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1999
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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, 1999
OR
|_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
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Commission File Number 1-368-2
Chevron Corporation
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(Exact name of registrant as specified in its charter)
575 Market Street,
Delaware 94-0890210 San Francisco, California 94105
- --------------- --------------- ------------------------- --------
(State or other (I.R.S. Employer (Address of principal (Zip Code)
jurisdiction of Identification executive offices)
incorporation Number)
or organization)
Registrant's telephone number, including area code (415) 894-7700
NONE
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(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 $1.50 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
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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 29, 2000 - $48,732,596,074
Number of Shares of Common Stock outstanding
as of February 29, 2000 - 654,870,769
DOCUMENTS INCORPORATED BY REFERENCE
(To The Extent Indicated Herein)
Notice of Annual Meeting and Proxy Statement Dated March 22, 2000 (in Part III)
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TABLE OF CONTENTS
Item Page No.
PART I
1. Business............................................... 1
(a) General Development of Business................ 1
(b) Description of Business and Properties......... 2
Capital and Exploratory Expenditures........... 3
Petroleum - Exploration and Production......... 4
Liquids and Natural Gas Production......... 4
Acreage.................................... 5
Reserves and Contract Obligations.......... 7
Development Activities..................... 7
Exploration Activities..................... 8
Review of Ongoing Exploration and
Production Activities In Key Areas........ 9
Petroleum - Natural Gas Liquids................ 13
Petroleum - Refining........................... 13
Petroleum - Refined Products Marketing......... 14
Petroleum - Transportation..................... 16
Chemicals...................................... 17
Coal........................................... 18
Electronic Commerce and Technology............. 18
Research and Environmental Protection.......... 18
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
PART I
Item 1. Business
(a) General Development of Business
Summary Description of Chevron
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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 and coal mining. 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
lube 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, 1999, Chevron had 36,490
employees, 74 percent of whom were employed in U.S. operations.
- --------------------------------------------------------------------------------
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 "expects," "intends," "plans," "projects," "believes," "estimates" and
similar expressions are used to identify such forward-looking statements. These
statements are not guarantees of future performance and involve certain risks,
uncertainties and assumptions that are difficult to predict. Therefore, actual
outcomes and results may differ materially from what is expressed or forecast in
such forward-looking statements.
Among the factors that could cause actual results to differ materially are crude
oil and natural gas prices; refining and marketing margins; chemicals prices and
competitive conditions affecting supply and demand for the company's aromatics,
olefins and additives products; 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; 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 (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. Chevron undertakes
no obligation to update publicly any forward-looking statements, whether as a
result of new information, future events or otherwise.
- --------------------------------------------------------------------------------
(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-
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 and efficient 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.
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 new process technologies, 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 focus on
developing the skills of its employees, sharing best practices across the
organization, and applying systems and processes effectively to the four
priorities described above.
(b) Description of Business and Properties
The company's largest business segments are its exploration and production
operations and its refining, marketing and transportation operations. Chemicals
is also a significant operation. 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, Republic of
Congo, Australia, the United Kingdom, Norway, China, Papua New Guinea, Thailand,
Argentina 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
-2-
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 and the United Kingdom. Its business activities include energy marketing,
independent power generation and gathering, processing, selling and
transportation of natural gas and natural gas liquids. In February 2000, Dynegy
merged with Illinova Corporation, an energy services holding company based in
Illinois. Chevron invested an additional $200 million to maintain a comparable
ownership interest in the merged company. The company expects that this merger
will accelerate Dynegy's growth in the power generation and marketing business.
The company's chemicals operations are concentrated in the United States, but
also include manufacturing facilities in France, Japan, Brazil, Singapore, Saudi
Arabia and Mexico. Chemicals manufacturing facilities are under construction in
China. In February 2000, Chevron and Phillips Petroleum Company signed a letter
of intent and exclusivity agreement to combine most of their chemicals
businesses into a joint venture. Each company will own 50 percent of the joint
venture, which is subject to final approval of the companies' board of directors
and regulatory review. Final approvals are expected to be completed by mid-2000.
Tabulations of segment sales and other operating revenues, earnings, income
taxes and assets, by United States and International geographic areas, for the
years 1997 to 1999, may be found in Note 9 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
12 and 13 on pages FS-23 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 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-5 of this Annual Report on Form 10-K in Management's
Discussion and Analysis of Financial Condition and Results of Operations.
Capital and Exploratory Expenditures
------------------------------------
Worldwide capital and exploratory (C&E) expenditures totaled $6.133 billion in
1999, compared with $5.314 billion in 1998. Expenditures for consolidated
worldwide exploration and production increased by 45 percent between years. This
increase was driven by two significant international exploration and production
acquisitions in 1999: the Rutherford-Moran Oil Corporation in Thailand and
Petrolera Argentina San Jorge S.A. in Argentina. U.S. refining, marketing and
transportation expenditures decreased in 1999 after having increased in 1998
with the acquisition of Amoco's North American lubricants operations.
International refining, marketing and transportation expenditures doubled to
$183 million as the Caspian Pipeline Consortium began construction of pipeline
facilities linking the Tengiz Field in Kazakhstan with the Russian Black Sea.
Chemicals expenditures were 22 percent lower in 1999 as the company completed
major expansion and construction projects begun in earlier years and constrained
new capital spending in this segment.
The company's share of upstream and downstream expenditures by its Caltex
affiliate accounted for about 53 percent of affiliates' expenditures in 1999,
although at lower absolute levels than in 1998. Caltex expenditures
-3-
continued to be curtailed as a result of economic conditions in the Asia-Pacific
region. Expenditures by the company's chemicals affiliates were $169 million
lower in 1999 as the construction of a new manufacturing facility in Saudi
Arabia was completed during the year.
Chevron's C&E expenditures during 1999 and 1998 are summarized in the following
table:
Capital and Exploratory Expenditures
(Millions of Dollars)
1999 1998 Change %
-------- ------- -------- ----
Exploration and Production - United States $ 900 $1,213 $ (313) (26)
International 3,242 1,647 1,595 97
-------- ------- --------
Sub-total 4,142 2,860 1,282 45
Refining, Marketing
and Transportation - United States 516 654 (138) (21)
International 183 92 91 99
------- ------- --------
Sub-total 699 746 (47) (6)
Chemicals - United States 326 385 (59) (15)
International 67 121 (54) (45)
------- ------- --------
Sub-total 393 506 (113) (22)
All Other 117 208 (91) (44)
------- ------- --------
Total Consolidated Companies 5,351 4,320 1,031 24
Chevron's Share in Affiliates 782 994 (212) (21)
------- ------- --------
Total Including Affiliates $6,133 $5,314 $ 819 15
======= ======= ========
The company's 2000 C&E expenditures, including its share of equity affiliates'
expenditures, are projected at $5.2 billion, 15 percent lower than 1999 spending
levels. Consolidated companies' expenditures are planned to decrease by 22
percent to $4.2 billion, while the company's share of equity affiliates'
expenditures is expected to increase by 33 percent to just over $1 billion. The
foregoing expenditure levels may change depending on the timing of a successful
formation of the proposed chemicals joint venture with Phillips Petroleum
Company. The company plans to devote the majority of its C&E expenditures to
worldwide upstream projects, while limiting capital spending in the
international chemicals and downstream businesses.
Petroleum - Exploration and Production
--------------------------------------
Liquids and Natural Gas Production
- ----------------------------------
In 1999, 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, increased
in 1999 by nearly 2 percent - the seventh consecutive year of production
increases. Net liquids production in the United States fell about 3 percent.
International net liquids production, including affiliates, increased by about 4
percent in 1999 - the tenth consecutive year of production increases. This
increase was due primarily to new production in Argentina and Thailand following
acquisitions the company made in 1999; higher production from new fields in
Angola; and higher production in Kazakhstan, where the company's share of
production at the Tengiz Field increased as processing plant expansions
progressed. These increases were partially offset by production declines in
Australia, Indonesia (Caltex operations) and Nigeria.
Net production of natural gas, including affiliates, increased by 5 percent in
1999. United States production fell about six percent, as higher field declines
and property sales more than offset new production from the Gulf of Mexico shelf
and deepwater Gulf of Mexico. International volumes increased 34 percent in
1999. 1999 production volumes reflected a full year of production from the
Britannia Field in the U.K. North Sea, which began producing in August 1998; new
production in Thailand and Argentina; and higher production in Kazakhstan,
Canada, Nigeria and Australia. These increases were slightly offset by a decline
in production in Indonesia (Caltex operations). The company expects current
plans to expand the Escravos Gas Project in Nigeria, and the continued expansion
and
-4-
development of its projects in Australia, to contribute to natural gas
production increases from its international portfolio.
The following table summarizes the company's and its affiliates' net production
of crude oil, natural gas liquids and natural gas for 1999 and 1998.
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)
------------------------------ -----------------------
1999 1998 1999 1998
---- ---- ---- ----
United States
-California 111.8 116.2 114.8 122.0
-Gulf of Mexico 104.7 93.5 790.0 820.1
-Texas 45.7 57.9 323.0 331.1
-Wyoming 10.0 9.1 170.3 181.2
-Other States 43.6 48.4 240.3 284.5
------------------------------------------------------------
Total United States 315.8 325.1 1,638.4 1,738.9
------------------------------------------------------------
Angola 145.6 133.1 - -
Congo 28.9 27.8 - -
Democratic Republic of Congo 8.8 10.1 - -
Nigeria 144.0 148.3 39.2 33.5
United Kingdom (North Sea) 42.2 39.2 218.8 73.9
Norway 15.8 13.0 0.4 0.4
Canada 65.0 63.0 193.6 180.3
Australia 30.4 38.4 227.1 223.4
Indonesia 17.0 17.5 - -
Papua New Guinea 15.2 14.5 - -
China 13.9 11.4 - -
Thailand 3.7 - 39.4 -
Argentina 13.4 - 8.8 -
Colombia 11.4 12.2 - -
Venezuela 2.5 1.4 - -
Netherlands - - 1.9 2.2
------------------------------------------------------------
Total International 557.8 529.9 729.2 513.7
------------------------------------------------------------
Total Consolidated Companies 873.6 855.0 2,367.6 2,252.6
Chevron's Share of Affiliates 253.4 252.3 145.0 140.0
------------------------------------------------------------
Total Including Affiliates 1,127.0 1,107.3 2,512.6 2,392.6
============================================================
* Net production excludes royalty interests owned by others.
Acreage
- -------
At December 31, 1999, 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.
-5-
Acreage* At December 31, 1999
(Thousands of Acres)
Developed
Undeveloped Developed and Undeveloped
------------------- ------------------- -------------------
Gross Net Gross Net Gross Net
-------- -------- -------- --------- -------- --------
United States 5,359 3,798 2,770 1,701 8,129 5,499
-------- -------- -------- --------- --------- --------
Canada 21,207 11,496 1,386 532 22,593 12,028
Africa 12,075 6,470 193 72 12,268 6,542
Asia 15,588 7,407 84 35 15,672 7,442
Other International 34,424 15,730 359 148 34,783 15,878
--------- --------- --------- --------- --------- --------
Total International 83,294 41,103 2,022 787 85,316 41,890
-------- -------- --------- --------- --------- --------
Total Consolidated Companies 88,653 44,901 4,792 2,488 93,445 47,389
Chevron's Share in Affiliates 3,013 1,448 340 168 3,353 1,616
--------- --------- --------- --------- --------- --------
Total Including Affiliates 91,666 46,349 5,132 2,656 96,798 49,005
========= ========= ========= ========= ========= ========
* 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.
Refer to Table III on pages FS-33 to FS-35 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 1999, 1998 and
1997. The following table summarizes gross and net productive wells at year-end
1999 for the company and its affiliates.
Productive Oil And Gas Wells At December 31, 1999
Productive(1) Productive(1)
Oil Wells Gas Wells
------------------- --------------------
Gross(2) Net(2) Gross(2) Net(2)
-------- -------- --------- ---------
United States 23,190 12,378 4,495 2,173
-------- -------- --------- ---------
Canada 1,320 905 211 153
Africa 1,223 467 12 4
Other International 1,774 737 152 61
-------- -------- --------- ---------
Total International 4,317 2,109 375 218
-------- -------- --------- ---------
Total Consolidated Companies 27,507 14,487 4,870 2,391
Chevron's Share of Affiliates 5,559 2,882 341 188
-------- -------- --------- ---------
Total Including Affiliates 33,066 17,369 5,211 2,579
======== ======== ========= =========
Multiple completion wells
included above: 649 358 353 197
(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.
-6-
Reserves and Contract Obligations
- ---------------------------------
Table IV on pages FS-35 and FS-36 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, 1999, 1998 and 1997. During 2000, 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-36 of this Annual Report on Form 10-K.
In 1999, Chevron's worldwide oil and equivalent-gas (OEG) barrels of net proved
reserves additions exceeded production for the seventh consecutive year with a
replacement rate of 108 percent of net production, including sales and
acquisitions. Excluding sales and acquisitions, the replacement rate was 67
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 1999.
Reserves Replacement - 1999
Additions to Net OEG Reserves Memo:
Reserves Production Replacement % Including
------------------- --------------- ------------- Sales and
Liquids Gas Liquids Gas Acquisitions
(mmbbls) (bcf) (mmbbls) (bcf)
--------- ------ ------ ------ ------------
United States 70.9 (71.6) 115.3 598.2 27% 10%
Africa 110.8 49.4 119.5 15.0 97% 97%
Other international(1) 137.3 355.6 176.2 299.6 87% 111%
--------- ------ ------ ------
Total Worldwide 319.0 333.4 411.0 912.8 67% 108%
========= ====== ====== ======
(1) Includes equity in affiliates
mmbbls = millions of barrels
bcf = billions of cubic feet
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 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 430 billion cubic feet of natural gas through 2020 and 140
billion cubic feet of natural gas through 2002 from Australian and U.K.
reserves. Pricing terms for substantially all of these contracts are
market-based. 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 1999, 1998 and 1997 are presented in Table I on page FS-32 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, 1999. 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.
