $122,270 $ 12,700 $ 30,350 $ 165,320
Future production and development costs (13,610) (7,740) (6,410) (27,760) (8,560) (7,250) (43,570)
Future income taxes (16,590) (15,690) (7,720) (40,000) (1,720) (6,440) (48,160)
- -------------------------------------------------------------------------------------------------------------------------
Undiscounted future net cash flows 30,630 10,520 13,360 54,510 2,420 16,660 73,590
10 percent midyear annual discount for
timing of estimated cash flows (12,340) (4,130) (5,210) (21,680) (930) (11,180) (33,790)
- -------------------------------------------------------------------------------------------------------------------------
STANDARDIZED MEASURE OF DISCOUNTED
FUTURE NET CASH FLOWS $ 18,290 $ 6,390 $ 8,150 $ 32,830 $ 1,490 $ 5,480 $ 39,800
=========================================================================================================================
AT DECEMBER 31, 1999
Future cash inflows from production $ 31,650 $ 31,830 $ 23,690 $ 87,170 $ 11,950 $ 24,380 $ 123,500
Future production and development costs (11,350) (6,030) (5,420) (22,800) (7,830) (4,900) (35,530)
Future income taxes (7,050) (16,490) (6,200) (29,740) (1,820) (4,980) (36,540)
- -------------------------------------------------------------------------------------------------------------------------
Undiscounted future net cash flows 13,250 9,310 12,070 34,630 2,300 14,500 51,430
10 percent midyear annual discount for
timing of estimated cash flows (5,480) (2,920) (4,590) (12,990) (900) (10,400) (24,290)
- -------------------------------------------------------------------------------------------------------------------------
Standardized Measure of Discounted
Future Net Cash Flows $ 7,770 $ 6,390 $ 7,480 $ 21,640 $ 1,400 $ 4,100 $ 27,140
=========================================================================================================================
AT DECEMBER 31, 1998
Future cash inflows from production $ 19,810 $ 12,560 $ 13,010 $ 45,380 $ 6,020 $ 8,360 $ 59,760
Future production and development costs (12,940) (6,980) (4,930) (24,850) (4,470) (5,860) (35,180)
Future income taxes (1,970) (2,110) (2,850) (6,930) (660) (200) (7,790)
- -------------------------------------------------------------------------------------------------------------------------
Undiscounted future net cash flows 4,900 3,470 5,230 13,600 890 2,300 16,790
10 percent midyear annual discount for
timing of estimated cash flows (1,880) (1,070) (2,190) (5,140) (390) (1,990) (7,520)
- -------------------------------------------------------------------------------------------------------------------------
Standardized Measure of Discounted
Future Net Cash Flows $ 3,020 $ 2,400 $ 3,040 $ 8,460 $ 500 $ 310 $ 9,270
=========================================================================================================================
</TABLE>
<TABLE>
<CAPTION>
TABLE VI - CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS FROM PROVED RESERVES
Consolidated Companies Affiliated Companies Worldwide
------------------------- ------------------------ ---------------------------
Millions of dollars 2000 1999 1998 2000 1999 1998 2000 1999 1998
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
PRESENT VALUE AT JANUARY 1 $21,640 $ 8,460 $13,110 $5,500 $ 810 $ 1,890 $27,140 $ 9,270 $15,000
- --------------------------------------------------------------------------------------------------------------------------
Sales and transfers of oil and gas
produced, net of production costs (9,863) (5,385) (3,294) (1,254) (679) (429) (11,117) (6,064) (3,723)
Development costs incurred 1,488 1,425 1,652 408 330 276 1,896 1,755 1,928
Purchases of reserves 1,154 2,811 208 - - - 1,154 2,811 208
Sales of reserves (1,020) (344) (347) - - - (1,020) (344) (347)
Extensions, discoveries and improved
recovery, less related costs 5,147 2,886 813 132 385 49 5,279 3,271 862
Revisions of previous quantity
estimates (1,093) (503) 262 1,281 84 280 188 (419) 542
Net changes in prices, development
and production costs 17,105 25,457 (11,321) 625 6,938 (2,159) 17,730 32,395 (13,480)
Accretion of discount 3,672 1,165 2,096 817 135 289 4,489 1,300 2,385
Net change in income tax (5,400) (14,332) 5,281 (539) (2,503) 614 (5,939) (16,835) 5,895
- --------------------------------------------------------------------------------------------------------------------------
Net change for the year 11,190 13,180 (4,650) 1,470 4,690 (1,080) 12,660 17,870 (5,730)
- --------------------------------------------------------------------------------------------------------------------------
PRESENT VALUE AT DECEMBER 31 $32,830 $21,640 $ 8,460 $6,970 $5,500 $ 810 $39,800 $27,140 $ 9,270
==========================================================================================================================
</TABLE>
The changes in present values between years, which can be significant, reflect
changes in estimated proved reserve quantities and prices and assumptions used
in forecasting production volumes and costs. Changes in the timing of production
are included with "Revisions of previous quantity estimates."
FS-38
<PAGE>
<TABLE>
<CAPTION>
FIVE YEAR FINANCIAL SUMMARY
Millions of dollars, except per-share amounts 2000 1999 1998 1997 1996
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
CONSOLIDATED STATEMENT OF INCOME DATA
REVENUES
Sales and other operating revenues
Refined products $20,484 $13,742 $11,461 $15,586 $15,785
Crude oil 17,075 10,078 7,781 11,296 12,397
Natural gas 3,615 2,256 2,104 2,568 3,299
Natural gas liquids 813 432 322 553 1,167
Other petroleum 1,460 1,115 1,063 1,118 1,184
Chemicals 2,757 3,544 3,054 3,520 3,422
Coal and other minerals 279 360 399 359 340
Excise taxes 4,060 3,910 3,756 5,587 5,202
Corporate and other 49 11 3 9 (14)
- -------------------------------------------------------------------------------------------------- ---------------------------
Total sales and other operating revenues 50,592 35,448 29,943 40,596 42,782
Income from equity affiliates 750 526 228 688 767
Other income 787 612 386 679 344
- -------------------------------------------------------------------------------------------------- ---------------------------
TOTAL REVENUES 52,129 36,586 30,557 41,963 43,893
COSTS, OTHER DEDUCTIONS AND INCOME TAXES 46,944 34,516 29,218 38,707 41,286
- -------------------------------------------------------------------------------------------------- ---------------------------
NET INCOME $ 5,185 $ 2,070 $ 1,339 $ 3,256 $ 2,607
==============================================================================================================================
NET INCOME PER SHARE OF COMMON STOCK - BASIC $7.98 $3.16 $2.05 $4.97 $3.99
- DILUTED $7.97 $3.14 $2.04 $4.95 $3.98
==============================================================================================================================
CASH DIVIDENDS PER SHARE $2.60 $2.48 $2.44 $2.28 $2.08
==============================================================================================================================
CONSOLIDATED BALANCE SHEET DATA (AT DECEMBER 31)
Current assets $ 8,213 $ 8,297 $ 6,297 $ 7,006 $ 7,942
Properties, plant and equipment (net) 22,894 25,317 23,729 22,671 21,496
Total assets 41,264 40,668 36,540 35,473 34,854
Short-term debt 1,079 3,434 3,165 1,637 2,706
Other current liabilities 6,595 5,455 4,001 5,309 6,201
Long-term debt and capital lease obligations 5,153 5,485 4,393 4,431 3,988
Stockholders' equity 19,925 17,749 17,034 17,472 15,623
Per share $ 31.08 $ 27.04 $ 26.08 $ 26.64 $ 23.92
==============================================================================================================================
SELECTED DATA
Return on average stockholders' equity 27.5% 11.9% 7.8% 19.7% 17.4%
Return on average capital employed 20.8% 9.4% 6.7% 15.0% 12.7%
Total debt/total debt plus equity 23.8% 33.4% 30.7% 25.8% 30.0%
Capital and exploratory expenditures(1) $ 5,153 $ 6,133 $ 5,314 $ 5,541 $ 4,840
Common stock price - High $ 94.88 $104.94 $ 90.19 $ 89.19 $ 68.38
- Low $ 69.94 $ 73.13 $ 67.75 $ 61.75 $ 51.00
- Year-end $ 84.44 $ 86.63 $ 82.94 $ 77.00 $ 65.00
Common shares outstanding at year-end (in thousands) 641,060 656,346 653,026 655,931 653,086
Weighted-average shares outstanding
for the year (in thousands) 649,014 655,468 653,667 654,991 652,769
Number of employees at year-end(2) 34,610 36,490 39,191 39,362 40,820
==============================================================================================================================
<FN>
(1) Includes equity in affiliates' expenditures. $967 $782 $994 $1,174 $983
(2) Includes service station personnel.
</FN>
</TABLE>
FS-39
CALTEX GROUP OF COMPANIES
COMBINED FINANCIAL STATEMENTS
December 31, 2000
C-1
<PAGE>
CALTEX GROUP OF COMPANIES
COMBINED FINANCIAL STATEMENTS
DECEMBER 31, 2000
INDEX
Page
------
General Information C-3 to C-4
Independent Auditors' Report C-5
Combined Statement of Income C-6
Combined Statement of Comprehensive Income C-6
Combined Balance Sheet C-7
Combined Statement of Stockholders' Equity C-8
Combined Statement of Cash Flows C-9
Notes to Combined Financial Statements C-10 to C-20
Note: Financial statement schedules are omitted as permitted by Rule 4.03 and
Rule 5.04 of Regulation S-X.
C-2
<PAGE>
CALTEX GROUP OF COMPANIES
GENERAL INFORMATION
The Caltex Group of Companies (Group) is jointly owned 50% each by Chevron
Corporation and Texaco Inc. (collectively, the Stockholders) and was created in
1936 by its two owners to explore for, produce, transport, refine and market
crude oil and petroleum products. The Group is comprised of the following
companies:
o Caltex Corporation, a company incorporated in Delaware with its corporate
headquarters in Singapore, that, through its many subsidiaries and
affiliates, conducts refining, transporting, trading, and marketing
activities in the Eastern Hemisphere;
o P. T. Caltex Pacific Indonesia, an exploration and production company
incorporated and operating in Indonesia; and,
o American Overseas Petroleum Limited, a company incorporated in
the Bahamas.
A brief description of each company's operations and other items follows. All
reported amounts are in U.S. dollars.
Caltex Corporation (Caltex)
- ---------------------------
Through its subsidiaries and affiliates, Caltex operates in approximately
57 countries, principally in Africa, Asia, the Middle East, New Zealand and
Australia. These geographic areas comprise a broad diversity of mature,
developing, and emerging markets. At the end of 2000, it had total assets of
$7.7 billion, sales of 1.4 million barrels of crude oil and petroleum products
per day, and total revenues of $18.4 billion for the year. Caltex is involved in
all aspects of the downstream business: marketing, refining, distribution,
transportation, storage, supply and trading operations; the corporation is also
active in the petrochemical business through its affiliate in Korea. At year-end
2000, Caltex had more than 7,200 employees.
The majority of refining and certain marketing operations are conducted
through joint ventures. Caltex has equity interests in 10 refineries with equity
refining capacity of approximately 846,000 barrels per day. Additionally, it has
interests in two lubricant refineries, 17 lubricant blending plants, and a
network of ocean terminals and depots. Caltex also has an interest in a fleet of
vessels, and owns or has equity interests in numerous pipelines. Caltex conducts
international crude oil and petroleum product logistics and trading operations
from a subsidiary in Singapore.
P. T. Caltex Pacific Indonesia (CPI)
- ------------------------------------
CPI holds a Production Sharing Contract (PSC) in Central Sumatra through
the year 2021. CPI also acts as operator in Sumatra for eight other petroleum
contract areas, with 33 fields, which are jointly held by Chevron and Texaco. At
the end of 2000, CPI had total assets of $2.5 billion, which generated total
revenues of $2.0 billion for the year. Exploration is pursued over an area
comprising 18.3 million acres with production established in the giant Minas and
Duri fields, along with smaller fields. Gross production from fields operated by
CPI for 2000 was over 707,000 barrels of crude oil per day. CPI entitlements are
sold to its Stockholders, who use them in their systems or sell them to third
parties. At year-end 2000, CPI had approximately 5,800 employees, all located in
Indonesia.
American Overseas Petroleum Limited (AOPL)
- ------------------------------------------
AOPL and its subsidiary, Amoseas Indonesia, Inc, provide services for CPI
and manage certain geothermal steam operations and geothermal power generation
projects in Indonesia in which Chevron and Texaco have interests. At year-end
2000, AOPL had approximately 186 employees, of which 9% were located in the
United States.
C-3
<PAGE>
CALTEX GROUP OF COMPANIES
GENERAL INFORMATION
Supplemental Market Risk Disclosures
- ------------------------------------
The Group uses various derivative financial instruments for hedging and
trading purposes. These instruments principally include interest rate and/or
currency swap contracts, forward and option contracts to buy and sell foreign
currencies, and commodity futures, options, swaps and other derivative
instruments. Hedged market risk exposures include certain portions of assets,
liabilities, future commitments and anticipated sales. Positions are adjusted
for changes in the exposures being hedged. Since the Group hedges only a portion
of its market risk exposures, exposure remains on the unhedged portion. The
Notes to the Combined Financial Statements provide additional data relating to
derivatives and applicable accounting policies.
Debt and debt-related derivatives - The Group is exposed to interest rate risk
on its short-term and long-term debt with variable interest rates (approximately
$1.9 billion and $2.2 billion, before the effects of related net interest rate
swaps of $0.3 billion and $0.4 billion, at December 31, 2000 and 1999,
respectively). The Group seeks to balance the benefit of lower cost variable
rate debt, having inherent increased risk, with more expensive, but lower risk
fixed rate debt. This is accomplished through adjusting the mix of fixed and
variable rate debt, as well as the use of derivative financial instruments,
principally interest rate swaps.
Based on the overall interest rate exposure on variable rate debt and
interest rate swaps at December 31, 2000 and 1999, a hypothetical change in the
interest rates of 2% would change net income by approximately $23 million and
$25 million in 2000 and 1999, respectively.
Crude oil and petroleum product derivatives - The Group uses established
petroleum futures exchanges, as well as "over-the-counter" instruments,
including futures, options, swaps, and other derivative products to hedge a
portion of the market risks associated with its crude oil and petroleum product
purchases and sales. The Group also enters into derivative contracts as part of
its crude oil and petroleum product trading activities.
The Group had net open petroleum derivative purchase contracts of
approximately $146 million and $127 million at December 31, 2000 and 1999,
respectively. As a sensitivity for these contracts, a hypothetical 10% change in
crude oil and petroleum product prices would change net income by approximately
$10 million and $9 million in 2000 and 1999, respectively.
Currency-related derivatives - The Group is exposed to foreign currency exchange
risk in the countries in which it operates. To hedge against adverse changes in
foreign currency exchange rates against the U.S. dollar, the Group sometimes
enters into forward exchange and options contracts. Depending on the exposure
being hedged, the Group either purchases or sells selected foreign currencies.
The Group had net foreign currency purchase contracts of approximately $191
million and $279 million at December 31, 2000 and 1999, respectively, to hedge
certain specific transactions or net exposures including foreign currency
denominated debt. A hypothetical 10% change in exchange rates against the U.S.
dollar would not result in a net material change in the Group's operating
results or cash flows from the derivatives and their related underlying hedged
positions in 2000 or 1999.
New Accounting Standard
- -----------------------
Statement of Financial Accounting Standards No. 133 (SFAS No. 133),
"Accounting for Derivative Instruments and Hedging Activities", as amended by
SFAS No. 137 and No. 138, will be adopted by the Group beginning January 1,
2001. SFAS No. 133/138 require companies to record derivatives on the balance
sheet as assets or liabilities and measure those derivatives at fair value.
Changes in the fair values of derivatives are to be recorded each period in
current earnings or other comprehensive income, depending on whether a
derivative is designated as part of a hedge transaction and the type of exposure
being hedged.
Based on its current level of activity with derivative instruments, the
Group does not expect the adoption of SFAS No. 133/138 to have significant
impact on results of operations, other comprehensive income or financial
position.
C-4
<PAGE>
Independent Auditors' Report
----------------------------
To the Stockholders
The Caltex Group of Companies:
We have audited the accompanying combined balance sheets of the Caltex
Group of Companies as of December 31, 2000 and 1999, and the related combined
statements of income, comprehensive income, stockholders' equity, and cash flows
for each of the years in the three-year period ended December 31, 2000, all
expressed in United States of America dollars. These combined financial
statements are the responsibility of the Group's management. Our responsibility
is to express an opinion on these combined financial statements based on our
audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the combined financial statements referred to above
present fairly, in all material respects, the financial position of the Caltex
Group of Companies as of December 31, 2000 and 1999 and the results of its
operations and its cash flows for each of the years in the three-year period
ended December 31, 2000, in conformity with accounting principles generally
accepted in the United States of America.