-7-
Development Well Activity
Net Wells Completed (1)
Wells Drilling -----------------------------------------------
At 12/31/99 1999 1998 1997
----------------- ------------ ------------ ------------
Gross(2) Net(2) Prod. Dry Prod. Dry Prod. Dry
------- ------ ----- ---- ----- ---- ----- ----
United States 272 152 411 7 324 5 617 6
------- ------ ----- ---- ----- ---- ------ ----
Africa 10 4 18 - 38 1 22 1
Other International 27 16 42 - 33 2 67 -
------- ----- ----- ---- ----- ----- ------ ----
Total International 37 20 60 - 71 3 89 1
------- ----- ----- ---- ----- ----- ------ ----
Total Consolidated Companies 309 172 471 7 395 8 706 7
Equity in Affiliates 37 14 220 - 272 - 150 -
------- ----- ----- ---- ----- ----- ------ ----
Total Including Affiliates 346 186 691 7 667 8 856 7
======= ===== ===== ==== ===== ===== ====== ====
(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.
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, 1999.
Exploratory Well Activity
Net Wells Completed (1)
Wells Drilling -----------------------------------------------
At 12/31/99 1999 1998 1997
----------------- ------------ ------------ ------------
Gross(2) Net(2) Prod. Dry Prod. Dry Prod. Dry
------- ----- ------ ---- ----- ----- ------ ----
United States 50 26 72 30 46 12 56 31
------- ----- ------ ---- ----- ----- ------ ----
Africa 2 1 1 2 7 2 5 1
Other International 18 3 7 9 9 8 12 6
------- ----- ------ ---- ----- ----- ------ --
Total International 20 4 8 11 16 10 17 7
------- ----- ------ ---- ----- ----- ------ --
Total Consolidated Companies 70 30 80 41 62 22 73 38
Chevron's Share in Affiliates 8 4 1 - 2 - 3 -
------- ----- ------ ---- ----- ----- ------ ---
Total Including Affiliates 78 34 81 41 64 22 76 38
======= ===== ====== ==== ===== ===== ====== ===
(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.
"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 $374 million of
suspended exploratory wells included in properties, plant and equipment at
year-end 1999, an increase of $181 million from 1998. The increase between years
is primarily due to extensive drilling in Angola and the deepwater Gulf of
Mexico during 1999. 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 the results of future exploratory drilling
activity and development decisions.
-8-
Details of the company's exploration expenditures and costs of unproved property
acquisitions for 1999, 1998 and 1997 are presented in Table I on page FS-32 of
this Annual Report on Form 10-K.
Review of Ongoing Exploration and Production Activities in Key Areas
- --------------------------------------------------------------------
Chevron's 1999 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 over 300
fields located in the Gulf of Mexico, Texas, 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. Peak total production is expected to reach 55,000 barrels
of oil and 65 million cubic feet of gas per day in mid-2000. 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 and peak production rates of 200 million cubic feet of gas and 3,000
barrels of condensate per day were achieved in late 1999. Typhoon is Chevron's
third deepwater development, in 2,000 feet of water, in the Gulf of Mexico.
Under current development plans, initial production from Typhoon is scheduled
for third quarter 2001 and will support production of 40,000 barrels of oil and
60 million cubic feet of gas per day. Chevron is the operator with a 50 percent
interest.
Chevron has interests in the Viosca Knoll Trend in the Gulf of Mexico shelf and
in 1999 continued to focus on establishing production from additional gas
reservoirs. Total production is currently 80 million cubic feet of gas per day
from four wells and is expected to approach 200 million cubic feet of gas per
day once an infrastructure is completed in late 2000, with further development
planned for 2001 and 2002. Chevron's share of average 1999 total production of
40 million cubic feet of gas per day was 80 percent. Development of the Destin
Dome area of the Norphlet trend offshore Florida continues to be subject to
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. Issuance of the final EIS and a regulatory
ruling on the Development and Production Plan is expected in late 2000.
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 1999 production from the San Joaquin Valley
fields was 103,000 barrels of oil and 114 million cubic feet of gas per day.
In Alaska, Chevron continued to participate in appraisal and delineation
drilling in the Prudhoe Bay satellite developments. First oil from these
developments is planned for 2002. Chevron holds working interests of between 6
and 41 percent in these prospects. In 1999, Chevron, along with BP Amoco and
Phillips Petroleum, acquired 33 leases totaling 233,000 acres in the National
Petroleum Reserve of Alaska.
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, and renewal
efforts will begin soon. 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
projects in Nigeria. CPNL has a 30 percent interest in one deepwater Niger Delta
block and three inland Benue Basin blocks operated by Elf. A sole interest is
also held by CPNL in six other Benue Basin blocks through a production-sharing
contract.
-9-
Production from the 33 CNL-operated fields averaged about 420,000 barrels of
liquids per day in 1999, slightly higher than 1998. Production from the COCNL
fields averaged approximately 45,000 barrels of oil per day in 1999.
Construction of Escravos Gas Project Phase 2 is scheduled for completion in
second quarter 2000. Phase 2 will expand the gas processing capacity of the
facility to 285 million cubic feet per day. Preliminary design is under way for
Phase 3 of the gas plant, which will add a second train and expand gas
processing to 680 million cubic feet per day, once the necessary approvals are
obtained. Feasibility engineering and technical evaluations are nearing
completion for a Gas-To-Liquids (GTL) plant proposed for construction in
Escravos. Promising results would lead to continued development during 2000. The
proposed 30,000-barrels-per-day Escravos project is expected to be the first of
a previously announced GTL globalization effort by Chevron and SASOL.
In 1999, CNL was appointed the Managing Sponsor of a consortium of six energy
companies, which was granted development rights by the governments of Benin,
Ghana, Nigeria and Togo to construct and operate a gas transmission pipeline
between these countries. Subject to successful negotiation of concession
conditions with the governments, commercial operations may commence by late
2002.
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 crude oil production during 1999 averaged 460,000 barrels per day up
from an average of 421,000 in 1998. Area A of Block 0 includes 23 major fields,
13 in the Malongo Area and 10 in the Takula Area. Fifteen of the Area A fields
are currently producing. The Banzala Field achieved first production in August
1999 and is producing at a rate of over 20,000 barrels of oil per day.
Installation of new waterflood projects in the Kungulo and Vuko fields
progressed. Area B includes six major fields. The Kokongo and Lomba fields and
the southern part of the Nemba Field have undergone the initial stages of
development and are currently on production with additional infill well
opportunities envisioned for the Kokongo and Nemba fields in 2000. Future
development plans also include installation of the North Nemba production and
gas injection platform in 2001. During 1999, a vessel carrying the production
deck for the North Nemba facility capsized and the deck was lost. As a result,
the start of production from North Nemba will be delayed from 2000 to 2001.
This is not expected to have a significant impact on overall 2000 or 2001
production levels. Area C includes seven major fields. The Ndola and Sanha
fields are currently on production.
Four fields have been discovered in Block 14 - Kuito, Landana, Benguela and
Belize. First production from the Kuito Field commenced in December 1999.
Production rates in early 2000 average 30,000 barrels of oil per day. Kuito is
being developed using a phased approach, with Phase One production expected to
average over 70,000 barrels per day in 2000 and to peak at a rate of 100,000
barrels per day during the first half of 2000. The Benguela and Belize fields,
discovered in 1998, are located near the Kuito Field. Development planning is in
progress for the two fields with project authorization targeted for the first
half of 2001. For the Landana Field, further appraisal and study is required
prior to development planning.
Republic of Congo: Chevron has interests in three license areas - Haute Mer,
Marine VII and Mer Profonde Sud - in offshore Congo, adjacent to Chevron's
concessions in Angola. All licenses are partner-operated. Net production from
Chevron's concessions in the Republic of Congo averaged about 29,000 barrels per
day in 1999. 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 36,000 barrels of
oil per day. Further development work, including gas injection facilities and an
infill well, are planned for 2000. In Haute Mer, where Chevron has a 30 percent
interest, development of the Nkossa Field continued with the drilling of
additional production and gas injection wells. Total production in the field,
operated by Elf Congo, averaged about 74,000 barrels of oil and liquefied
petroleum gas per day in 1999. Development planning for the Moho and Bilondo
fields in the Haute Mer license continues. Chevron obtained a 15 percent
interest in the Mer Profonde Sud license at the end of 1999.
-10-
C) Other International Areas
Caspian Region: The Tengizchevroil (TCO) partnership formed in 1993 covers the
Tengiz and Korolev oil fields in western Kazakhstan. Chevron has a 45 percent
interest in TCO. In 1999, total liquids production from the Tengiz Field
increased for the sixth straight year, averaging 214,000 barrels per day. TCO is
nearing completion of a three-year plant expansion project. The project provides
TCO with additional processing and export facilities that will permit production
to increase to approximately 260,000 barrels per day by the fourth quarter of
2000. TCO plans to initiate production from the Korolev Field in 2001. The
Caspian Pipeline Consortium (CPC) was formed to build a crude oil export
pipeline from the Tengiz oil field to the Russian Black Sea coast at a projected
total cost of $2.5 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.
Construction at the marine terminal and tank farm commenced in May 1999, while
pipe laying began in November 1999. CPC remains on schedule to deliver first oil
by July 2001.
Europe: Chevron holds interests in four producing fields off-shore 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 74,000 barrels of crude oil per day in 1999. Chevron's interest
in the Alba Field is approximately 21 percent. 1999 was the first full year of
production for the Britannia Field. At peak demand, the field produced 740
million cubic feet of gas per day and in excess of 45,000 barrels per day of
condensate. Chevron has an approximate 30 percent interest in Britannia and
shares operatorship with Conoco. In Norway, production from the Draugen Field
averaged 209,000 barrels of crude oil per day. Chevron's interest in the Draugen
Field is about 8 percent.
Canada: In 1999, Chevron continued to increase its offshore lease position in
Canada's East Coast and maintained focus on core areas in Western Canada.
Production from the Hibernia Field, in which Chevron holds an interest of about
27 percent, averaged approximately 100,000 barrels of crude oil per day in 1999,
with rates up to 150,000 barrels per day achieved during the latter part of the
year. Delineation drilling of the Hebron Field continued during the year with
encouraging results. Chevron was appointed operator of the Hebron Field and has
an approximate 30 percent interest. Chevron also acquired interests in three
deepwater parcels totaling approximately 1.2 million acres at the Nova Scotia
lease sale in April 1999. Chevron's interest in these blocks is approximately 33
percent, and supplements the 740,000-acre deepwater Nova Scotia parcel acquired
in 1998. Chevron's Western Canadian operations produced 44,500 barrels per day
of crude oil and natural gas liquids in 1999. Chevron's major development
efforts in 1999 focused on natural gas, primarily in the area west of Kaybob in
Alberta, and Fort Liard in the Northwest Territories. During 1999, a significant
natural gas discovery was made northwest of Fort Liard. Plans are being
developed for the construction of production and transportation facilities and
additional wells to permit first production by May 2000. A second successful
well was completed in January 2000 and is expected to begin production in the
fourth quarter 2000.
Australia: Chevron's primary interests in Australia involve two major joint
ventures. Average total field production during 1999 from the North Rankin and
Goodwyn fields in the North West Shelf (NWS) project, where Chevron has an
approximate 17 percent interest, was 1.5 billion cubic feet of gas per day.
Total condensate production averaged 100,000 barrels per day. Additionally in
1999, total production from the Wanaea/Cossack oil development averaged 35,000
barrels per day. The second joint venture is in permit areas, which include the
Barrow Island and Thevenard Island oil fields and the undeveloped Gorgon gas
field formerly operated by West Australian Petroleum Pty. Ltd. (WAPET). Chevron
assumed operatorship of these areas from WAPET in February 2000 and has
interests varying between 25 and 50 percent. During 1999, total oil production
from the WAPET area averaged 30,000 barrels per day with Chevron's share about
8,000 barrels per day. The WAPET joint venture made two significant natural gas
discoveries in the offshore permit area WA-267-P where Chevron has a 25 percent
interest - Geryon and Orthrus. In addition to the two major joint ventures
above, Chevron has interests in the northern Browse Basin, and three new
deepwater exploration permits recently awarded in the offshore Canning Basin,
near the NWS joint venture acreage. Chevron's interests vary from about 17
percent to 25 percent.
Indonesia: Chevron's interests in Indonesia are managed by two affiliate
companies, P.T. 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 745,000
-11-
barrels per day in 1999 was 182,000 barrels per day. The Duri Field, under
steamflood since 1985, is the largest steamflood in the world. AI is a power
generation company, which 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 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.
China: Chevron has an interest in two blocks (16/08 and 16/19) in the South
China Sea and three blocks (02/31, 06/17 and Zhanhuadong) in the Bohai Gulf area
of the North China Basin. Chevron has an interest of about 16 percent in the
producing Block 16/08, which produced an average of 101,600 barrels of oil per
day in 1999. The newest field in the group, HZ/32-5, was brought on stream early
in 1999 with three wells producing at a combined rate in excess of 30,000
barrels of oil per day. Chevron plans to complete its current exploration
contractual commitments in 2000 by drilling two more exploration wells on Block
02/31, one on Block 06/17, two in Zhanhuadong, and one on Block 16/19.
Thailand: Chevron acquired Rutherford-Moran Oil Corporation and its approximate
46 percent interest in Gulf of Thailand Block B8/32 in March 1999. This,
combined with acquisition of a majority interest in Palang Sophon Limited, gave
Chevron an approximate 52 percent interest Block B8/32. Chevron assumed
operatorship of Block B8/32 in October 1999. Chevron also holds a 33 percent
interest in three adjacent exploration blocks, which are currently inactive
pending resolution of a Thailand-Cambodia border dispute. Block B8/32 is
currently producing oil and natural gas from two fields, Tantawan and Benchamas.
In December 1999, the Tantawan Field was producing at a rate of 65 million cubic
feet of gas per day and 9,600 barrels of oil per day. Benchamas Field was
brought on-stream in June 1999 and was producing at a rate of 77 million cubic
feet of gas per day and 13,000 barrels of oil per day as of December 1999.