As discussed in Note 2 to the combined financial statements, the Group
changed its method of accounting for start-up costs in 1998 to comply with the
provisions of the AICPA's Statement of Position 98-5 - "Reporting on the Costs
of Start-up Activities".
/s/ KPMG
KPMG
Singapore
February 8, 2001
C-5
<PAGE>
<TABLE>
<CAPTION>
CALTEX GROUP OF COMPANIES
COMBINED STATEMENT OF INCOME
Year ended December 31,
------------------------------------------
(Millions of U.S. dollars)
2000 1999 1998
--------- --------- ---------
<S> <C> <C> <C>
Revenues:
Sales and other operating revenues(1) $ 20,239 $ 14,942 $ 11,522
Gain on sale of investment in affiliate - 18 -
Income in equity affiliates 71 252 108
Dividends, interest and other income 62 62 97
--------- --------- ---------
Total revenues 20,372 15,274 11,727
Costs and deductions:
Cost of sales and operating expenses(2) 17,991 13,134 9,763
Selling, general and administrative expenses 515 582 676
Depreciation, depletion and amortization 494 459 431
Maintenance and repairs 129 154 147
Foreign exchange - net (37) 11 16
Interest expense 192 152 172
Minority interest - 2 3
--------- --------- ---------
Total costs and deductions 19,284 14,494 11,208
--------- --------- ---------
Income before income taxes 1,088 780 519
Provision for income taxes 569 390 326
--------- --------- ---------
Income before cumulative effect of accounting change 519 390 193
Cumulative effect of accounting change (no tax benefit) - - (50)
--------- --------- ---------
Net income $ 519 $ 390 $ 143
========= ========= =========
(1) Includes sales to:
Stockholders $2,924 $2,275 $1,555
Affiliates 5,454 3,970 2,121
(2) Includes purchases from:
Stockholders $2,970 $1,491 $1,455
Affiliates 1,888 1,121 1,353
</TABLE>
<TABLE>
<CAPTION>
CALTEX GROUP OF COMPANIES
COMBINED STATEMENT OF COMPREHENSIVE INCOME
Year ended December 31,
-----------------------------------------
(Millions of U.S. dollars)
2000 1999 1998
--------- -------- --------
<S> <C> <C> <C>
Net income $ 519 $ 390 $ 143
Other comprehensive income:
Currency translation adjustments:
Change during the year (14) (5) (10)
Reclassification to net income for sale of investment in affiliate - (63) -
Unrealized gains/(losses) on investments:
Change during the year 3 32 8
Reclassification of gains included in net income (1) (64) -
Related income tax benefit (expense) - 11 (1)
--------- -------- --------
Total other comprehensive loss (12) (89) (3)
--------- -------- --------
Comprehensive income $ 507 $ 301 $ 140
========= ======== ========
<FN>
See accompanying notes to combined financial statements.
</FN>
</TABLE>
C-6
<PAGE>
<TABLE>
<CAPTION>
CALTEX GROUP OF COMPANIES
COMBINED BALANCE SHEET
As of December 31,
------------------------
(Millions of U.S. dollars)
2000 1999
------- -------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents, including time deposits of $13 in 2000
and $12 in 1999 $ 219 $ 225
Marketable securities 11 117
Accounts and notes receivable, less allowance for doubtful
accounts of $58 in 2000 and $43 in 1999:
Trade 1,047 1,048
Affiliates 432 541
Other 224 132
------- -------
1,703 1,721
Inventories 557 623
Deferred income taxes 54 19
------- -------
Total current assets 2,544 2,705
Equity in affiliates 2,192 2,127
Miscellaneous investments and long-term receivables,
less allowance of $23 in 2000 and $24 in 1999 106 96
Property, plant, and equipment, at cost:
Producing 5,085 4,732
Refining 1,352 1,350
Marketing 3,241 3,194
Other 15 14
------- -------
9,693 9,290
Accumulated depreciation, depletion and amortization (4,552) (4,120)
------- -------
Net property, plant and equipment 5,141 5,170
Deferred income taxes 13 28
Prepaid and deferred charges 226 211
------- -------
Total assets $10,222 $10,337
======= =======
LIABILITIES
Current liabilities:
Short-term debt $ 1,639 $ 1,588
Accounts payable:
Trade and other 1,297 1,440
Stockholders 134 44
Affiliates 55 61
------- -------
1,486 1,545
Accrued liabilities 193 163
Estimated income taxes 67 99
------- -------
Total current liabilities 3,385 3,395
Long-term debt 853 1,054
Employee benefit plans 87 85
Deferred credits and other non-current liabilities 1,344 1,271
Deferred income taxes 232 234
Minority interest in subsidiary companies 27 23
------- -------
Total 5,928 6,062
STOCKHOLDERS' EQUITY
Common stock 355 355
Capital in excess of par value 2 2
Retained Earnings 4,148 4,117
Accumulated other comprehensive loss (211) (199)
------- -------
Total stockholders' equity 4,294 4,275
------- -------
Total liabilities and stockholders' equity $10,222 $10,337
======= =======
<FN>
See accompanying notes to combined financial statements.
</FN>
</TABLE>
C-7
<PAGE>
<TABLE>
<CAPTION>
CALTEX GROUP OF COMPANIES
COMBINED STATEMENT OF STOCKHOLDERS' EQUITY
Year ended December 31,
------------------------------------------
(Millions of U.S. dollars)
2000 1999 1998
--------- --------- ---------
<S> <C> <C> <C>
Common stock $ 355 $ 355 $ 355
========= ========= =========
Capital in excess of par value $ 2 $ 2 $ 2
========= ========= =========
Retained earnings:
Balance at beginning of year $4,117 $4,151 $ ,342
Net income 519 390 143
Cash dividends (488) (424) (334)
--------- --------- ---------
Balance at end of year $4,148 $4,117 $4,151
========= ========= =========
Accumulated other comprehensive loss:
Cumulative translation adjustments:
Balance at beginning of year $ (198) $ (130) $ (120)
Change during the year (14) (5) (10)
Reclassification to net income for sale of investment
in affiliate - (63) -
--------- --------- ---------
Balance at end of year $ (212) $ (198) $ (130)
Unrealized holding gain/(loss) on investments, net of tax:
Balance at beginning of year $ (1) $ 20 $ 13
Change during the year 3 19 7
Reclassification of gains included in net income (1) (40) -
--------- --------- ---------
Balance at end of year $ 1 $ (1) $ 20
========= ========= =========
Accumulated other comprehensive loss - end of year $ (211) $ (199) $ (110)
========= ========= =========
Total stockholders' equity - end of year $4,294 $4,275 $4,398
========= ========= =========
<FN>
See accompanying notes to combined financial statements.
</FN>
</TABLE>
C-8
<PAGE>
<TABLE>
<CAPTION>
CALTEX GROUP OF COMPANIES
COMBINED STATEMENT OF CASH FLOWS
Year ended December 31,
------------------------------------------
(Millions of U.S. dollars)
2000 1999 1998
--------- --------- ---------
<S> <C> <C> <C>
Operating activities:
Net income $ 519 $ 390 $ 143
Reconciliation to net cash provided by operating activities:
Depreciation, depletion and amortization 494 459 431
Dividends more (less) than income in equity affiliates 12 (181) (8)
Net losses on asset disposals/write-downs 6 34 50
Deferred income taxes (13) (58) 92
Prepaid charges and deferred credits 58 154 59
Changes in operating working capital:
Accounts and notes receivable (51) (653) 404
Inventories 66 (12) (28)
Accounts payable (10) 484 (105)
Accrued liabilities 40 (23) 41
Estimated income taxes (27) 14 4
Gain on sale of investment in affiliate - (18) -
Other (6) (25) 35
--------- --------- ---------
Net cash provided by operating activities 1,088 565 1,118
Investing activities:
Capital expenditures (509) (580) (761)
Investments in and advances to affiliates (87) (1) (211)
Purchase of investment instruments (108) (11) (114)
Sale of investment instruments 214 - 90
Proceeds from sale of investments in affiliates - 249 -
Proceeds from asset sales 21 16 9
--------- --------- ---------
Net cash used for investing activities (469) (327) (987)
Financing activities:
Debt with terms in excess of three months:
Borrowings 996 959 849
Repayments (727) (824) (701)
Net (decrease) increase in other debt (351) 118 (22)
Funding provided by minority interest - - 17
Dividends paid (488) (424) (334)
--------- --------- ---------
Net cash used for financing activities (570) (171) (191)
Effect of exchange rate changes on cash and cash equivalents (55) (20) (44)
--------- --------- ---------
Cash and cash equivalents:
Net change during the year (6) 47 (104)
Beginning of year balance 225 178 282
--------- --------- ---------
End of year balance $ 219 $ 225 $ 178
========= ========= =========
Net cash provided by operating activities includes the following cash payments
for interest and income taxes:
Interest paid (net of capitalized interest) $ 189 $ 142 $ 182
Income taxes paid 601 404 237
<FN>
See accompanying notes to combined financial statements.
</FN>
</TABLE>
C-9
<PAGE>
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
Note 1 - Summary of significant accounting policies
Principles of combination The combined financial statements of the Caltex Group
of Companies (Group) include the accounts of Caltex Corporation and
subsidiaries, American Overseas Petroleum Limited and subsidiary, and P.T.Caltex
Pacific Indonesia. Intercompany transactions and balances have been eliminated.
Subsidiaries include companies owned directly or indirectly more than 50% except
cases in which control does not rest with the Group. The Group's accounting
policies are in accordance with U.S. generally accepted accounting principles,
and the Group's reporting currency is the U.S. dollar.
Translation of foreign currencies The U.S. dollar is the functional currency for
all principal subsidiary and affiliate operations.
Estimates The preparation of financial statements in conformity with U.S.
generally accepted accounting principles requires estimates and assumptions that
affect the reported amounts of assets and liabilities, the disclosure of
contingent assets and liabilities at the date of the financial statements, and
the reported amounts of revenues and expenses during the reporting period.
Actual results may differ from those estimates.
Short-term investments All highly liquid investments are classified as available
for sale. Those with a maturity of three months or less when purchased are
considered as "Cash equivalents" and those with longer maturities are classified
as "Marketable securities".
Inventories Inventories are valued at the lower of cost or current market,
except as noted below. Crude oil and petroleum product inventory costs are
primarily determined using the last-in, first-out (LIFO) method, and include
applicable acquisition and refining costs, duties, import taxes, freight, etc.
Materials and supplies are stated at average cost. Certain trading-related
inventory, which is highly transitory in nature, is marked-to-market.
Investments and advances Investments in affiliates in which the Group has an
ownership interest of 20% to 50% or majority-owned investments where control
does not rest with the Group, are accounted for by the equity method. The
Group's share of earnings or losses of these companies is included in current
results, and the recorded investments reflect the underlying equity in each
company. Investments in other affiliates are carried at cost and dividends are
reported as income.
Property, plant and equipment Exploration and production activities are
accounted for under the successful efforts method. All costs for development
wells, related plant and equipment, and proved mineral interests in oil and gas
properties are capitalized. Costs of exploratory wells are capitalized pending
determination of whether the wells found proved reserves. Costs of wells that
are assigned proved reserves remain capitalized. Costs are also capitalized for
wells that find commercially producible reserves that cannot be classified as
proved, pending one or more of the following: (1) decisions on additional major
capital expenditures, (2) the results of additional exploratory wells that are
under way or firmly planned, and (3) securing final regulatory approvals for
development. Otherwise, well costs are expensed if a determination cannot be
made within one year following completion of drilling as to whether proved
reserves were found. All other exploratory wells and costs are expensed.
Long-lived assets, including proved developed oil and gas properties, are
assessed for possible impairment by comparing their carrying values to the
undiscounted-future-net-before-tax cash flows. Impaired assets are written down
to their fair values, generally their discounted cash flows. Impaired assets
held for sale are recorded at their fair value less cost to sell. For proved oil
and gas properties, the reviews are performed on a concession basis. Impairment
amounts are recorded as incremental depreciation expense in the period in which
the event occurs.
Depreciation, depletion and amortization expenses for capitalized costs
relating to producing properties, including intangible development costs, are
determined using the unit-of-production method by individual fields as the
proved developed reserves are produced. Depletion expenses for capitalized costs
of proved mineral interests are recognized using the unit-of-production method
by individual fields as the related proved reserves are produced. Periodic
valuation provisions for impairment of capitalized costs of unproved mineral
interests are expensed. All other assets are depreciated by class on a
straight-line basis using rates based upon the estimated useful life of each
class.
C-10
<PAGE>
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
Note 1 - Summary of significant accounting policies - continued
Maintenance and repairs necessary to maintain facilities in operating
condition are charged to income as incurred. Additions and improvements that
materially extend the life of assets are capitalized. Upon disposal of assets,
any net gain or loss is included in income.
Deferred credits Deferred credits primarily represent the Indonesian
government's interest in specific property, plant and equipment balances. Under
the Production Sharing Contract (PSC), the Indonesian government retains a
majority equity share of current production profits. Intangible development
costs (IDC) are capitalized for U.S. generally accepted accounting principles
under the successful efforts method, but are treated as period expenses for PSC
reporting. Other capitalized amounts are depreciated at an accelerated rate for
PSC reporting. The deferred credit balances recognize the government's share of
IDC and other reported capital costs that over the life of the PSC will be
included in income as depreciation, depletion and amortization and will be
applied against future production related profits.
Derivative financial instruments and energy trading contracts The Group uses
various derivative financial instruments for hedging purposes. These instruments
include interest rate and/or currency swap contracts, forward and options
contracts to buy and sell foreign currencies, and commodity futures, options,
swaps and other derivative instruments. Hedged market risk exposures include
certain portions of assets, liabilities, future commitments and anticipated
sales. Prior realized gains and losses on hedges of existing non-monetary assets
are included in the carrying value of those assets. Gains and losses related to
qualifying hedges of firm commitments or anticipated transactions are deferred
and recognized in income when the underlying hedged transaction is recognized in
income. If the derivative instrument ceases to be a hedge, the related gains and
losses are recognized currently in income. Gains and losses on derivative
instruments that do not qualify as hedges are recognized currently in income.
The Group also enters into energy contracts as a part of its crude oil and
petroleum product trading activities. Trading contracts are recorded at market
value and related gains and losses are recorded on a net basis in cost of sales
and operating expenses as the market values change. The net gains and losses
from trading contracts were not material to the Group's results of operations
for 2000, 1999 and 1998.
Accounting for contingencies Certain conditions may exist as of the date
financial statements are issued which may result in a loss to the Group, but
which will only be resolved when one or more future events occur or fail to
occur. Assessing contingencies necessarily involves an exercise of judgment. In
assessing loss contingencies related to legal proceedings that are pending
against the Group or unasserted claims that may result in such proceedings, the
Group evaluates the perceived merits of any legal proceedings or unasserted
claims as well as the perceived merits of the amount of relief sought or
expected to be sought therein.
If the assessment of a contingency indicates that it is probable that a
material liability had been incurred and the amount of the loss can be
estimated, then the estimated liability is accrued in the Group's financial
statements. If the assessment indicates that a potentially material liability is
not probable, but is reasonably possible, or is probable but cannot be
estimated, then the nature of the contingent liability, together with an
estimate of the range of possible loss, if determinable, is disclosed.
Loss contingencies considered remote are generally not disclosed unless
they involve guarantees, in which case the nature and amount of the guarantee
would be disclosed. However, in some instances in which disclosure is not
otherwise required, the Group may disclose contingent liabilities of an unusual
nature which, in the judgment of management and its legal counsel, may be of
interest to Stockholders or others.
Environmental matters The Group's environmental policies encompass the existing
laws in each country in which the Group operates, and the Group's own internal
standards. Expenditures that create future benefits or contribute to future
revenue generation are capitalized. Future remediation costs are accrued based
on estimates of known environmental exposure even if uncertainties exist about
the ultimate cost of the remediation. Such accruals are based on the best
available undiscounted estimates using data primarily developed by third party
experts. Costs of environmental compliance for past and ongoing operations,
including maintenance and monitoring, are expensed as incurred. Recoveries from
third parties are recorded as assets when realizable.
C-11
<PAGE>
.
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
Note 1 - Summary of significant accounting policies - continued
Revenue recognition In general, revenue is recognized for crude oil, natural gas
and refined product sales when title passes as specified in the sales contract.
Reclassifications Certain reclassifications have been made to the prior year
amounts to conform to the 2000 presentation.
Note 2 - Accounting change
An affiliate of the Group capitalized certain start-up costs, primarily
organizational and training, over the period 1992-1996 related to a grassroots
refinery construction project in Thailand. These costs were considered part of
the effort required to prepare the refinery for operations. With the issuance of
the AICPA's Statement of Position 98-5, "Reporting on the Costs of Start-up
Activities", these costs would be accounted for as period expenses. The Group
elected early adoption of this pronouncement effective January 1, 1998 and
accordingly, recorded a cumulative effect charge to income as of January 1, 1998
of $50 million representing the Group's share of the applicable start-up costs.