Production from the Benchamas Field reached 25,000 barrels of oil per day and 85
million cubic feet of gas per day during the first quarter 2000.
Argentina: Chevron acquired Petrolera Argentina San Jorge, S.A. in September
1999 establishing its first exploration and production position in Argentina. At
year-end 1999, properties in the Neuquen and Austral Basins were producing at
combined gross rates of 85,000 barrels of oil equivalent per day. New oil and
gas discoveries in 1999 increased proved reserves to over 200 million barrels
oil equivalent. In addition to the Argentina acreage, San Jorge's interests
included five million acres of exploration licenses in key petroleum basins in
Colombia, Ecuador, Peru, Bolivia, and Chile. Included in the acquisition was a
14 percent interest in Oldeval, a major export pipeline to the Argentine
Atlantic coast. Additional sales through the Transandino pipeline to the Pacific
coast make San Jorge Argentina's second largest petroleum exporter.
Venezuela: Chevron is the operator and has a 27 percent interest in the LL-652
Field in Lake Maracaibo. The LL-652 Field objective is to substantially increase
production over the next few years though the application of secondary recovery
technologies. The field was producing 12,500 barrels of oil per day at the end
of 1999. Chevron holds a 27 percent interest in the LL-652 project. 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 and production of the Boscan Field in 1996 under an operating
services agreement. Chevron receives operating expense reimbursement and capital
recovery, plus interest and an incentive fee. Due to Venezuela's OPEC
restrictions, production was constrained to 92,000 barrels per day for much of
1999, down from 105,000 barrels per day at the start of the year. Chevron has
not recorded any reserve quantities related to the service agreement involving
the Boscan Field.
-12-
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 it has a 28 percent equity
interest. 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 1999, U.S. sales volumes, including the company'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 are reported in the following table:
Natural Gas Liquids Sales Volumes
(Thousands of Barrels per Day)
1999 1998 1997
------- ------ ------
United States 65 63 64
Canada 24 26 30
Other International 10 7 13
------- ------- ------
Total Consolidated Companies 99 96 107
Share of Dynegy Affiliate 91 87 95
------- ------- ------
Total including Affiliate 190 183 202
======= ======= ======
Petroleum - Refining
--------------------
Based on refinery statistics published in the December 20, 1999 issue of The Oil
and Gas Journal, Chevron had the third largest U.S. refining capacity. The
company's 50 percent owned Caltex Corporation affiliate owned or had interests
in 11 operating refineries: Australia (2), Thailand (2), Korea, the Philippines,
New Zealand, Singapore, Pakistan, Kenya and South Africa. In 1999, Caltex sold
its interest in two Japanese refineries owned by Koa Oil Company Limited.
Distillation operating capacity utilization in 1999, adjusted for sales and
closures, averaged 91 percent in both the United States (including asphalt
plants) and worldwide (including affiliate), compared with 83 percent in the
United States and 86 percent worldwide in the prior year. Chevron's capacity
utilization at its U.S. fuels refineries averaged 96 percent in 1999, up from 86
percent in 1998. 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 78 percent in 1999, up from 75
percent in the year earlier. The company processed imported and domestic crude
oil in its U.S. refining operations. Imported crude oil accounted for 66 percent
of Chevron's U.S. refinery inputs in 1999.
-13-
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:
Petroleum Refineries: Locations, Capacities And Inputs
(Inputs and Capacities are in Thousands of Barrels Per Day)
December 31, 1999
-------------------
Refinery Inputs
Operable ---------------------------
Locations Number Capacity 1999 1998 1997
--------------------------------------------------- ------ -------- ------ ------ -----
Pascagoula, Mississippi 1 295 328 246 312
El Segundo, California 1 260 211 218 203
Richmond, California 1 225 207 201 220
El Paso,(1) Texas 1 65 65 62 60
Honolulu, Hawaii 1 54 51 49 53
Salt Lake City, Utah 1 45 43 40 41
Other(2) 3 102 50 52 44
--- ------ ------ ------ -----
Total United States 9 1,046 955 868 933
--- ------ ------ ------ -----
Burnaby, B.C., Canada 1 52 52 50 48
Milford Haven, Wales,(3) United Kingdom - - - - 101
--- ------ ------ ------ -----
Total International 1 52 52 50 149
--- ------ ------ ------ -----
Total Consolidated Companies 10 1,098 1,007 918 1,082
Equity in Caltex Affiliate(4) Various Locations 11 426 417 425 416
--- ------ ------ ------ -----
Total Including Affiliate 21 1,524 1,424 1,343 1,498
=== ====== ====== ====== =====
(1) Capacity and input amounts for El Paso represent Chevron's share.
(2) Refineries in Perth Amboy, New Jersey; Portland, Oregon; and Richmond
Beach, Washington, which are primarily asphalt plants.
(3) Ceased processing operations December, 1997.
(4) Inputs 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.
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 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 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 Corporation, which maintains an
interest in about 7,800 service stations (of which about 4,700 are branded
Caltex), operating in more than 60 countries in the Asia-Pacific region, Africa
and the Middle East, and (2) the company's interest in Fuel and Marine Marketing
LLC, which was established in late 1998 and markets marine fuel and lubricating
oils in approximately 100 countries worldwide.
-14-
Refined Products Sales Volumes
(Thousands of Barrels Per Day)
1999 1998 1997
--------- --------- --------
United States
Gasolines 667 653 591
Jet Fuel 234 247 249
Gas Oils and Kerosene 236 198 204
Residual Fuel Oil 64 56 60
Other Petroleum Products(1) 101 89 89
--------- --------- --------
Total United States 1,302 1,243 1,193
--------- --------- --------
International
United Kingdom(2) - 3 103
Canada 60 58 61
Other International 36 127 145
--------- --------- --------
Total International 96 188 309
--------- --------- --------
Total Consolidated Companies 1,398 1,431 1,502
Chevron's Share in Affiliates 796 597 577
--------- --------- --------
Total Including Affiliates 2,194 2,028 2,079
========= ========= ========
(1) Principally naphtha, lubes, asphalt and coke.
(2) Retail marketing assets in the United Kingdom were
sold in December 1997.
Retail Outlets: In the United States, the company supplies, directly or through
jobbers, more than 7,900 motor vehicle retail outlets, of which about 1,500 are
company-owned or -leased motor vehicle stations, and about 560 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 15
states, and is the top marketer of aviation fuel in the western United States.
During 1999, the company continued to rationalize its marketing network by
divesting small, lower-performing sites and investing in larger, higher-volume
facilities.
The company has continued to focus on a growing demand for convenience goods and
services. In 1999, the company experienced an overall company-operated gross
revenue growth from these areas of nearly 28 percent.
In Canada - primarily British Columbia - the company's branded products are sold
in nearly 200 stations (all owned or leased).
-15-
Petroleum - Transportation
--------------------------
Tankers: Chevron's controlled seagoing fleet at December 31, 1999, is summarized
in the following table. All controlled tankers were utilized in 1999. In
addition, at any given time, the company has 30 to 40 vessels under charter on a
term or voyage basis.
Controlled Tankers At December 31, 1999
U.S. Flag Foreign Flag
-------------------------------- ------------------------------
Cargo Capacity Cargo Capacity
Number (Millions of Barrels) Number (Millions of Barrels)
------- --------------------- ------ ---------------------
Owned 2 0.8 15 21.1
Bareboat Charter 2 0.5 13 16.1
Time-Charter - - 1 0.5
---- ----- ---- -------
Total 4 1.3 29 37.7
==== ===== ==== =======
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 1999, 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 1999, Chevron
was operating a total of 13 double hull tankers. Chevron has been actively
involved in the Marine Preservation Association, a non-profit organization that
funds the Marine Spill Response Corporation (MSRC). MSRC owns the largest
inventory of oil spill response equipment in the nation and operates five
strategically located U.S. coastal regional centers. In addition, the company is
a member of many oil-spill response cooperatives in areas in which it operates
around the world.
At year-end 1999, two of the company's controlled international flag vessels
were assigned for use as floating storage vessels. 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.
During 1999, the company completed the sale of seven vessels and chartered back
three. Additionally, in 1999 the company took delivery of two new 308,500
deadweight ton, double-hull tankers. These tankers are the second and third in a
series of four new double-hull tankers being built in Korea. The last vessel was
delivered in February 2000. Chevron will operate these tankers under long-term
bareboat charters.
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:
-16-
Pipeline Mileage At December 31, 1999
Wholly Partially
Owned Owned(1) Total
--------- --------- --------
United States:
Crude oil(2) 2,768 460 3,228
Natural gas 477 159 636
Petroleum products 2,084 1,958 4,042
--------- --------- --------
Total United States 5,329 2,577 7,906
--------- --------- --------
International:
Crude oil - 950 950
Natural gas - 325 325
Petroleum products - 587 587
--------- --------- --------
Total International - 1,862 1,862
--------- --------- --------
Worldwide 5,329 4,439 9,768
========= ========= ========
(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. production function.
Chemicals
---------
The company's chemicals operations manufacture and market petrochemicals and
petrochemical-based products for industrial use and chemical additives for fuels
and lubricants. At year-end 1999, Chevron owned and operated 15 U.S.
manufacturing facilities in nine states, owned manufacturing facilities in
Brazil, France, Singapore and Mexico, and owned a majority interest in a
manufacturing facility in Japan. Additionally, Chevron has a 50 percent equity
interest in a petrochemicals facility in Saudi Arabia.
In February 2000, Chevron and Phillips Petroleum Co. signed a letter of intent
and exclusivity agreement to combine most of their chemicals businesses into a
joint venture. Each company will own 50 percent of the joint venture, which will
have assets of more than $6 billion and would have had 1999 sales of about $6
billion. The combination is subject to final approval of the companies' boards
of directors, signing of definitive agreements and regulatory review, which are
expected to be complete by mid-2000.
In 1999, the company commenced commercial operation of a fuel and lube oil
additives manufacturing facility in Singapore. The plant has an annual capacity
of approximately 100,000 metric tons of additives. In Saudi Arabia, the company
and its joint venture partner, the Saudi Industrial Venture Capital Group,
completed construction of a petrochemicals complex expected to produce annually
approximately 480,000 tons of benzene, using the company's proprietary Aromax
technology, and 220,000 tons of cyclohexane.
In 2000, the company plans to complete a grass roots normal alpha olefins plant
at Cedar Bayou, Texas. In China, start-up of a 100,000 tons per year polystyrene
plant is planned for mid-2000. This plant represents the company's entry into
the chemicals business in China.
The following table shows 1999 revenues and the number of owned or
majority-owned chemicals manufacturing facilities and combined operating
capacities as of December 31, 1999.
-17-
Chemicals Operations
--------------------
Annual 1999
Manufacturing Capacity Production Revenue*
Facilities (Million lbs.) (Million lbs) ($ Millions)
---------------- -------------- ------------- -------------
U.S. 15 16,657 15,498 $2,958
International 5 951 685 779
--- ------- ------------ -------------
Total 20 17,608 16,183 $3,737
== ======= ============ =============
*Includes intercompany sales.
Coal
----
Coal: The Company's wholly owned coal mining and marketing subsidiary, The
Pittsburg & Midway Coal Mining Co. (P&M), owned four surface and two underground
mines at year-end 1999. All mines were operating at that time with the exception
of the Sebree Mine in Kentucky, which was idled in November 1998. P&M also owns
an approximate 30 percent interest in Inter-American Coal Holding N.V., which
has interests in mining operations in Venezuela.
In the second half of 1998, the company began actively marketing its entire coal
business for sale. In the first quarter 1999, P&M sold its 33 percent interest
in the Black Beauty Coal Company. In the fourth quarter 1999, the Company
discontinued negotiations to sell the Company's remaining coal operations, and
the assets are no longer held for sale.
Sales and other operating revenues in 1999 were $366 million, a decrease of 9
percent from 1998. Sales of coal from P&M's wholly owned mines and from its
affiliates were 16.0 million tons, a decrease of 31 percent from 1998. The
average selling price for coal from mines owned and operated by P&M was $22.73
per ton in 1999, compared with $23.21 per ton in 1998. At year-end 1999, P&M
controlled approximately 398 million tons of developed and undeveloped coal
reserves, including significant reserves of environmentally desirable low-sulfur
fuel.
Electronic Commerce and Technology
----------------------------------
Electronic Business: During 1999, Chevron implemented a new growth initiative
aimed at developing business opportunities capitalizing on Internet Web
technology. The company established a subsidiary to leverage electronic
opportunities in Chevron's business units. Additionally, the new subsidiary
plans to develop new Internet "business to business" (B2B) ideas for use in the
company's own operations and for potential development with other outside
investors. During the first quarter 2000, the company announced its
participation in a number of B2B joint ventures. These include Internet
marketplaces of goods and services for the oil and gas industry, and convenience
store and small business retailers. The company plans to develop additional
Internet commerce opportunities in the future, for use in its own operations and
for offer to third party investors.
New Technology: Chevron also established a technology ventures unit during 1999.
The company plans to focus on making equity investments in a broad portfolio of
emerging technology companies with expertise in information technology,
materials sciences and biotechnology. These investments will be directed toward
areas where the company will potentially be a customer.
Research and Environmental Protection
-------------------------------------
Research: The company's principal research laboratories are at Richmond and San
Ramon, California and Houston, Texas. In February 1999, the company relocated
most of the research activities previously carried out at La Habra, California
to the San Francisco Bay Area. 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
-18-
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 1999 numbered
more than 900, with approximately 500 additional employees working on research
activities in the company's other operating units.
Chevron's research and development expenses were $182 million, $187 million and
$179 million for the years 1999, 1998 and 1997, 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 1999, the company's U.S. capitalized environmental expenditures were $121
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 $192 million and $177 million in
1998 and 1997, 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 2000,
the company estimates U.S. capital expenditures for environmental control
facilities will be $137 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 1999 environmental expenditures, remediation provisions and year-end
environmental reserves are discussed on page FS-4 of this Annual Report on Form
10-K.
-19-
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-32 to FS-37 of this Annual Report on Form 10-K. Note 13, "Properties, Plant
and Equipment," to the company's financial statements contained on page FS-25 of
this Annual Report on Form 10-K 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 1999, 1998 and 1997.
Item 3. Legal Proceedings
A. Cities Service Co. v. The Gulf Oil Corporation
Oklahoma State District Court for the District of Tulsa.
This matter, previously reported as Item 3A of company's Annual Report on Form
10-K for the year ended December 31, 1998, and amended in Item 1 of the
company's Amended Quarterly Report for the period ended June 30, 1999 and its
Quarterly Report for the period ended September 30, 1999, was resolved pursuant
to a settlement agreement entered into on November 18, 1999. OXY USA agreed to
accept $775 million in full satisfaction of all liability related to the
judgment and the claims asserted in the lawsuit. In accord with the settlement,
Chevron's certiorari petition was dismissed on November 18, 1999. Chevron made
the settlement payment on December 1, 1999, and OXY USA executed a formal
satisfaction of the judgment that same day. Also on December 1, 1999, the Tulsa
District Court entered an order exonerating and releasing the supersedeas bond.
B. Rangely Field - Clean Water Act.
In 1999, EPA made a civil penalty demand of $1.5 million under the Clean Water
Act concerning spills that have occurred at the company's operations at the
Rangely Field, Colorado.
C. El Segundo Refinery - Clean Air Act.
In 1998, EPA issued a Notice of Violation alleging Clean Air Act violations at
the company's El Segundo, California, refinery.
D. Richmond Refinery - VOC emissions.
The Bay Area Air Quality Management District has initiated an enforcement action
against the company's Richmond, California, refinery associated with alleged
violations of the District's rules relating to fugitive VOC emissions from
connections.
E. Hawaii Refining and Marketing Facilities - Clean Air Act.
The Department of Justice has made civil penalty demands totaling approximately
$1.5 million alleging violations of the Clean Air Act by the company's Hawaii
refinery and its associated Hilo and Kahului terminals.
F. Perth Amboy Refinery - Clean Air Act.
The company has agreed to pay $145,000 to settle allegations that it failed to
monitor certain emissions as required by the Clean Air Act at its Perth Amboy,
New Jersey, refinery.
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 1999 to a vote of security
holders through the solicitation of proxies or otherwise.
-20-
Executive Officers of the Registrant at March 1, 2000
Name and Age Executive Office Held Major Area of Responsibility
- ------------------ ---------------------------- ----------------------------
D.J. O'Reilly 53 Chairman of the Board since Chief Executive Officer
2000 Human Resources
Director since 1998
Executive Committee Member
since 1994
R.H. Matzke 63 Vice-Chairman of the Board Worldwide Exploration and
since 2000 Production Activities
Director since 1997
President of Chevron Overseas
Petroleum Inc.from 1989 to 2000
Executive Committee Member
since 1993
J.N. Sullivan 62 Vice-Chairman of the Board Worldwide Refining,Marketing
since 1989 and Transportation
Director since 1988 Activities,
Executive Committee Member Chemicals, Real Estate,
since 1986 Environmental, Coal,
Administrative Services,
Aircraft Services
D.W. Callahan 57 Vice-President since 1999 Chemicals
President of Chevron Chemical
Company since 1999
Executive Committee Member
since 1999
H.D. Hinman 59 Vice-President and General Law
Counsel since 1993
Executive Committee Member
since 1993
G.L. Kirkland 49 President of Chevron U.S.A. North American
Production Company since 2000 Exploration and Production
Executive Committee Member
since 2000
M.R. Klitten 55 Vice-President and Chief Finance
Financial Officer since 1989
Executive Committee Member
since 1989
P.J. Robertson 53 Vice-President since 1994 Overseas Exploration and
President of Chevron Overseas Production
Petroleum Inc. since 2000
Executive Committee Member
since 1997
P.A. Woertz 46 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-Chairmen 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-
G.L. Kirkland - General Manager, Production, Chevron Nigeria Limited - 1992
- 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 - Vice-President for Strategic Planning and Quality,
Chevron Corporation - 1994
- 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
P.A. Woertz - President, Chevron Canada Limited - 1993
- President, Chevron International Oil Company - 1996
- Vice President, Logistics and Trading, Chevron
Products Company - 1996
- President, Chevron Products Company - 1998
K.T. Derr, Chairman of the Board and Chief Executive Officer since 1989, retired
on December 31, 1999.
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 1995 through 1999 are presented on page
FS-38 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-
PART III
Item 10. Directors and Executive Officers of the Registrant
The information on Directors appearing on pages 4 through 7 of the Notice of
Annual Meeting of Stockholders and Proxy Statement dated March 22, 2000, 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 11 of the Notice of Annual Meeting of
Stockholders and Proxy Statement dated March 22, 2000 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 1999.
Item 11. Executive Compensation
The information on pages 12 through 19 of the Notice of Annual Meeting of
Stockholders and Proxy Statement dated March 22, 2000, 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 11 of the Notice of Annual Meeting of Stockholders and
Proxy Statement dated March 22, 2000 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, 1999 FS-13
Consolidated Statement of Comprehensive Income
for the three years ended December 31, 1999 FS-13
Consolidated Balance Sheet at December 31,
1999 and 1998 FS-14
Consolidated Statement of Cash Flows
for the three years ended December 31, 1999 FS-15
Consolidated Statement of Stockholders' Equity
for the three years ended December 31, 1999 FS-16
Notes to Consolidated Financial Statements FS-17 to FS-31
-23-
(2) Financial Statement Schedules:
Caltex Group of Companies Combined
Financial Statements C-1 to C-24
The Combined Financial Statements of the Caltex Group of Companies
are filed as part of this report. All schedules 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 26 and 27 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, dated November 18, 1999, was filed by
the company on November 18, 1999. In this report, Chevron announced
that it had reached an agreement with Occidental Petroleum to
settle the Cities Service litigation.
(2) A Current Report on Form 8-K, dated January 18, 2000, was filed by
the company on January 18, 2000. In this report Chevron filed
restated financial statements for the three- and six-month periods
ended June 30, 1999 and the three- and nine- month periods ended
September 30, 1999. These statements were restated to recognize the
initial ownership of certain marketable equity securities and
subsequent unrealized gains on these securities.
(3) A Current Report on Form 8-K, dated March 6, 2000, was filed by the
company on March 6, 2000. In this report, Chevron filed the company's
1999 audited financial statements.
(4) An amended current report on Form 8-K, dated March 7, 2000 was
filed by the company on March 7, 2000. In this amended report,
Chevron re-filed the company's 1999 audited financial statements
previously filed in a Current Report on Form 8-K, dated March 6,
2000, filed on March 6, 2000.
-24-
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 29th 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 29th day of March 2000.
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
JAMES N. SULLIVAN* CARLA A. HILLS *
- --------------------------------------------- -------------------------
James N. Sullivan, Vice-Chairman of the Board Carla A. Hills
J. BENNETT JOHNSTON*
-------------------------
J. Bennett Johnston
CHARLES M. PIGOTT*
-------------------------
Principal Financial Officer Charles M. Pigott
MARTIN R. KLITTEN* CONDOLEEZZA RICE*
- --------------------------------------------- -------------------------
Martin R. Klitten, Vice-President Condoleezza Rice
and Chief Financial Officer
FRANK A. SHRONTZ*
-------------------------
Principal Accounting Officer Frank A. Shrontz
STEPHEN J. CROWE* CHANG-LIN TIEN *
- --------------------------------------------- -------------------------
Stephen J. Crowe, Comptroller Chang-Lin Tien
JOHN A. YOUNG*
-------------------------
John A. Young
*By: /s/ LYDIA I. BEEBE
--------------------------------------
Lydia I. Beebe, Attorney-in-Fact
-25-
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.
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 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.
10.2 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.
10.3 Supplemental Pension Plan of Gulf Oil Corporation, amended as
of June 30, 1986, filed as Exhibit 10.4 to Chevron
Corporation's Annual Report on Form 10-K for 1986 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.
-26-
EXHIBIT INDEX
(continued)
Exhibit
No. Description
- -------- --------------------------------------------------------------------
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
24.14 on Form 10-K on their behalf.
27.1 Financial Data Schedule
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.
-27-
INDEX TO MANAGEMENT'S DISCUSSION AND ANALYSIS
CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page(s)
-------------
Management's Discussion and Analysis FS-2 to FS-11
Quarterly Results and Stock Market Data FS-11
Report of Management FS-12
Report of Independent Accountants FS-12
Consolidated Statement of Income FS-13
Consolidated Statement of Comprehensive Income FS-13
Consolidated Balance Sheet FS-14
Consolidated Statement of Cash Flows FS-15
Consolidated Statement of Stockholders' Equity FS-16
Notes to Consolidated Financial Statements FS-17 to FS-31
Supplemental Information on Oil and Gas Producing Activities FS-32 to FS-37
Five-Year Financial Summary FS-38
FS-1
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
1999 KEY INDICATORS
* Net income increased 55 percent to $2.070 billion
* Exploration and production operational earnings rose 80 percent
* Average U.S. crude oil realizations increased 41 percent to $16.11 per
barrel
* Average U.S. natural gas realizations were up 7 percent to $2.16 per
thousand cubic feet
* International liquids production increased for the 10th consecutive year
- up 4 percent
* Refining, marketing and transportation operational earnings declined 44
percent on lower margins
* Worldwide net oil and gas reserves additions exceeded production for the
seventh consecutive year
* Annual dividends increased for the 12th consecutive year
KEY FINANCIAL RESULTS
Millions of dollars,
except per-share amounts 1999 1998 1997
- -----------------------------------------------------------------
Net Income ...................... $ 2,070 $ 1,339 $ 3,256
Special (Charges) Credits
Included in Net Income (216) (606) 76
- -----------------------------------------------------------------
Earnings, Excluding Special Items $ 2,286 $ 1,945 $ 3,180
- -----------------------------------------------------------------
Per Share:
Net Income - Basic $ 3.16 $ 2.05 $ 4.97
- Diluted .... $ 3.14 $ 2.04 $ 4.95
Dividends ..................... $ 2.48 $ 2.44 $ 2.28
Sales and
Other Operating Revenues ...... $35,448 $29,943 $40,596
Return on:
Average Capital Employed ...... 9.4% 6.7% 15.0%
Average Stockholders' Equity .. 11.9% 7.8% 19.7%
=================================================================
Chevron's net income for 1999 was $2.070 billion, up 55 percent from 1998 net
income of $1.339 billion, but 36 percent lower than record earnings of $3.256
billion in 1997. Net special charges of $216 million in 1999 included losses
from asset write-downs, environmental remediation provisions and restructuring
charges, partially offset by benefits from the sale of assets, net favorable
adjustments for prior years' taxes and litigation issues and net LIFO inventory
gains. Net special charges in 1998 included a loss provision of $637 million for
litigation, substantially all of which pertained to a lawsuit against Gulf Oil
by Cities Service filed in 1982 - prior to the Chevron-Gulf merger in 1984.
Included in net income were foreign currency losses of $38 million in 1999 and
$47 million in 1998 and gains of $246 million in 1997.
NET INCOME BY MAJOR OPERATING AREA
Millions of dollars 1999 1998 1997
- ---------------------------------------------------------------------------
Exploration and Production
United States $ 526 $ 365 $1,001
International 1,093 707 1,252
- ---------------------------------------------------------------------------
Total Exploration and Production 1,619 1,072 2,253
- ---------------------------------------------------------------------------
Refining, Marketing and Transportation
United States 357 572 601
International 74 28 298
- ---------------------------------------------------------------------------
Total Refining, Marketing
and Transportation 431 600 899
- ---------------------------------------------------------------------------
Chemicals 109 122 228
All Other (89) (455) (124)
- ---------------------------------------------------------------------------
Net Income $2,070 $1,339 $3,256
===========================================================================
Net income for the company's individual business segments is discussed in the
Results of Operations section.
ENVIRONMENT AND OUTLOOK
Crude oil prices rose dramatically during most of 1999, after falling to 20-year
lows in late 1998. The sharp rise in prices was largely driven by agreements
among the Organization of the Petroleum Exporting Countries (OPEC) and several
larger non-OPEC producers to curtail production. The spot price of West Texas
Intermediate (WTI) benchmark crude oil averaged $19.30 per barrel for 1999,
compared with $14.38 for 1998 and $20.60 for 1997. The 1999 year-end WTI spot
price was $25.60. Fluctuations in natural gas prices, on the other hand, were
not as dramatic as crude oil. The average 1999 Henry Hub spot natural gas price
was $2.27 per thousand cubic feet, up 9 percent from 1998 and down 12 percent
from the 1997 average.
Crude oil prices remained strong in early 2000, but it is uncertain how long the
high price levels will continue. Some factors that may affect future price
changes include OPEC's actions to maintain or change its crude oil production
quotas, unforeseen supply disruptions, worldwide inventory levels, demand for
heating oil and natural gas as a result of winter weather conditions in the
Northern Hemisphere, and the demand for refined products reflecting the overall
strength of the world economies. High crude oil prices increase the company's
revenues and earnings in exploration and production operations. However, higher
crude oil prices could adversely affect financial results in the refining,
marketing and chemicals businesses if higher feedstock costs cannot be recovered
in the prices of finished products.
The company continues to focus on cost control in all of its businesses to help
sustain Chevron's competitiveness worldwide - regardless of commodity price
levels. In 1999, Chevron's initiatives to eliminate $500 million from its cost
structure were very successful. Operating companies and corporate departments
were streamlined, and by mid-2000 staff reductions of approximately 10 percent
from year-end 1998 levels will have been achieved. Successful containment of
costs and improved operating cash flows during 1999 enabled the company to
maintain a robust capital spending program during the recent period of price
volatility. Maintaining a consistent level of capital spending - while other
competitors were cutting back because of low commodity prices - gave the
company an advantage with the rebound in crude oil prices.
SIGNIFICANT DEVELOPMENTS
Chevron's worldwide oil and equivalent-gas (OEG) production was up 3 percent in
1999, with international net OEG production increasing 7 percent. Chevron's 1999
worldwide oil-equivalent barrels of net proved reserves additions exceeded
production for the seventh consecutive year. The company's reserves replacement
was 108 percent of production for 1999, including sales and acquisitions.