Excluding the cumulative effect, the change in accounting for start-up costs did
not materially affect net income for 1998.
Note 3 - Restructuring/Reorganization
Caltex recorded a charge to selling, general and administrative expenses
of $37 million and $86 million in 1999 and 1998, respectively, for various
restructuring and reorganization activities undertaken to realign its downstream
operations along functional lines and reduce redundant operating activities. The
charges included severance and other termination benefits of $23 million and $60
million for approximately 200 employees and 500 employees in 1999 and 1998,
respectively. All affected employees had left Caltex by December 2000. The
following table summarizes the restructuring/reorganization costs for 2000, 1999
and 1998 (millions of U.S. dollars):
<TABLE>
<CAPTION>
2000 1999 1998
---------------------------- ---------------------------- ----------------------------
Balance Balance Balance
at Payments/ at Payments/ at Payments/
Dec 31 Write-offs Expense Dec 31 Write-offs Expense Dec 31 Write-offs Expense
------- ---------- --------- ------- ---------- --------- -------- ---------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Severance and
other termination
benefits - (8) (2) 10 (57) 23 44 (16) 60
Other reorganization
costs 9 (5) 2 12 (11) 14 9 (17) 26
------- ---------- --------- ------- ---------- --------- ------- --------- --------
Total $ 9 $ (13) $ - $ 22 $ (68) $ 37 $ 53 $ (33) $ 86
======= ========== ========= ======= ========== ========= ======= ========= ========
</TABLE>
The $9 million liability as of December 31, 2000 primarily relates to
future lease commitments on vacated office space over the remaining lease term
ending in 2002. Adjustments made in 2000 and 1999 to recorded liabilities were
insignificant.
In addition to the above, 1999 net income included a $27 million after tax
charge for restructuring activities of affiliates.
Note 4 - Assets Held for Disposal
The Group continually reviews its asset portfolio and periodically sells
or otherwise disposes of various assets that no longer fit into the Group's
strategic direction. The Group recorded a charge to earnings of approximately $4
million in 2000 and $30 million in both 1999 and 1998 related to various
marketing assets (primarily service station land and buildings) which have been
removed from operation and are awaiting disposal or sale as buyers are located.
Carrying value of these assets, which is based on appraisals or estimated
selling prices, as of December 31, 2000 is approximately $25 million. The effect
of suspending depreciation on assets held for sale in 2000, 1999 and 1998 was
not material.
C-12
<PAGE>
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
Note 5 - Operating leases
The Group has operating leases involving various marketing assets for
which net rental expense was $92 million, $112 million, and $103 million in
2000, 1999, and 1998, respectively.
Future net minimum rental commitments under operating leases having
non-cancelable terms in excess of one year are as follows (in millions of U.S.
dollars): 2001 - $42; 2002 - $16; 2003 - $7; 2004 - $6; 2005 - $6; and 2006 and
thereafter - $23.
Note 6 - Taxes
Taxes charged to income consist of the following:
<TABLE>
<CAPTION>
Year ended December 31,
----------------------------------------
(Millions of U.S. dollars)
2000 1999 1998
-------- -------- -------
<S> <C> <C> <C>
Taxes other than income taxes:
Duties, import and excise taxes $ 1,389 $ 1,077 $ 1,218
Other 16 16 17
-------- -------- -------
Total taxes other than income taxes $ 1,405 $ 1,093 $ 1,235
======== ======== =======
Income taxes:
U.S. taxes :
Current $ 3 $ 72 $ 6
Deferred - - 23
-------- -------- -------
Total U.S. 3 72 29
-------- -------- -------
International taxes:
Current $ 579 $ 376 $ 228
Deferred (13) (58) 69
--------- --------- -------
Total International 566 318 297
-------- -------- -------
Total provision for income taxes $ 569 $ 390 $ 326
======== ======== =======
</TABLE>
Income taxes have been computed on an individual company basis at rates in
effect in the various countries of operation. The effective tax rate differs
from the "expected" tax rate (U.S. Federal corporate tax rate) as follows:
<TABLE>
<CAPTION>
Year ended December 31,
---------------------------------------
2000 1999 1998
-------- ------- ------
<S> <C> <C> <C>
Computed "expected" tax rate 35.0% 35.0% 35.0%
Effect of recording equity in net income
of affiliates on an after tax basis (2.4) (11.3) (7.3)
Effect of dividends received from
subsidiaries and affiliates 0.6 0.4 (0.3)
Income subject to foreign taxes at other
than U.S. statutory tax rate 16.1 18.4 26.0
Effect of sale of investment in an affiliate - 6.6 -
Deferred income tax valuation allowance 4.2 2.4 8.7
Other (1.2) (1.5) 0.7
-------- ------- ------
Effective tax rate 52.3% 50.0% 62.8%
======== ======= ======
</TABLE>
For 2000, the increase in effective tax rate is primarily due to the
larger proportion of earnings from higher tax rate foreign jurisdictions. For
1999, the increase in the effective tax rate resulting from the sale of
investment in an affiliate is net of the effect of previously unrecorded foreign
tax credit carry-forwards of $29 million.
C-13
<PAGE>
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
Note 6 - Taxes - continued
Deferred income taxes are provided in each tax jurisdiction for temporary
differences between the financial reporting and the tax basis of assets and
liabilities. Temporary differences and tax loss carry-forwards which give rise
to deferred tax liabilities (assets) are as follows:
<TABLE>
<CAPTION>
Year ended December 31,
------------------------
(Millions of U.S. dollars)
2000 1999
----- -----
<S> <C> <C>
Depreciation $ 317 $ 322
Miscellaneous 10 17
----- -----
Deferred tax liabilities 327 339
----- -----
Inventory (41) (24)
Investment allowances (61) (62)
Tax loss carry-forwards (122) (100)
Foreign exchange (18) (13)
Retirement benefits (27) (33)
Miscellaneous (30) (11)
------ -----
Deferred tax assets (299) (243)
Valuation allowance 137 91
----- -----
Net deferred taxes $ 165 $ 187
===== =====
</TABLE>
A valuation allowance has been established to reduce deferred income tax
assets to amounts which, in the Group's judgement are more likely than not (more
than 50%) to be utilized against current and future taxable income when those
temporary differences become deductible.
Undistributed earnings of subsidiaries and affiliates, for which no U.S.
deferred income tax provision has been made, approximated $3.3 billion and $3.4
billion as of December 31, 2000 and December 31, 1999, respectively. Such
earnings have been or are intended to be indefinitely reinvested, and become
taxable in the U.S. only upon remittance as dividends. It is not practical to
estimate the amount of tax that may be payable on the eventual remittance of
such earnings. Upon remittance, certain foreign countries impose withholding
taxes which, subject to certain limitations, are available for use as tax
credits against the U.S. tax liability. Excess U.S. foreign income tax credits
are not recorded until realized.
Note 7 - Inventories
<TABLE>
<CAPTION>
As of December 31,
------------------------
(Millions of U.S. dollars)
2000 1999
---- ----
<S> <C> <C>
Inventories
Crude oil $ 169 $ 170
Petroleum products 364 427
Materials and supplies 24 26
----- ------
$ 557 $ 623
===== ======
</TABLE>
The reported value of inventory at December 31, 2000 and 1999 was less
than its current cost by approximately $152 million and $104 million,
respectively. In 2000 and 1998, certain inventories were recorded at market,
which was lower than the LIFO carrying value. Adjustments to market reduced net
income $4 million in 2000 and $18 million in 1998. In 1999, the market valuation
adjustment reserves established in prior years were eliminated as market prices
improved and the physical units of inventory were sold. Elimination of these
reserves increased net income in 1999 by $71 million. At December 31, 2000,
inventories were primarily reported at LIFO carrying cost except for
approximately $39 million of trading inventory recorded at market.
Inventory quantities valued on the LIFO basis were reduced at certain
locations during the periods presented. Such inventory reductions increased net
income in 2000 and 1999 by $41 million each year and decreased net income by $4
million (net of a related market valuation adjustment of $1 million) in 1998.
C-14
<PAGE>
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
Note 8 - Equity in affiliates
Investments in affiliates at equity include the following:
<TABLE>
<CAPTION>
As of December 31,
--------------------------
(Millions of U.S.
dollars)
Equity % 2000 1999
-------- --------- ---------
<S> <C> <C> <C>
Caltex Australia Limited 50% $ 253 $ 260
LG-Caltex Oil Corporation 50% 1,468 1,441
Star Petroleum Refining Company, Ltd. 64% 337 269
All other Various 134 157
--------- ---------
$ 2,192 $ 2,127
========= =========
</TABLE>
The carrying value of the Group's investment in its affiliates in excess
of its proportionate share of affiliate net equity is being amortized over
approximately 20 years.