Key events during 1999 and early 2000 to capture profitable growth
opportunities follow.
Upstream Acquisitions
Chevron made two acquisitions in 1999 that will help sustain the company's
growth in international exploration and production. The September acquisition of
Petrolera Argentina San Jorge S.A., coupled with the award in early 2000 of
rights to partner with Petrobras in a 50-50 exploration venture in two promising
deepwater blocks offshore Brazil, were significant steps in the company's Latin
FS-2
America growth strategy. The March purchase of Rutherford-Moran Oil Corporation
and the assumption of the operatorship of Block B8/32 offshore Thailand provided
an entry into the natural gas market in Southeast Asia. The company began new
production from the Benchamas Field offshore Thailand and announced new
discoveries in prospects from both of these acquisitions.
Angola
In December, oil production started at the Chevron-operated, 31 percent-owned
Kuito Field, Angola's first deepwater production from Block 14. After the recent
successful completion of appraisal wells in the Benguela and Belize Fields in
Block 14, options for the development of these areas are under study. The
company also began production from the Banzala Field, in the Block 0 concession
adjacent to Block 14. These developments help move Chevron closer to meeting its
objective of boosting production from its Angolan operations to 600,000 barrels
per day by 2002 from a 1999 year-end level of 460,000 barrels per day.
Nigeria
The company added 85 million barrels of proved oil-equivalent reserves in
Nigeria during 1999. Operationally, Chevron is taking an active role to
eliminate flaring of natural gas from production facilities in Nigeria,
mitigating the environmental effects and monetizing the extracted resource.
Chevron was named Managing Sponsor of the West African Gas Pipeline, a joint
venture among six energy companies to develop a 600-mile pipeline that runs from
gas producing and processing facilities in Nigeria to Ghana, Benin and Togo.
Also, an agreement was signed with Sasol Synfuels International to create a new
global joint venture for gas-to-liquids (GTL) technology. Preliminary design and
engineering continue for a GTL facility in Nigeria that will convert natural gas
into synthetic liquid fuels for further processing into commercial products.
Deepwater Gulf of Mexico
Chevron began producing from its first two deepwater projects in the Gulf of
Mexico - Genesis and Gemini. Gross oil-equivalent production from Genesis,
operated and 57 percent-owned by Chevron, reached 47,000 barrels per day by
year-end. Gross oil-equivalent production from the 40 percent-owned Gemini
project reached 35,000 barrels per day. Evaluation of options is under way to
develop a third Gulf of Mexico deepwater project, Typhoon. Chevron is the
operator and 50 percent owner of Typhoon.
Caspian Sea Region
Gross liquids production by Tengizchevroil (TCO), 45 percent-owned by Chevron,
averaged 214,000 barrels per day in 1999, an increase of 14 percent over 1998
average production. While expanding production, TCO's employees surpassed 6
million work hours without a lost-time injury. Chevron's approximate share of
proved oil-equivalent reserves added in 1999 for the Tengiz and Korolev fields
was 230 million barrels. Construction of a pipeline by the Caspian Pipeline
Consortium (CPC) continues on schedule. CPC shareholders approved a $1.3 billion
budget and work plan for 2000 and began awarding construction contracts. The
pipeline, 15 percent owned by Chevron, will deliver crude oil from the Tengiz
Field in Kazakhstan to the Black Sea port of Novorossiysk and is scheduled for
start-up in mid-2001. The additional export capacity provided by this pipeline
is important for planned future expansions at TCO to permit production to reach
a production goal of 700,000 barrels per day by 2010.
Canada
During 1999, a significant natural gas discovery was made northwest of Fort
Liard, Northwest Territories, Canada. Plans are being developed for the
construction of production and transportation facilities and additional wells to
permit first production by May 2000. A second successful well was completed in
January 2000 and is expected to begin producing in the fourth quarter 2000.
Chevron is the operator and has a 43 percent interest in both discoveries. In
Alberta, Canada, Chevron acquired a 20 percent interest in the Athabasca Oil
Sands Project. Completion of construction and start-up of the project is planned
for late 2002 and represents a long-term earnings growth opportunity with
expected gross production of 155,000 barrels per day. Production from the
Hibernia Field, in which Chevron holds a 27 percent interest, averaged
approximately 100,000 barrels per day in 1999, up from 65,000 barrels per day in
1998. Rates up to 150,000 barrels per day were achieved during the latter part
of the year. Development drilling in the Hibernia reservoir continued in 1999.
Chemicals
In February 2000, Chevron and Phillips Petroleum Company signed a letter of
intent and exclusivity agreement to combine most of their chemicals businesses
in a joint venture. Chevron will retain its Oronite Additives business. Each
company will own 50 percent of the joint venture, which would have had 1999
sales of about $6 billion and will have assets of more than $6 billion. The
combination is subject to final approval by the companies' boards of directors,
signing of definitive agreements and regulatory review, which are expected to be
completed by mid-2000.
Dynegy
On February 1, 2000, Chevron's affiliate, Dynegy Inc., merged with Illinova
Corporation, an energy services holding company in Illinois. Chevron invested an
additional $200 million to maintain its approximately 28 percent ownership in
the merged company. The merger will accelerate Dynegy's growth in the power
generation and marketing business.
e-Business
During 1999, the company implemented a new growth initiative aimed at developing
business opportunities capitalizing on Internet technology. In February 2000,
Chevron and Ariba Inc. formed Petrocosm Marketplace, a global, independent
Internet business-to-business marketplace to be owned by buyers and suppliers
across the energy industry. Also in February, Chevron entered into a joint
venture - Upstreaminfo.com - with Electronic Data Systems and others that will
allow the sale of information such as seismic data between companies and help
these energy businesses to recapture their costs in data collection and storage.
New Technology Ventures
Chevron established a technology ventures unit during 1999. The company plans to
make equity investments in a broad portfolio of emerging technology companies
with expertise in information technology, materials sciences and biotechnology.
These investments will be directed toward areas where the company could
potentially be a customer of the new ventures.
YEAR 2000 ISSUE
The Year 2000 issue was the result of computer systems and equipment with
embedded chips potentially being unable to process certain data accurately
before, during or after 2000. Chevron established a corporate-level Year 2000
project team in 1998 to coordinate the company's efforts to address the issue.
To date, the company and its
FS-3
major affiliates have experienced no significant disruptions in their operations
as a result of this matter. The company used both internal and external
resources in its Year 2000 efforts. The cumulative cost for the company and its
affiliates to achieve Year 2000 compliance is estimated at $170 million,
substantially all of which had been spent by year-end 1999. While the company
believes that it has addressed all material issues that could arise as a result
of the Year 2000 issue, other factors, such as the effect of Year 2000 problems
on third-party partners and suppliers could cause the actual effects of Year
2000 problems to be different from the company's current assessment. Such
factors could arise in 2000 or later. Year 2000 contingency plans have been
incorporated into the company's existing contingency plans to respond to
equipment failures, emergencies and business interruptions.
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
myriad laws and regulations pertaining to company operations and products are
embedded in the normal costs of doing business.
Using definitions and guidelines established by the American Petroleum
Institute, Chevron estimates its worldwide environmental spending in 1999 at
$882 million for its consolidated companies. Included in these expenditures were
$183 million of environmental capital expenditures and $699 million of costs
associated with the control and abatement of hazardous substances and pollutants
from ongoing operations. For 2000, total worldwide environmental capital
expenditures are estimated at $178 million. These capital costs are in addition
to the ongoing costs of complying with environmental regulations and the costs
to remediate previously contaminated sites.
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. The most significant of the company's
previously owned sites is the Port Arthur, Texas, refinery, where the company
retained certain environmental cleanup obligations when it sold the refinery in
1995. Anticipated costs were accrued at the time of sale, and those reserves
remain adequate. 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.
The following table displays the year-end balances and yearly changes to the
company's before-tax environmental remediation reserves, including those for
Superfund sites. For 1999, the company recorded additional provisions for
estimated remediation costs at refined products marketing sites, refineries,
chemical manufacturing facilities and previously sold oil and gas producing
properties.
Millions of dollars 1999 1998 1997
- -------------------------------------------------------------
Balance at January 1 $ 826 $ 987 $1,135
Expense Provisions 219 73 57
Expenditures (231) (234) (205)
- -------------------------------------------------------------
Balance at December 31 $ 814 $ 826 $ 987
=============================================================
Under provisions of the Superfund law, the Environmental Protection Agency (EPA)
has designated Chevron a potentially responsible party, or has otherwise
involved it, in the remediation of 307 hazardous waste sites. The company has
made expense provisions or payments in 1999 and prior years for 229 of these
sites. No single site is currently 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 Corporation to assume other 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 1999, 1998 and 1997 for Superfund sites were $33 million, $44
million and $52 million, respectively.
It is likely that the company will continue to incur additional liabilities,
beyond those recorded, for environmental remediation relating to past
operations. Future costs of these liabilities 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 expenditures
have had, or will have, any significant impact on the company's competitive
position relative to other domestic or international petroleum or chemicals
concerns.
In addition to the reserves for environmental remediation discussed previously,
the company maintains 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 as the properties are
produced. The amount of these reserves at year-end 1999 was $1.5 billion and is
included in accumulated depreciation, depletion and amortization on the
company's consolidated balance sheet. For the company's other operating assets,
such as refineries and chemical 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.
FS-4
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. On March 29, 2000,
the U. S. Court of Appeals for the Federal Circuit upheld a trial court's
decision that Unocal's patent is valid. The company will evaluate the decision
by the Court of Appeals and assess legal alternatives, but it expects to seek
further review of these rulings in the appropriate courts. If Unocal's patent
ultimately is upheld, the company's financial exposure includes royalties, plus
interest, for production of gasoline that is ruled to have infringed the patent.
As a result of the March 2000 ruling, the company expects to record an after-tax
charge in the first quarter 2000 of approximately $75 million for the four-year
period ending March 31, 2000. The majority of this charge pertains to gasoline
production in the earlier part of this period, before the company modified its
manufacturing processes to minimize the manufacture of the patented
formulations. Unocal has also obtained additional patents for alternate
formulations that could affect a larger share of U.S. gasoline production. We
believe 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.
In December 1999, Chevron paid OXY U.S.A. Inc. $775 million to settle the
long-standing lawsuit brought in 1982 by Cities Service Co. (later acquired by
OXY) against Gulf Oil Corporation (later acquired by Chevron). At year-end 1998,
Chevron had accrued a loss provision of $924 million. The provision exceeded the
settlement amount, and as a result, the company recognized $104 million in
additional net income ($149 million before tax) in 1999.
Along with other oil companies, the company is a party to numerous lawsuits and
claims - including actions challenging oil and gas royalty and severance tax
payments based on posted prices, and actions related to the use of the chemical
MTBE in certain oxygenated gasolines. In some of these matters, plaintiffs may
seek to recover large and sometimes unspecified amounts. In others, the
plaintiffs 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 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.
Higher-than-expected investment returns on pension plan trust assets over the
past few years have moderated U.S. pension expense and have extended the fully
funded status of the company's main U.S. pension plan. These effects may not
occur on a sustained basis in the future if investment returns on pension plan
assets decline.
In June 1997, Caltex Corporation received a claim from the U.S. Internal Revenue
Service (IRS) for $292 million in excise taxes, $140 million in penalties and
$1.6 billion in interest. The IRS claim related to crude oil sales to Japanese
customers beginning in 1980. To settle this claim, in December 1999, Caltex paid
tax and interest of $65 million less a payment of $12 million previously made to
the IRS.
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 related operations and
results, and are carefully considered by management when evaluating the level of
current and future activity in such countries.
Chevron and its affiliates continue to review and analyze their operations and
may close, sell, exchange, purchase or restructure assets to achieve operational
or strategic benefits 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 may result in significant losses or gains in future periods.
FINANCIAL INSTRUMENTS
The company utilizes various derivative instruments 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 are
relatively straightforward, involve little complexity and generally, are of a
short-term duration. Most of the activity in these instruments is intended to
hedge a physical transaction; hence, gains and losses arising from these
instruments offset and are recognized in income concurrently with the
recognition of the underlying physical transactions in income. 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. The results of operations and
financial position of certain equity affiliates may, however, be affected by
their business activities involving the use of derivative instruments.
NEW ACCOUNTING STANDARDS
In June 1998, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities," which, as amended by SFAS No. 137,
"Accounting for Derivative Instruments and Hedging Activities - Deferral of the
Effective Date of FASB Statement No. 133," is to be implemented on or before
January 1, 2001. The basic rules of the new standard require that all derivative
instruments be recognized on the balance sheet at their fair values. For hedging
activities, changes in fair value are accounted for in accordance with the
underlying hedged item. Thus, some hedging gains or losses appear in income,
offsetting gains or losses stemming from the underlying exposure. In other
instances, hedging gains or losses are reported in other comprehensive income (a
component of stockholders' equity) until the underlying exposure is recognized
in net income. These rules may be applied on a transaction-by-transaction basis.
For all nonhedging derivative activity, gains or losses are recognized currently
in income. The company will implement SFAS No. 133 on January 1, 2001. As
Chevron's activity in this area is minor and the derivative instruments used are
relatively straightforward
FS-5
involving little complexity, the company does not expect the new standard to
have a significant effect on its earnings in any given period.
EMPLOYEE STAFF REDUCTIONS AND RESTRUCTURINGS
During the second quarter of 1999, Chevron began implementing a staff reduction
program and other restructuring activities across the company. While the
programs affect the activities of all the company's business segments, most of
the net costs and future savings relate to the termination and relocation of
U.S.-based employees.
Restructuring costs of $183 million were reflected in 1999 net income, including
estimated termination benefits for 3,472 employees. These restructuring costs
included accrued employee termination benefits, restructuring-related pension
settlement gains and other items. Also included is $25 million for Chevron's
share of restructuring charges recorded by its Caltex affiliate. The net-income
effect of these costs and the estimated number of employees (excluding Caltex
employees) to be separated are presented by business segment in the following
table.