In 1999, Caltex Corporation sold its 50% interest in Koa Oil Company,
Limited (Koa) with a net book value of approximately $219 million, to Nippon
Mitsubishi Oil Corp, for approximately $237 million in cash. As a result of the
sale, Caltex incurred additional U.S. tax liabilities of approximately $81
million.
The remaining interest in Star Petroleum Refining Company, Ltd. (SPRC) is
owned by a governmental entity of the Kingdom of Thailand. Provisions in the
SPRC shareholders agreement limit the Group's control and provide for active
participation of the minority shareholder in routine business operating
decisions. The agreement also mandates reduction in Group ownership to a
minority position before the year 2001; however, this requirement has been
delayed in view of the current economic difficulties in the region.
Shown below is summarized combined financial information for affiliates at
equity (in millions of U.S. dollars):
<TABLE>
<CAPTION>
100% Equity Share
---------------------- --------------------
2000 1999 2000 1999
--------- --------- ------- -------
<S> <C> <C> <C> <C>
Current assets $ 3,182 $ 3,005 $ 1,614 $ 1,535
Other assets 6,573 6,333 3,424 3,287
Current liabilities 3,227 3,351 1,669 1,816
Other liabilities 2,334 1,883 1,235 937
------- -------- ------- -------
Net worth $ 4,194 $ 4,104 $ 2,134 $ 2,069
======= ======== ======= =======
</TABLE>
<TABLE>
<CAPTION>
100% Equity Share
----------------------------- -----------------------------
2000 1999 1998 2000 1999 1998
-------- -------- -------- -------- ------ --------
<S> <C> <C> <C> <C> <C> <C>
Operating revenues $ 15,713 $ 12,796 $ 11,811 $ 8,041 $ 6,511 $ 5,968
Operating income 421 726 1,101 222 358 539
Net income 150 539 193 71 252 58
</TABLE>
Cash dividends received from these affiliates were $83 million, $71
million, and $50 million in 2000, 1999, and 1998, respectively.
The summarized combined financial information shown above includes the
cumulative effect of the accounting change in 1998 as described in Note 2.
Retained earnings as of December 31, 2000 and 1999 includes $1.4 billion
which represents the Group's share of undistributed earnings of affiliates at
equity.
C-15
<PAGE>
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
Note 9 - Short-term debt
Short-term debt consists primarily of demand and promissory notes,
acceptance credits, overdrafts and the current portion of long-term debt. The
weighted average interest rates on short-term financing as of December 31, 2000
and 1999 were 6.9% and 6.5%, respectively. Unutilized lines of credit available
for short-term financing totaled $1.0 billion as of December 31, 2000.
Note 10 - Long-term debt
Long-term debt, with related interest rates for 2000 and 1999 consists of
the following:
<TABLE>
<CAPTION>
As of December 31,
----------------------
(Millions of U.S.
dollars)
2000 1999
------ ------
<S> <C> <C>
U.S. dollar debt:
Variable interest rate loans with average rates
of 6.9% and 6.4%, due 2002-2009 $ 482 $ 481
Fixed interest rate term loans with average rates of 6.4%
and 6.2%, due 2002-2005 174 171
Australian dollar debt:
Fixed interest rate loan with 12.4% rate due 2001 - 205
Hong Kong dollar debt:
Variable interest rate loans with average rates
of 6.32% and 6.07%, due 2002 75 75
New Zealand dollar debt:
Variable interest rate loans with average rates
of 7.0% and 5.6%, due 2002-2005 70 70
Malaysian ringgit debt:
Variable interest rate loans with average rate of 3.8%
due 2005 7 -
Fixed interest rate loans with average rates of 6.95%
and 7.81%, due 2005 13 24
South African rand debt:
Fixed interest rate loan with 17.8% rate due 2007 6 8
Other - variable interest rate loans with average rates
of 12.1% and 15.3%, due 2003-2007 26 20
------ ------
$ 853 $1,054
====== ======
<FN>
Aggregate maturities of long-term debt by year are as follows (in millions
of U.S. dollars): 2001 - $469 (included in short-term debt); 2002 - $590; 2003 -
$118; 2004 - $56; 2005 - $70; and thereafter - $19.
</FN>
</TABLE>
C-16
<PAGE>
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
Note 11 - Financial Instruments
Certain Group companies are parties to financial instruments with
off-balance sheet credit and market risk, principally interest rate risk. The
Group's outstanding commitments for interest rate swaps and foreign currency
contractual amounts are:
<TABLE>
<CAPTION>
As of December 31,
--------------------------
(Millions of U.S.
dollars)
2000 1999
---- ----
<S> <C> <C>
Interest rate swaps - Pay Fixed, Receive Floating $ 507 $ 632
Interest rate swaps - Pay Floating, Receive Fixed 188 245
Commitments to purchase foreign currencies 275 360
Commitments to sell foreign currencies 84 81
</TABLE>
The Group enters into interest rate swaps in managing its interest risk,
and their effects are recognized in the statement of income at the same time as
the interest expense on the debt to which they relate. The swap contracts have
remaining maturities of up to six years. Net unrealized (losses) and gains on
contracts outstanding at December 31, 2000 and 1999 were ($1 million) and $4
million, respectively.
The Group enters into forward exchange contracts to hedge against some of
its foreign currency exposure stemming from existing liabilities and firm
commitments. Contracts to purchase foreign currencies (principally Australian
and Singapore dollars) to hedge existing liabilities have maturities of up to
two years. Net unrealized losses applicable to outstanding forward exchange
contracts at December 31, 2000 and 1999 were $37 million and $5 million,
respectively.
The Group hedges a portion of the market risks associated with its crude
oil and petroleum product purchases and sales. Established petroleum futures
exchanges are used, as well as "over-the-counter" hedge instruments, including
futures, options, swaps, and other derivative products. Gains and losses on
hedges are deferred and recognized concurrently with the underlying commodity
transactions. Deferred (losses) and gains on hedging contracts outstanding at
year-end were ($4 million) in 2000 and $4 million in 1999.
The Group's recorded value of fixed interest rate debt exceeded the fair
value by $27 million and $22 million as of December 31, 2000 and 1999,
respectively. The fair value estimates were based on the present value of
expected cash flows discounted at current market rates for similar obligations.
The reported amounts of financial instruments such as cash and cash equivalents,
marketable securities, notes and accounts receivable, and all other current
liabilities approximate fair value because of their short maturities.
The Group had investments in debt securities available-for-sale at
amortized costs of $11 million and $120 million at December 31, 2000 and 1999,
respectively. The fair value of these securities at December 31, 2000 and 1999
approximated amortized costs. As of December 31, 2000 and 1999, investments in
debt securities available-for-sale had maturities of less than ten years. The
Group's carrying amount for investments in affiliates accounted for at equity
included $1 million and $2 million, as of December 31, 2000 and 1999,
respectively, for after-tax unrealized net gains on investments held by these
companies.
The Group is exposed to credit risks in the event of non-performance by
counter-parties to financial instruments. For financial instruments with
institutions, the Group does not expect any counter-party to fail to meet its
obligations given their high credit ratings. Other financial instruments exposed
to credit risk consist primarily of trade receivables. These receivables are
dispersed among the countries in which the Group operates, thus limiting
concentration of such risk. The Group performs ongoing credit evaluations of its
customers and generally does not require collateral. Letters of credit are the
principal security obtained to support lines of credit when the financial
strength of a customer is not considered sufficient. Credit losses have
historically been within management's expectations.
C-17
<PAGE>
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
Note 12 - Employee benefit plans
The Group has various retirement plans, including defined benefit pension
plans, covering substantially all of its employees. The benefit levels, vesting
terms and funding practices vary among plans. The following provides a
reconciliation of benefit obligations, plan assets, and funded status of the
various plans, primarily foreign.
<TABLE>
<CAPTION>
As of December 31,
---------------------------------------------
(Millions of U.S. dollars)
Other Post-retirement
Pension Benefits Benefits
------------------ ---------------------
2000 1999 2000 1999
------ ------ -------- --------
<S> <C> <C> <C> <C>
Change in benefit obligations:
Benefit obligation at January 1, $ 186 $ 231 $ 78 $ 79
Service cost 13 10 1 1
Interest cost 21 18 8 8
Actuarial loss (gain) 57 7 3 (5)
Benefits paid (22) (25) (6) (4)
Settlements and curtailments (7) (57) - -
Foreign exchange rate changes (24) 2 (7) (1)
------ ------ -------- --------
Benefit obligation at December 31, $ 224 $ 186 $ 77 $ 78
====== ====== ======== ========
Change in plan assets:
Fair value at January 1, $ 210 $ 220 $ - $ -
Actual return on plan assets 10 32 - -
Group contribution 26 32 6 4
Benefits paid (22) (25) (6) (4)
Settlements (7) (57) - -
Foreign exchange rate changes (36) 8 - -
------ ------ -------- --------
Fair value at December 31, $ 181 $ 210 $ - $ -
====== ====== ======== ========
Accrued benefit costs:
Funded status $ (43) $ 24 $ (77) $ (78)
Unrecognized net actuarial loss (gain) 16 (26) 17 17
Unrecognized prior service cost 26 6 - -
------ ------ -------- --------
(Accrued) prepaid benefit cost recognized $ (1) $ 4 $ (60) $ (61)
====== ====== ======== ========
Amounts recognized in the Combined Balance Sheet:
Prepaid benefit cost $ 27 $ 32 $ - $ -
Accrued benefit liability (28) (28) (60) (61)
------ ------ -------- --------
(Accrued) prepaid benefit cost recognized $ (1) $ 4 $ (60) $ (61)
====== ====== ======== ========
Weighted average rate assumptions:
Discount rate 9.7% 9.3% 9.9% 10.9%
Rate of increase in compensation 7.4% 7.0% 6.8% 4.0%
Expected return on plan assets 10.3% 11.5% n/a n/a
</TABLE>
<TABLE>
<CAPTION>
As of December 31,
---------------------
(Millions of U.S.
dollars)
2000 1999
-------- -------
<S> <C> <C>
Pension plans with accumulated benefit obligations in excess of assets:
Projected benefit obligation $ 24 $ 25
Accumulated benefit obligation 13 13
Fair value of assets - -
</TABLE>
C-18
<PAGE>
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
Note 12 - Employee benefit plans - continued
<TABLE>
<CAPTION>
Year ended December 31,
-------------------------------
(Millions of U.S. dollars)
2000 1999 1998
------ ------ ------
<S> <C> <C> <C>
Components of Pension Expense
Service cost $ 13 $ 10 $ 10
Interest cost 21 18 20
Expected return on plan assets (20) (22) (21)
Amortization of prior service cost 3 3 1
Recognized net actuarial loss (gain) 1 (2) 3
Curtailment/settlement loss 1 17 13
------ ------ ------
Total $ 19 $ 24 $ 26
====== ====== ======
Components of Other Post-retirement Benefits
Service cost $ 1 $ 1 $ 2
Interest cost 8 8 6
Special termination benefit recognition - - 3
Curtailment recognition - - 3
------ ------ ------
Total $ 9 $ 9 $ 14
====== ====== ======
</TABLE>
Other post-retirement benefits are comprised of contributory healthcare
and life insurance plans. A one percentage point change in the assumed health
care cost trend rate of 10% would change the post-retirement benefit obligation
by $9 million and would not have a material effect on aggregate service and
interest components.
Note 13 - Commitments and contingencies
Caltex is involved in tax audits in the United States and in certain other
jurisdictions. The Internal Revenue Service's audit for the years 1987-1993 has
been administratively settled and Caltex will receive a refund of tax and
interest for these years. In jurisdictions outside the United States, the tax
authorities' audits are in various stages of completion. In the opinion of
management, adequate provision has been made for income taxes for all years
under examination or subject to future examination.
Caltex and certain of its subsidiaries are named as defendants, along with
privately held Philippine ferry and shipping companies and the shipping
company's insurer, in various lawsuits filed in the U.S. and the Philippines on
behalf of at least 3,350 parties, who were either survivors of, or relatives of
persons who allegedly died in a collision in Philippine waters on December 20,
1987. One vessel involved in the collision was carrying products for Caltex
(Philippines) Inc. (a subsidiary of Caltex) in connection with a contract of
affreightment. Although Caltex had no direct or indirect ownership in or
operational responsibility for either vessel, various theories of liability have
been alleged against Caltex. The major suit filed in the U.S. (Louisiana State
Court) was dismissed in December 2000 on forum non conveniens grounds and is
currently under appeal by the plaintiffs. Caltex will vigorously contest this
appeal. Caltex is actively pursuing dismissal of all Philippine litigation on
the strength of a Philippine Supreme Court decision absolving it of any
responsibility for the collision. No reasonable estimate of damages involved or
being sought can be made at this time.
The Group may be subject to loss contingencies pursuant to
environmental laws and regulations in each of the countries in which it operates
that, in the future, may require the Group to take action to correct or
remediate the effects on the environment of prior disposal or release of
petroleum substances by the Group. The amount of such future cost is
indeterminable due to such factors as the nature of the new regulations, the
unknown magnitude of any possible contamination, the unknown timing and extent
of the corrective actions that may be required, and the extent to which such
costs are recoverable from third parties.
In the Group's opinion, while it is impossible to ascertain the ultimate
legal and financial liability, if any, with respect to the above mentioned and
other contingent liabilities, the aggregate amount that may arise from such
liabilities is not anticipated to be material in relation to the Group's
combined financial position or liquidity, or results of operations over a
reasonable period of time.
C-19
<PAGE>
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
Note 13 - Commitments and contingencies - continued
A Caltex subsidiary has a contractual commitment until 2007 to purchase
petroleum products in conjunction with the financing of a refinery owned by an
affiliate. Total future estimated commitments under this contract, based on
current pricing and projected growth rates, are approximately $0.8 billion per
year. Purchases (in billions of U.S. dollars) under this and other similar
contracts were $1.0, $0.7 and $0.8 in 2000, 1999, and 1998 respectively.
Caltex is contingently liable for sponsor support funding for a maximum of
$193 million in connection with an affiliate's project finance obligations. The
project has been operational since 1996 and has successfully completed all
mechanical, technical and reliability tests associated with the plant physical
completion covenant. However, the affiliate has been unable to satisfy a
covenant relating to a working capital requirement. As a result, a technical
event of default exists which has not been waived by the lenders. The lenders
have not enforced their rights and remedies under the finance agreements and
they have not indicated an intention to do so. The affiliate is current on these
financial obligations and anticipates resolving the issue with its secured
creditors during further restructuring discussions. During 2000, Caltex and the
other sponsor provided temporary short-term extended trade credit related to
crude oil supply with an outstanding balance owing to Caltex at December 31,
2000 of $124 million.
Note 14 - Oil and gas exploration, development and producing activities
The financial statements of Chevron Corporation and Texaco Inc. contain
required supplementary information on oil and gas producing activities,
including disclosures on affiliates at equity. Accordingly, such disclosures are
not presented herein.
C-20
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10
<SEQUENCE>2
<FILENAME>0002.txt
<DESCRIPTION>EX 10.1 DEFERRED COMPENSATION PLAN FOR DIRECTORS
<TEXT>
CHEVRON CORPORATION
DEFERRED COMPENSATION PLAN
FOR DIRECTORS
(As Amended and Restated Effective January 1, 2001)
1. ESTABLISHMENT AND PURPOSE.
-------------------------
The Chevron Corporation Deferred Compensation Plan for Directors was
adopted on May 26, 1982, to provide Directors an opportunity to defer payment of
their Director's Fees. The Plan is also intended to establish a method of paying
Director's Fees which will assist the Corporation in attracting and retaining
persons of outstanding achievement and ability as members of the Board. The Plan
was amended and restated to read as set forth herein effective January 1, 2001.
2. DEFINITIONS.
-----------
For purposes of the Plan, the following terms shall have the meanings
set forth below:
(a) "Account" means the bookkeeping account maintained on behalf of a
Participant to which shall be credited any amount deferred pursuant to a
deferral election under Section 5.
(b) "Beneficiary" means the person designated as such by the Participant
-----------
pursuant to Section 10(a).
(c) "Board" means the Board of Directors of the Corporation.
-----
(d) "Change in Control" means a `change in control' as that term is defined in
Article VI of the bylaws of the Corporation, as such bylaws may be amended from
time to time.
(e) "Code" means the Internal Revenue Code of 1986, as amended.
----
(f) "Corporation" means Chevron Corporation, a Delaware corporation, or any
-----------
successor corporation.
(g) "Director" means a member of the Board who is not an employee of the
--------
Corporation or any subsidiary thereof.