Net Expense Number of
Millions of dollars After Tax Employees
- -----------------------------------------------------------------------
United States Exploration
and Production $ 42 772
International Exploration
and Production 21 489
United States Refining, Marketing
and Transportation 35 855
International Refining, Marketing
and Transportation 31 127
Worldwide Chemicals 22 390
All Other 32 839
- ------------------------------------------------------------------------
Total $183 3,472
========================================================================
The staff reductions will be completed by mid-2000. At December 31, 1999,
termination payments had been made to 2,157 employees.
RESULTS OF OPERATIONS
Sales and other operating revenues were $35.4 billion in 1999, compared with
$29.9 billion in 1998 and $40.6 billion in 1997. Revenues for 1999 increased
primarily on sharply higher prices for crude oil and refined products. In 1998,
revenues were down from 1997 levels, primarily due to lower crude oil, natural
gas and refined products prices; lower U.S. natural gas production; and the
company's 1997 exit from the U.K. refining and marketing business.
Purchased crude oil and products costs in 1999 were 28 percent higher than in
1998 because of higher prices for crude oil, natural gas, refined products and
chemicals feedstock. However, such costs were 11 percent lower than in 1997
because prices fell precipitously in 1998 and did not begin to recover until the
second quarter of 1999.
Other income totaled $612 million in 1999, $386 million in 1998 and $679 million
in 1997. Changes in net gains from the disposition of assets and changes in
interest income caused the fluctuations between years.
Operating, selling, general and administrative expenses, excluding the effects
of special items, declined to $6,170 million, from $6,251 million in 1998 and
$6,549 million in 1997. Approximately $200 million of the 1998 decline resulted
from the company's exit from the U.K. downstream business.
Millions of dollars 1999 1998 1997
- --------------------------------------------------------------------------------
Operating Expenses ......................... $5,090 $4,834 $5,280
Selling, General and
Administrative Expenses ........... 1,404 2,239 1,533
- --------------------------------------------------------------------------------
Total Operating Expenses .......... 6,494 7,073 6,813
Less: Special Charges, Before Tax .......... 324 822 264
- --------------------------------------------------------------------------------
Adjusted Total Operating Expenses .......... $6,170 $6,251 $6,549
================================================================================
Depreciation, depletion and amortization expenses increased to $2,866 million
from $2,320 million in 1998 and $2,300 million in 1997 due in part to asset
impairments. Depreciation expense associated with asset impairments in 1999 was
$394 million, compared with about $100 million in 1998 and 1997. Increased
production of crude oil and natural gas in 1999 resulted in higher depreciation
expense of about $150 million in the company's worldwide upstream operations.
Income tax expenses were $1,578 million in 1999, $495 million in 1998 and $2,246
million in 1997, reflecting effective income tax rates of 43 percent, 27 percent
and 41 percent for each of the three years, respectively. The increase in the
1999 effective tax rate reflects a higher proportion of earnings from
international operations that are 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 slightly offset by the effect of lower
taxes on taxable income received from equity affiliates in 1999.
The lower effective tax rate in 1998, compared with 1997, primarily reflects
favorable prior-period tax adjustments; favorable adjustments associated with
the finalization of the company's 1997 tax returns, higher tax-related credits
connected with the utilization of capital loss benefits and a shift in the
international earnings mix to lower-tax-rate countries.
FS-6
Foreign currency losses decreased net income $38 million in 1999 and $47 million
in 1998, while gains increased net income $246 million in 1997. These amounts
include the company's share of affiliates' foreign currency gains or losses. In
1999, the company's foreign currency losses occurred primarily in the company's
operations in Canada and Australia and in the Australian operations of Caltex.
The most significant losses in 1998 were in Caltex's operations in Korea,
Thailand and Japan. The foreign currency gains for 1997 occurred in Australia
and in the Asian operating areas of Caltex, where, generally, the currencies
weakened against the U.S. dollar.
SELECTED OPERATING DATA 1999 1998 1997
- ------------------------------------------------------------------------
U.S. EXPLORATION AND PRODUCTION
Net Crude Oil and Natural Gas
Liquids Production (MBPD) ...... 316 325 343
Net Natural Gas
Production (MMCFPD) ............ 1,639 1,739 1,849
Natural Gas Sales (MMCFPD)(1)............ 3,162 3,303 3,400
Natural Gas Liquids Sales (MBPD)(1)...... 133 130 133
Revenues from Net Production
Crude Oil ($/Bbl) ............. $16.11 $11.42 $17.68
Natural Gas ($/MCF) ............ $ 2.16 $ 2.02 $ 2.42
INTERNATIONAL EXPLORATION
AND PRODUCTION(1)
Net Crude Oil and Natural Gas
Liquids Production (MBPD) ...... 811 782 731
Net Natural Gas
Production (MMCFPD) ............ 874 654 576
Natural Gas Sales (MMCFPD) .............. 1,774 1,504 1,209
Natural Gas Liquids Sales (MBPD) ........ 57 53 69
Revenues from Liftings
Liquids ($/Bbl) ................ $17.31 $11.77 $17.97
Natural Gas ($/MCF) ............ $ 1.87 $ 1.94 $ 2.10
Other Produced Volumes (MBPD)(2)......... 96 95 82
U.S. REFINING AND MARKETING
Gasoline Sales (MBPD) ................... 667 653 591
Other Refined Products Sales (MBPD) ..... 635 590 602
Refinery Input (MBPD) ................... 955 869 933
Average Refined Products
Sales Price ($/Bbl) ............ $26.86 $22.37 $28.93
INTERNATIONAL REFINING
AND MARKETING(1)
Refined Products Sales (MBPD)(3)......... 892 798 886
Refinery Input (MBPD) ................... 469 475 565
CHEMICALS SALES AND OTHER
OPERATING REVENUES(4)
United States ........................... $2,958 $2,591 $3,046
International ........................... 779 625 600
- ------------------------------------------------------------------------
Worldwide ............................... $3,737 $3,216 $3,646
========================================================================
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.
(3)1998 restated to conform to 1999 presentation.
(4)Millions of dollars. Includes sales to other Chevron companies.
U.S. exploration and production earnings in 1999, excluding special items, more
than doubled 1998 earnings, but declined 16 percent from 1997 levels. These
changes largely tracked changes in crude oil prices. Higher gains from assets
sales and lower exploration expenses each year helped offset declines in
production of liquids and natural gas. The effect on net income from special
items for the years 1997 through 1999 is shown in the following table.
U.S. Exploration and Production
Millions of dollars 1999 1998 1997
- -------------------------------------------------------------------------------
Earnings, Excluding Special Items ......... $ 818 $ 381 $ 972
- -------------------------------------------------------------------------------
Asset Write-Offs and Revaluations ......... (204) (44) (68)
Asset Dispositions ........................ 3 47 190
Environmental Remediation Provisions ...... (23) 26 (6)
Restructurings and Reorganizations ........ (42) - (60)
Other ..................................... (26) (45) (27)
- -------------------------------------------------------------------------------
Total Special Items ....................... (292) (16) 29
- -------------------------------------------------------------------------------
Net Income ................................ $ 526 $ 365 $ 1,001
===============================================================================
The company's average 1999 U.S. crude oil realizations of $16.11 per barrel were
$4.69 higher than 1998 but $1.57 lower than 1997. Average 1999 U.S. natural gas
prices were $2.16 per thousand cubic feet, 14 cents higher than 1998 but 26
cents lower than 1997.
Net liquids production for the year averaged 316,000 barrels per day, down 3
percent from 1998 and down 8 percent from 1997. Net natural gas production in
1999 averaged 1.639 billion cubic feet per day, down 6 percent from 1998 and 11
percent from 1997. The decline in oil-equivalent production reflects normal
field declines and asset sales, partially offset by new production in the
Gulf of Mexico. Production in 1998 was also adversely affected by a number of
storms in the Gulf of Mexico, including Hurricane Georges.
International exploration and production earnings, excluding special items, in
1999 increased 61 percent from 1998 earnings, but were down 3 percent from 1997
levels. As in the U.S. upstream segment, these changes in earnings largely
reflected the swings in crude oil prices. While 1999 average crude oil prices
did not return to 1997 levels, production has grown each year.
The effect on net income from special items for the years 1997 through 1999 is
shown in the following table.
International Exploration and Production
Millions of dollars 1999 1998 1997
- -------------------------------------------------------------------------------
Earnings, Excluding Special Items ...... $ 1,156 $ 717 $ 1,197
- -------------------------------------------------------------------------------
Asset Write-Offs and Revaluations ...... (37) (6) -
Asset Dispositions ..................... 17 (56) 50
Prior-Year Tax Adjustments ............. (23) 56 10
Restructurings and Reorganizations ..... (21) - -
Other .................................. 1 (4) (5)
- -------------------------------------------------------------------------------
Total Special Items .................... (63) (10) 55
- -------------------------------------------------------------------------------
Net Income ............................. $ 1,093 $ 707 $ 1,252
===============================================================================
Chevron's average liquids realizations, including equity affiliates, were $17.31
per barrel in 1999, compared with $11.77 per barrel in 1998 and $17.97 per
barrel in 1997. Average natural gas realizations fell to $1.87 per thousand
cubic feet in 1999, compared with $1.94 in 1998 and $2.10 in 1997.
FS-7
In 1999, net liquids production of 811,000 barrels per day increased 4 percent
from 1998 and 11 percent from 1997. In 1999, production increases in Angola and
Kazakhstan, combined with production from properties acquired during the year in
Argentina and Thailand, offset declines in Australia, Indonesia and Nigeria. In
1998, operations in Kazakhstan, offshore eastern Canada, Indonesia, Angola and
Congo were the principal sources of production increases from 1997.
Net natural gas production of 874 million cubic feet in 1999 was up 34 percent
and 52 percent from 1998 and 1997, respectively. Increases in 1999 were from the
United Kingdom, as well as from production from the properties acquired in
Thailand and Argentina. In 1998, production rose in Indonesia and Nigeria as
well as in the United Kingdom upon the start-up of the Britannia Field.
For 10 consecutive years, international production and proved reserves
increased, reflecting the company's strategy of expanding its international
upstream operations. In 1999, OEG production increased by 7 percent, and at
year-end 1999 OEG proved reserves were higher than year-end 1998 by 6 percent.
The company replaced 169 percent of 1999 OEG production during the year,
including sales and acquisitions.
U.S. refining, marketing and transportation earnings, excluding special items,
declined in 1999 to $375 million after strong earnings in 1998 and 1997 of $633
million and $662 million, respectively. Earnings for 1999 suffered from
compressed margins, as higher raw materials costs outpaced increases in refined
products sales realizations. Operating incidents at the Richmond, California,
refinery also contributed to the lower results. These effects were offset
partially by increases in refined products sales volumes and proceeds from
business interruption insurance.
For 1998, declines in refined products margins and the adverse effects of storms
in the Gulf of Mexico were offset primarily by decreases in operating expenses
and increases in refined products sales volumes. Also included in 1998 results
were proceeds from a partial payment of business interruption insurance as well
as adjustments to prior years' taxes.
The effect on net income from special items for the years 1997 through 1999 is
shown in the following table.
U.S. Refining and Marketing
Millions of dollars 1999 1998 1997
- -------------------------------------------------------------------------------
Earnings, Excluding Special Items ........... $ 375 $633 $ 662
- -------------------------------------------------------------------------------
Asset Write-Offs and Revaluations ........... - (22) -
Asset Dispositions .......................... 75 - (18)
Environmental Remediation ................... (71) (39) (12)
Restructuring and Reorganizations ........... (35) - -
LIFO Inventory Gains ........................ 13 - -
Other ....................................... - - (31)
- -------------------------------------------------------------------------------
Total Special Items ......................... (18) (61) (61)
- -------------------------------------------------------------------------------
Net Income .................................. $ 357 $572 $ 601
===============================================================================
Refined products sales volumes of 1.302 million barrels per day in 1999
increased 5 percent over 1998 and 9 percent from 1997. The sales increases in
1999 reflected higher gasoline sales volumes, including branded gasoline sales
of 545,000 BPD, which increased 5 percent from the 1998 level and 10 percent
from 1997.
For 1999, U.S. refined products sales realizations were $26.86 per barrel, up 20
percent from 1998 but 7 percent lower than in 1997.
International refining, marketing and transportation earnings include results of
the consolidated refining and marketing subsidiaries, international marine
operations and equity earnings of Caltex. Excluding special items, 1999 earnings
of $49 million were down from $123 million in 1998 and $367 million in 1997.
Foreign currency losses were $21 million in 1999, compared with losses of $69
million in 1998 and gains of $169 million in 1997. The effect on net income from
special items for the years 1997 through 1999 is shown in the following table.
International Refining, Marketing and Transportation
Millions of dollars 1999 1998 1997
- -------------------------------------------------------------------------------
Earnings, Excluding Special Items ............ $ 49 $ 123 $ 367
- -------------------------------------------------------------------------------
Asset Dispositions ........................... (31) - (72)
Prior-Year Tax Adjustments .................. 60 - -
Environmental Remediation Provisions ......... - (11) -
Restructurings and Reorganizations .......... (31) (43) -
LIFO Inventory Gains (Losses) ................ 27 (16) 6
Other ........................................ - (25) (3)
- -------------------------------------------------------------------------------
Total Special Items .......................... 25 (95) (69)
- -------------------------------------------------------------------------------
Net Income ................................... $ 74 $ 28 $ 298
===============================================================================
The Caltex contribution to segment results for the years 1997 through 1999 is
shown in the table below.
Caltex
Millions of dollars 1999 1998 1997
- -------------------------------------------------------------------------------
Net Income (Loss) .................................. $ 56 $ (36) $ 252
Less:
Special Items ............................. 30 (82) 5
Foreign Currency (Losses) Gains ........... (15) (68) 177
LCM* Inventory Adjustments and Other ...... 76 (43) (50)
- -------------------------------------------------------------------------------
Adjusted (Loss) Earnings ........................... $ (35) $ 157 $ 120
===============================================================================
*Lower of cost or market
On an adjusted basis, Caltex earnings declined in 1999 due to weak sales margins
in most of its areas of operations, as competitive pressures prevented refined
products sales realizations from rising sufficiently to recover higher crude oil
costs. Sales realizations in 1998 did not decline as fast as raw material costs,
resulting in higher sales margins and adjusted earnings when compared with 1997.