(h) "Director's Fees" means the amount of compensation paid by the Corporation
to a Director for his or her services as a Director, including an annual
retainer and any amount payable for attendance at a meeting of the Board or any
committee thereof. "Director's Fees" shall not include any reimbursement by the
Corporation of expenses incurred by a Director incidental to attendance at a
meeting of the Board or a committee thereof or of any other expense incurred on
behalf of the Corporation.
-1-
<PAGE>
(i) "Participant" means a Director who elects to participate in the Plan.
-----------
(j) "Plan" means the Chevron Corporation Deferred Compensation Plan for
Directors, as set forth herein and as amended from time to time.
(k) "Plan Year" means the calendar year.
---------
3. ADMINISTRATION.
--------------
The Plan shall be administered by the Board.
The Board shall have the authority to administer the Plan in its sole
discretion. To this end, the Board is authorized to construe and interpret the
Plan, to promulgate, amend and rescind Rules relating to the implementation of
the Plan and to make all other determinations necessary or advisable for the
administration of the Plan. Any determination, decision or action of the Board
in connection with the construction, interpretation, administration, or
application of the Plan shall be final, conclusive and binding upon all persons
participating in the Plan and any person validly claiming under or through
persons participating in the Plan.
No member of the Board will be liable for any action or determination
made in good faith by the Board with respect to the Plan.
Within 30 days after the occurrence of a Change in Control, the Board
shall appoint an independent organization which shall thereafter administer the
Plan and have all of the powers and duties formerly held and exercised by the
Board pursuant to this Section 3 with respect to the Plan. Upon such
appointment, the Board shall cease to have any responsibility with respect to
the administration of the Plan.
4. PARTICIPATION.
-------------
Each Director may elect to become a Participant in the Plan by electing
to defer Director's Fees under the Plan in accordance with Section 5.
5. DEFERRAL ELECTION.
-----------------
A Director may elect to participate in the Plan at any time by filing a
written election of deferral of Director's Fees with the Secretary of the
Corporation. Such election shall apply solely to Director's Fees to be earned
after the date of filing the election and shall specify the portion of
Director's Fees which are the subject of the deferral election. Such election
shall apply to the specified portion of Director's Fees for the balance of the
Year following the date of filing the election form with the Secretary of the
Corporation and for succeeding Years, until revoked or modified by the Director
as provided below. A director elected to fill a vacancy on the Board may elect
to participate in the Plan for the balance of the Year in which he or she was
elected and for succeeding Years by filing a deferral election with the
Secretary of the Corporation prior to the actual receipt of any Director's Fees
which he or she wishes to defer.
A Director who has previously elected to participate in the Plan may at
any later date elect to:
-2-
<PAGE>
(a) Terminate his or her participation in the Plan with respect to
Director's Fees to be earned after the date of election to
terminate participation; or
(b) Modify the prior election to participate in the Plan by
specifying a larger or smaller portion of his or her Director's Fees
which is to be deferred. Such election shall apply to Director's
Fees to be earned after the date of election to modify the prior
participation election.
An election to terminate or modify participation in the Plan shall be
effective upon the filing of a written election with the Secretary of the
Corporation.
An initial deferral election shall be null, void and without effect if
at the time of making the deferral election the Participant fails to also submit
to the Corporation an investment election form indicating the Participant's
election to have the value of the Participant's Account determined by crediting
it with such earnings, gains and losses as would have accrued had the Account
actually been invested and reinvested in one or more of the following funds
maintained in the Savings component of the Chevron Corporation Profit
Sharing/Savings Plan. This investment election shall be made in whole
percentages totaling 100% of the deferred amount. These funds are as follows:
Chevron Stock Fund
Short-Term Income Fund
Long-Term Income Fund
Balanced Fund
Diversified Equity Fund
Value Stock Fund
Growth Stock Fund
Small Cap Stock Fund
International Stock Fund
For purposes of this Section 5 the value of stock units credited to a
Participant's Stock Units Account under the terms of the Plan as in effect prior
to January 1, 2001 shall be determined with reference to the Chevron Stock Fund
effective January 1, 2001, subject to the rules set forth below regarding
transfers between investment funds.
If an investment fund is eliminated from the Savings component of the
Profit Sharing/Savings Plan, the value of the portion of the Participant's
Account that the Participant previously had elected be determined with reference
to such investment fund shall thereafter be determined with reference to another
investment fund in the Savings component of the Profit Sharing/Savings Plan, as
determined and designated by the Board in its sole discretion.
Once each calendar year during the quarterly 20-business day window
period which begins on the third business day after the Corporation's quarterly
earnings are released, a Participant may elect to transfer amounts credited to
his or her Account among any of the available investment funds by following the
procedures prescribed by the Corporation for this purpose. Transfers between
funds shall be effective on the last day of the window period in which the
election is received, provided that the election is received on or before the
business day immediately preceding the last day of that window period. Any
election received after the
-3-
<PAGE>
business day immediately preceding the last day of a window period shall be
effective on the last day of the following window period.
The foregoing notwithstanding, in the event of a Change in Control in
which the Corporation and any successor corporation ceases to be a publicly held
corporation, the Chevron Stock Fund shall be converted to a dollar value
determined with reference to the consideration received by holders of a share of
common stock of the Corporation in the transaction constituting the Change in
Control and thereafter such amounts shall be credited to the Balanced Fund.
6. TIME OF DISTRIBUTION.
--------------------
Payment of a Director's Account shall be made in cash in annual
installments over such period of years (not exceeding ten (10) years) or in a
lump sum and commencing at such time as the Director shall specify in writing in
his or her initial deferral election form, but not earlier than the date the
Director's service as a Director terminates and not later than the date the
Director attains age 72 or five (5) years after the date the Director's service
as a Director terminates, whichever is later. Any such election shall be
effective upon filing with the Secretary of the Corporation. If a Director fails
to make such an election his or her deferral election shall be null and void.
Any other provision of this Section 6 to the contrary notwithstanding,
in the event of a Change in Control, to the extent such elections may be made
without causing constructive receipt of income for tax purposes, Participants
who previously had made deferral elections shall be given an opportunity to
receive a current distribution of their deferred amounts.
7. DEATH OF PARTICIPANT.
--------------------
In the event of the death of the Participant, the Participant's Account
shall be paid to the Participant's Beneficiary at the time or times specified in
the Director's deferral election unless the Board shall determine in its sole
discretion that payment shall be made at an earlier date.
8. FORM AND VALUE OF DISTRIBUTION.
------------------------------
(a) Establishment of Account.
------------------------
An amount deferred pursuant to a deferral election shall be credited to
a separate bookkeeping Account for the Participant. The value of a Participant's
Account shall be determined with reference to the Participant's investment and
investment transfer elections made pursuant to Section 5.
(b) Distribution of Account.
-----------------------
The Participant's Account shall be distributed in cash at the time
determined in Section 6. For this purpose, amounts attributable to the portion
of the Participant's Account which the Participant elected to have valued with
reference to the Chevron Stock Fund shall be valued as of the date of
distribution. If a distribution is to be made in a lump sum, the Account shall
be paid in its entirety. If a distribution is to be made in installments, the
amount of each annual installment shall be determined by dividing the balance of
the Account by the number of annual
-4-
<PAGE>
payments remaining to be made. The value of the Account shall continue to be
determined with reference to the investment funds elected by the Participant
until the entire Account is distributed.
9. AMENDMENT OR TERMINATION OF THE PLAN.
------------------------------------
Except as otherwise provided in this Section 9, the Board may amend,
suspend or terminate the Plan at any time. In the event of such termination, the
Accounts of Participants shall be paid at such times and in such forms as shall
be determined pursuant to Section 6, unless the Board prescribes a different
time or times for payment of such Accounts. No amendment, suspension or
termination (other than an amendment to discontinue future deferrals) approved
by the Board after six months prior to the public announcement of a proposed
transaction which, when effected, is a Change in Control or before the date
which is two years after the date of a Change in Control (the `Benefit
Protection Period') shall be valid or effective if such amendment, suspension or
termination would alter the terms of these resolutions or adversely affect the
amount of a Participant's Account under the Plan, whether or not the
Participant's status as a Director had terminated at the time the amendment,
suspension or termination was approved; provided, however, any amendment,
suspension or termination may be effected, even if so approved after such a
public announcement, if (a) the amendment, suspension or termination is approved
after any plans have been abandoned to effect the transaction which, if
effected, would have constituted a Change in Control and the event which would
have constituted the Change in Control has not occurred, and (b) within a period
of six months after such approval, no other event constituting a Change in
Control shall have occurred, and no public announcement of a proposed event
which would constitute a Change in Control shall