Total international refined products sales volumes in 1999 were 892,000 barrels
per day, increasing from 798,000 in 1998 and 886,000 in 1997.
Higher Caltex sales volumes were primarily responsible for the increase. Sales
volumes in 1998 were lower than 1997 as a result of Chevron's withdrawal from
the refining and marketing business in the United Kingdom in late 1997.
Excluding the 1997 volumes from the discontinued U.K. business, refined products
sales volumes were essentially flat between 1998 and 1997.
Chemicals earnings, excluding special items, rose 36 percent in 1999 to $205
million but did not reach the $224 million recorded in 1997. Earnings in 1999
benefited from improved sales margins for major products, higher sales vol-
FS-8
umes and lower operating expenses. The 1998 results were affected adversely by
plant shutdowns for expansions and storm damage repairs. Earnings in 2000 remain
under pressure from industry overcapacity. However, the company's sales volumes
grew in 1999, increasing 10 percent over 1998 and 20 percent from 1997 levels.
The effect on net income from special items for the years 1997 through 1999 is
shown in the following table.
Chemicals
Millions of dollars 1999 1998 1997
- -------------------------------------------------------------------------------
Earnings, Excluding Special Items ............. $ 205 $ 151 $ 224
- -------------------------------------------------------------------------------
Asset Write-Offs and Revaluations ............. (43) (19) (10)
Asset Dispositions ............................ - - 33
Environmental Remediation Provisions .......... (28) (5) (9)
Restructurings and Reorganizations ............ (22) - -
LIFO Inventory Losses ......................... (3) (5) (1)
Other ......................................... - - (9)
- -------------------------------------------------------------------------------
Total Special Items ........................... (96) (29) 4
- -------------------------------------------------------------------------------
Net Income .................................... $ 109 $ 122 $ 228
===============================================================================
All Other activities include coal operations, interest expense, interest income
on cash and marketable securities, real estate and insurance activities, and
corporate center costs. All Other net charges, excluding special items, were
$317 million in 1999, compared with $60 million and $242 million in 1998 and
1997, respectively.
The effect on net charges from special items for the years 1997 through 1999 is
shown in the following table.
All Other
Millions of dollars 1999 1998 1997
- -------------------------------------------------------------------------------
Net Charges, Excluding Special Items ......... $(317) $ (60) $(242)
- -------------------------------------------------------------------------------
Asset Write-Offs and Revaluations ............ (62) (68) (8)
Asset Dispositions ........................... 147 - -
Environmental Remediation Provisions ......... (1) (10) (8)
Prior-Year Tax Adjustments ................... 72 215 142
Restructurings and Reorganizations .......... (32) - -
Cities Service Litigation .................... 104 (629) -
Other ........................................ - 97 (8)
- -------------------------------------------------------------------------------
Total Special Items .......................... 228 (395) 118
- -------------------------------------------------------------------------------
Net Charges .................................. $ (89) $(455) $(124)
===============================================================================
Net income, excluding special items, for the company's coal operations was $34
million in 1999, compared with $77 million in 1998 and $41 million in 1997. Net
income for 1999 included net special benefits of $26 million. Lower 1999 results
were due primarily to the absence of earnings from an affiliate sold in the
first quarter, lower sales tonnage and sales prices for the remaining coal
business, and adjustments during the year to the carrying value of these
remaining operations that were under active negotiation for sale. Late in 1999,
as a result of unsuccessful negotiations to sell the company's coal operations,
final adjustments were made to reduce the net carrying value of the assets,
which are no longer held for sale. Earnings in 1998, in contrast with 1999 and
1997, benefited from the suspension of depreciation expense for part of the year
while the held-for-sale assets were actively being marketed to prospective
buyers.
Net charges, excluding special items, for the balance of the All Other segment
were $351 million in 1999, $137 million in 1998 and $283 million in 1997. Higher
interest expense, lower interest income, and fewer favorable state and federal
income tax adjustments were the primary causes of the higher level of charges in
1999 compared with 1998. Included in the 1998 earnings were net incremental
benefits totaling approximately $80 million, consisting primarily of tax-related
credits, which were connected with the utilization of capital loss benefits, and
the receipt of proceeds from favorable insurance settlements. Net charges for
1998 also included more favorable tax-related adjustments than in 1997.
Partially offsetting these 1998 items were higher interest expenses on increased
debt levels and lower interest income.
LIQUIDITY AND CAPITAL RESOURCES
Cash, cash equivalents and marketable securities totaled $2.032 billion at
year-end 1999, up 44 percent from $1.413 billion at year-end 1998. Cash provided
by operating activities in 1999 was $4.481 billion, compared with $3.731 billion
in 1998 and $4.880 billion in 1997. Cash provided by operating activities in
1999 benefited from the environment of rising crude oil prices and the resulting
impact on the company's earnings, but was not totally sufficient to fund the
company's total cash needs. As a result, the company increased its borrowings in
1999 by about $1.4 billion to supplement cash received from operating activities
and proceeds from the sales of assets to provide the funds for acquisitions, its
capital expenditure program, dividend payments to stockholders, and the December
1999 payment of $775 million to Occidental Petroleum in settlement of the Cities
Service lawsuit. In 1998, cash provided by operating activities was not
sufficient to fund the company's investing activities and also resulted in
increased borrowings that year. In 1997, cash provided by operating activities
and asset sales exceeded the company's investment and dividend requirements, and
debt was reduced.
In October 1999, the company increased its quarterly dividend from 61 cents to
65 cents per share. For the full year, Chevron paid dividends of $2.48 per
share, compared with $2.44 per share in 1998 - the 12th consecutive year of
dividend increases. In January 2000, the company declared a quarterly dividend
of 65 cents a share on its common stock.
The company's total debt and capital lease obligations were $8.919 billion at
December 31, 1999, an increase of 18 percent from $7.558 billion at year-end
1998. In 1999, the company's Employee Stock Ownership Plan (ESOP) borrowed a
total of $645 million at an average interest rate of 7.4 percent, guaranteed by
Chevron Corporation. Debt proceeds of $620 million were paid to Chevron
Corporation in exchange for Chevron's assumption of the existing 8.11 percent
ESOP debt of $620 million. In October 1999, the company issued $500 million of
new 6.625 percent notes. Chevron used the proceeds from the new debt to reduce
short-term debt, primarily commercial paper. Other additions to long-term debt
and capital lease obligations in 1999, excluding debt assumed in acquisitions
and guarantees of ESOP debt, totaled about $200 million. The additions to
long-term debt in 1999 were partially offset by repayments of existing long-term
debt and capital lease obligations of $163 million, repayments of debt assumed
in acquisitions of $386 million and a scheduled $70 million noncash retirement
of 8.11 percent ESOP debt. There were also net additions of $219 million in
short-term debt,
FS-9
primarily commercial paper, excluding debt assumed in acquisitions and new
guarantees of ESOP debt.
On December 31, 1999, Chevron had $4.750 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 1999. 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. This is an increase of $1.5 billion from 1998 following a
new $2 billion shelf registration in 1999 and the 1999 issuance of $500 million
in new long-term debt under an existing shelf registration.
The company's short-term debt, consisting primarily of commercial paper and the
current portion of long-term debt, totaled $6.159 billion at December 31, 1999.
Of the total short-term debt, $2.725 billion was reclassified to long-term debt
at year-end 1999 because settlement of these obligations is not expected to
require the use of working capital in 2000, 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.
The company's future debt level is dependent primarily on cash provided by
operations and its capital spending program. The company believes it has
substantial borrowing capacity to meet unanticipated cash requirements. The
company's senior debt is rated AA by Standard & Poor's Corporation and Aa2 by
Moody's Investors Service. Chevron's U.S. commercial paper is rated A-1+ by
Standard & Poor's and Prime-1 by Moody's. Chevron's Canadian commercial paper is
rated R-1 (middle) by Dominion Bond Rating Service. Moody's counterparty rating
for Chevron is also Aa2. All of these ratings denote high-quality,
investment-grade securities.
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. Through March 24, 2000, the company had purchased 10.7
million shares at a cost of $826 million under the program.
FINANCIAL RATIOS
The current ratio is the ratio of current assets to current liabilities at
year-end. Two items negatively affected 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, that at year-end 1999 were lower
than current costs, based on average acquisition costs for the year, by $871
million. Also, the company continually refinances its commercial paper. At
year-end 1999, approximately $2.066 billion of commercial paper, after excluding
$2.725 billion reclassified to long-term debt, was classified as a current
liability, although it is likely to remain outstanding indefinitely. The company
benefits from lower interest rates available on short-term debt; however,
Chevron's proportionately large amount of short-term debt keeps its ratio of
current assets to current liabilities at a relatively low level.
Financial Ratios
1999 1998 1997
- ------------------------------------------------------------
Current Ratio 0.9 0.9 1.0
Interest Coverage Ratio 8.2 5.1 14.3
Total Debt/Total Debt Plus Equity 33.4% 30.7% 25.8%
============================================================
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 1999 due to higher before-tax income, despite higher interest
expense. The company's debt ratio (total debt/total debt plus equity) increased
in 1999, as the increase in total debt was proportionately higher than the
increase in stockholders' equity.
CAPITAL AND EXPLORATORY EXPENDITURES
Worldwide capital and exploratory expenditures for 1999 totaled $6.133 billion,
including the company's equity share of affiliates' expenditures. Capital and
exploratory expenditures were $5.314 billion in 1998 and $5.541 billion in 1997.
Expenditures for exploration and production, including those associated with the
company's Dynegy affiliate, accounted for 75 percent of total outlays in 1999,
compared with 61 percent in 1998 and 65 percent in 1997. International
exploration and production spending was 78 percent of worldwide exploration and
production expenditures in 1999, compared with 60 percent in 1998 and 54 percent
in 1997, reflecting the company's continuing focus on international exploration
and production activities. Additionally, 1999 expenditures included two
significant acquisitions in international exploration and production areas -
the Rutherford-Moran Oil Corporation and Petrolera Argentina San Jorge S.A. The
company's other segments had lower expenditures in 1999 than in 1998, as the
company reduced spending to fund its international exploration and production
activities.
The company estimates capital and exploratory expenditures for 2000 at $5.2
billion, including Chevron's share of spending by affiliates. This is down about
15 percent from 1999 spending levels, reflecting the absence of the two
significant 1999 acquisitions. The 2000 program provides $3.6 billion for
exploration and production investments, of which about 64 percent is for
international projects. Major areas of emphasis for exploration and production
are Kazakhstan, West Africa, Thailand, Canada and the deep waters of the Gulf of
Mexico. U.S. exploration and production estimates include $390 million for the
company's increased investment in Dynegy and Dynegy's expenditures for the year.
Successful implementation of the planned expenditure program for 2000 will
depend upon many factors, including the ability of our partners in many of these
projects, some of which are national petroleum companies of producing countries,
to fund their shares of project expenditures.
Transportation expenditures are estimated at about $420 million. Most of this
will be in the Caspian Sea region, where the Caspian Pipeline Consortium is
constructing a pipeline. Refining and marketing expenditures are estimated at
about $830 million, with $530 million of that planned for projects in the United
States, most of which will be spent for marketing projects. Most of the
international downstream capital program
FS-10
will be invested by the company's Caltex affiliate. The company has tentative
plans to invest about $200 million in the worldwide chemicals business, down
about 57 percent from 1999 spending levels. This amount may change depending on
the timing of a successful formation of the proposed chemicals joint venture
with Phillips Petroleum Company.
Capital and Exploratory Expenditures
1999 1998 1997
------------------------- ------------------------- --------------------------
Inter- Inter- Inter-
Millions of dollars U.S. national Total U.S. national Total U.S. national Total
- -------------------------------------------------------------------------------------------------------------------
Exploration and Production $1,029 $3,591 $4,620 $1,320 $1,942 $3,262 $1,659 $ 1,956 $3,615
Refining, Marketing and
Transportation 522 412 934 654 431 1,085 520 602 1,122
Chemicals 326 136 462 385 359 744 470 194 664
All Other 117 - 117 223 - 223 140 - 140
- -------------------------------------------------------------------------------------------------------------------
Total $1,994 $4,139 $6,133 $2,582 $2,732 $5,314 $2,789 $ 2,752 $5,541
- -------------------------------------------------------------------------------------------------------------------
Total, Excluding Equity
in Affiliates $1,859 $3,492 $5,351 $2,460 $1,860 $4,320 $2,487 $ 1,880 $4,367
===================================================================================================================
QUARTERLY RESULTS AND STOCK MARKET DATA
Unaudited
1999 1998
Millions of dollars, except per-share amounts 4TH Q 3RD Q 2ND Q 1ST Q 4TH Q 3RD Q 2ND Q 1ST Q
- -----------------------------------------------------------------------------------------------------------------------------
REVENUES
Sales and other operating revenues(1) $10,611 $9,965 $ 8,473 $ 6,399 $ 7,164 $7,561 $ 7,754 $ 7,464
Income (loss) from equity affiliates ......... 122 127 133 144 (66) 13 155 126
Other income ................................. 246 85 135 146 184 104 60 38
- -----------------------------------------------------------------------------------------------------------------------------
TOTAL REVENUES ............................... 10,979 10,177 8,741 6,689 7,282 7,678 7,969 7,628
- -----------------------------------------------------------------------------------------------------------------------------
COSTS AND OTHER DEDUCTIONS
Purchased crude oil and products,
operating and other expenses ................ 7,307 7,006 6,275 4,426 5,978 5,100 5,314 5,195
Depreciation, depletion and amortization ..... 900 767 633 566 646 563 557 554
Taxes other than on income(1)................. 1,184 1,181 1,143 1,078 1,115 1,145 1,140 1,011
Interest and debt expense .................... 138 116 113 105 109 103 99 94
- -----------------------------------------------------------------------------------------------------------------------------
TOTAL COSTS AND OTHER DEDUCTIONS ............. 9,529 9,070 8,164 6,175 7,848 6,911 7,110 6,854
- -----------------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAX ..................... 1,450 1,107 577 514 (566) 767 859 774
INCOME TAX (CREDIT) EXPENSE .................. 641 525 227 185 (360) 306 282 267
- -----------------------------------------------------------------------------------------------------------------------------
NET INCOME (LOSS)(2) ......................... $ 809 $ 582 $ 350 $ 329 $ (206) $ 461 $ 577 $ 507
=============================================================================================================================
NET (LOSS) INCOME PER SHARE - BASIC .......... $1.24 $0.88 $0.54 $0.50 $(0.31) $ 0.70 $0.88 $ 0.78
- DILUTED ........ $1.23 $0.88 $0.53 $0.50 $(0.31) $ 0.70 $0.88 $ 0.77
=============================================================================================================================
DIVIDENDS PAID PER SHARE ..................... $0.65 $0.61 $0.61 $0.61 $ 0.61 $ 0.61 $0.61 $ 0.61
=============================================================================================================================
COMMON STOCK PRICE RANGE - HIGH ..............$96 15/16 $100 13/16 $104 15/16 $90 5/16 $89 7/16 $89 $86 13/16 $90 3/16
- LOW ..............$83 3/8 $85 9/16 $86 3/8 $73 1/8 $78 3/8 $73 $77 3/8 $67 3/4
=============================================================================================================================
(1)Includes consumer excise taxes: $ 989 $ 1,023 $ 986 $ 912 $ 943 $ 973 $ 988 $ 852
(2)Special (charges) credits included
in Net Income (Loss): $ (10) (120) $(134) $ 48 $ (709) $ 75 $ (43) $ 71
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 23, 2000, stockholders of record numbered
approximately 116,000.
There are no restrictions on the company's ability to pay dividends. Chevron has
made dividend payments to stockholders for 88 consecutive years.
FS-11
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 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/ Martin R. Klitten /s/ Stephen J. Crowe
- --------------------- --------------------- ----------------------
David J. O'Reilly Martin R. Klitten Stephen J. Crowe
Chairman of the Board Vice President Comptroller
and Chief Executive Officer and Chief Financial Officer
February 23, 2000
REPORT OF INDEPENDENT ACCOUNTANTS
TO THE STOCKHOLDERS
AND THE BOARD OF DIRECTORS OF CHEVRON CORPORATION
In our opinion, the accompanying consolidated balance sheet and the related
consolidated statements of income, comprehensive income, stockholders' equity
and cash flows present fairly, in all material respects, the financial position
of Chevron Corporation and its subsidiaries at December 31, 1999 and 1998, and
the results of their operations and their cash flows for each of the three years
in the period ended December 31, 1999, in conformity with accounting principles
generally accepted in the United States. 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, 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 the opinion expressed above.
/s/ PricewaterhouseCoopers LLP
- ------------------------------
San Francisco, California
February 23, 2000
FS-12
CONSOLIDATED STATEMENT OF INCOME
--------------------------------
Year ended December 31
-----------------------------
Millions of dollars, except per-share amounts 1999 1998 1997
- -----------------------------------------------------------------------------------
REVENUES
Sales and other operating revenues* ....... $35,448 $29,943 $40,596
Income from equity affiliates .............. 526 228 688
Other income ............................... 612 386 679
- -----------------------------------------------------------------------------------
TOTAL REVENUES ...................................... 36,586 30,557 41,963
- -----------------------------------------------------------------------------------
COSTS AND OTHER DEDUCTIONS
Purchased crude oil and products ........... 17,982 14,036 20,223
Operating expenses ......................... 5,090 4,834 5,280
Selling, general and administrative expenses 1,404 2,239 1,533
Exploration expenses ....................... 538 478 493
Depreciation, depletion and amortization ... 2,866 2,320 2,300
Taxes other than on income* ................ 4,586 4,411 6,320
Interest and debt expense .................. 472 405 312
- -----------------------------------------------------------------------------------
TOTAL COSTS AND OTHER DEDUCTIONS .................... 32,938 28,723 36,461
- -----------------------------------------------------------------------------------
INCOME BEFORE INCOME TAX EXPENSE .................... 3,648 1,834 5,502
INCOME TAX EXPENSE .................................. 1,578 495 2,246
===================================================================================
NET INCOME .......................................... $ 2,070 $ 1,339 $ 3,256
===================================================================================
NET INCOME PER SHARE OF COMMON STOCK - BASIC ........ $ 3.16 $ 2.05 $ 4.97
- DILUTED ...... $ 3.14 $ 2.04 $ 4.95
===================================================================================
*Includes consumer excise taxes: .................... $ 3,910 $ 3,756 $ 5,587
See accompanying notes to consolidated financial statements.
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
----------------------------------------------
Year ended December 31
--------------------------------
Millions of dollars ................................. 1999 1998 1997
- -------------------------------------------------------------------------------------
NET INCOME .......................................... $ 2,070 $ 1,339 $ 3,256
- -------------------------------------------------------------------------------------
Currency translation adjustment ............ (43) (1) (173)
Unrealized holding gain (loss) on securities 29 3 (4)
Minimum pension liability adjustment ....... (11) (15) 4
- -------------------------------------------------------------------------------------
OTHER COMPREHENSIVE INCOME, NET OF TAX .............. (25) (13) (173)
- -------------------------------------------------------------------------------------
COMPREHENSIVE INCOME ................................ $ 2,045 $ 1,326 $ 3,083
=====================================================================================
See accompanying notes to consolidated financial statements.
FS-13
CONSOLIDATED BALANCE SHEET
--------------------------
At December 31
-----------------------
Millions of dollars 1999 1998
- ----------------------------------------------------------------------------------------------------
ASSETS
Cash and cash equivalents ................................................... $ 1,345 $ 569
Marketable securities ....................................................... 687 844
Accounts and notes receivable (less allowance: 1999 - $36; 1998 - $27) ...... 3,688 2,813
Inventories:
Crude oil and petroleum products ................................... 585 600
Chemicals .......................................................... 526 559
Materials, supplies and other ...................................... 291 296
----------------------
1,402 1,455
Prepaid expenses and other current assets ................................... 1,175 616
- ----------------------------------------------------------------------------------------------------
TOTAL CURRENT ASSETS ........................................................ 8,297 6,297
Long-term receivables ....................................................... 815 872
Investments and advances .................................................... 5,231 4,604
Properties, plant and equipment, at cost .................................... 54,212 51,337
Less: accumulated depreciation, depletion and amortization .................. 28,895 27,608
----------------------
25,317 23,729
Deferred charges and other assets ........................................... 1,008 1,038
- ----------------------------------------------------------------------------------------------------
TOTAL ASSETS ................................................................ $ 40,668 $ 36,540
====================================================================================================
LIABILITIES AND STOCKHOLDERS' EQUITY
Short-term debt ............................................................. $ 3,434 $ 3,165
Accounts payable ............................................................ 3,103 2,170
Accrued liabilities ......................................................... 1,210 1,202
Federal and other taxes on income ........................................... 718 226
Other taxes payable ......................................................... 424 403
- ----------------------------------------------------------------------------------------------------
TOTAL CURRENT LIABILITIES ................................................... 8,889 7,166
Long-term debt .............................................................. 5,174 4,128
Capital lease obligations ................................................... 311 265
Deferred credits and other noncurrent obligations ........................... 1,739 2,560
Noncurrent deferred income taxes ............................................ 5,010 3,645
Reserves for employee benefit plans ......................................... 1,796 1,742
- ----------------------------------------------------------------------------------------------------
TOTAL LIABILITIES ........................................................... 22,919 19,506
- ----------------------------------------------------------------------------------------------------
Preferred stock (authorized 100,000,000 shares, $1.00 par value, none issued) - -
Common stock (authorized 1,000,000,000 shares,
$1.50 par value, 712,487,068 shares issued) ........................ 1,069 1,069
Capital in excess of par value .............................................. 2,215 2,097
Deferred compensation ....................................................... (646) (691)
Accumulated other comprehensive income ...................................... (115) (90)
Retained earnings ........................................................... 17,400 16,942
Treasury stock, at cost (1999 - 56,140,994 shares; 1998 - 59,460,666 shares) (2,174) (2,293)
- ----------------------------------------------------------------------------------------------------
TOTAL STOCKHOLDERS' EQUITY .................................................. 17,749 17,034
- ----------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY .................................. $ 40,668 $ 36,540
====================================================================================================
See accompanying notes to consolidated financial statements.
FS-14
CONSOLIDATED STATEMENT OF CASH FLOWS
------------------------------------
Year ended December 31
-------------------------------------------
Millions of dollars 1999 1998 1997
- ------------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Net income ......................................................... $ 2,070 $ 1,339 $ 3,256
Adjustments
Depreciation, depletion and amortization ........................... 2,866 2,320 2,300
Dry hole expense related to prior years' expenditures .............. 126 40 31
Distributions (less than) greater than income from equity affiliates (258) 25 (353)
Net before-tax gains on asset retirements and sales ................ (471) (45) (344)
Net foreign currency losses (gains) ................................ 23 (20) (69)
Deferred income tax provision ...................................... 226 266 622
Net decrease (increase) in operating working capital(1) ............ 636 (809) (253)
(Decrease) increase in Cities Service provision .................... (149) 924 -
Cash settlement of Cities Service litigation ....................... (775) - -
Other, net ......................................................... 187 (309) (310)
- ------------------------------------------------------------------------------------------------------------------
NET CASH PROVIDED BY OPERATING ACTIVITIES(2) ......................... 4,481 3,731 4,880
- ------------------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Capital expenditures ............................................... (4,366) (3,880) (3,899)
Proceeds from asset sales .......................................... 992 434 1,235
Net sales (purchases) of marketable securities(3)................... 262 (183) 101
Other, net ......................................................... 32 (230) (297)
- ------------------------------------------------------------------------------------------------------------------
NET CASH USED FOR INVESTING ACTIVITIES ............................... (3,080) (3,859) (2,860)
- ------------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Net borrowings (repayments) of short-term obligations .............. 219 1,713 (163)
Proceeds from issuances of long-term debt .......................... 1,221 224 26
Repayments of long-term debt and other financing obligations ....... (549) (388) (421)
Cash dividends paid ................................................ (1,625) (1,596) (1,493)
Net sales (purchases) of treasury shares ........................... 108 (261) 173
- ------------------------------------------------------------------------------------------------------------------
NET CASH USED FOR FINANCING ACTIVITIES ............................... (626) (308) (1,878)
- ------------------------------------------------------------------------------------------------------------------
EFFECT OF FOREIGN CURRENCY EXCHANGE RATE CHANGES
ON CASH AND CASH EQUIVALENTS ....................................... 1 (10) (19)
- ------------------------------------------------------------------------------------------------------------------
NET CHANGE IN CASH AND CASH EQUIVALENTS .............................. 776 (446) 123
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR ....................... 569 1,015 892
- ------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT YEAR-END ................................ $ 1,345 $ 569 $ 1,015
==================================================================================================================
See accompanying notes to consolidated financial statements.
(1) "Net decrease (increase) in operating working capital" is
composed of the following:
(Increase) decrease in accounts and notes receivable $ (810) $ 552 $ 474
Decrease (increase) in inventories 72 (116) (11)
(Increase) decrease in prepaid expenses and other current assets (43) (23) 59
Increase (decrease) in accounts payable and accrued liabilities 915 (807) (685)
Increase (decrease) in income and other taxes payable 502 (415) (90)
- ------------------------------------------------------------------------------------------------------------------
Net decrease (increase) in operating working capital $ 636 $ (809) $ (253)
==================================================================================================================
(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) $ 438 $ 407 $ 318
Income taxes paid $ 864 $ 654 $ 1,706
==================================================================================================================
(3) "Net sales (purchases) of marketable securities" consists of
the following gross amounts:
Marketable securities purchased $(2,812) $(2,679) $(2,724)
Marketable securities sold 3,074 2,496 2,825
- ------------------------------------------------------------------------------------------------------------------
Net sales (purchases) of marketable securities $ 262 $ (183) $ 101
==================================================================================================================
FS-15
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
----------------------------------------------
1999 1998 1997
----------------------- ------------------------ ------------------------
Amounts in millions of dollars Shares Amount Shares Amount Shares Amount
- ----------------------------------------------------------------------------------------------------------------
COMMON STOCK
Balance at January 1 712,487,068 $ 1,069 712,487,068 $ 1,069 712,487,068 $ 1,069
Change during year - - - - - -
-----------------------------------------------------------------------------
Balance at December 31 712,487,068 $ 1,069 712,487,068 $ 1,069 712,487,068 $ 1,069
- ----------------------------------------------------------------------------------------------------------------
TREASURY STOCK AT COST
Balance at January 1 59,460,666 $(2,293) 56,555,871 $(1,977) 59,401,015 $(2,024)
Purchases 56,052 (5) 5,246,100 (398) 1,255,022 (95)
Reissuances (3,375,724) 124 (2,341,305) 82 (4,100,166) 142
-----------------------------------------------------------------------------
Balance at December 31 56,140,994 $(2,174) 59,460,666 $(2,293) 56,555,871 $(1,977)
- ----------------------------------------------------------------------------------------------------------------
CAPITAL IN EXCESS OF PAR
Balance at January 1 $ 2,097 $ 2,022 $ 1,874
Treasury stock transactions 118 75 148
------- ------- -------
Balance at December 31 $ 2,215 $ 2,097 $ 2,022
- ----------------------------------------------------------------------------------------------------------------
DEFERRED COMPENSATION
Balance at January 1 $ (691) $ (750) $ (800)
Net Reduction of ESOP debt and other 45 59 50
------- ------- -------
Balance at December 31 $ (646) $ (691) $ (750)
- ----------------------------------------------------------------------------------------------------------------
ACCUMULATED OTHER COMPREHENSIVE INCOME(1)
Balance at January 1 $ (90) $ (77) $ 96
Change during year (25) (13) (173)
------- ------- -------
Balance at December 31 $ (115) $ (90) $ (77)
- ----------------------------------------------------------------------------------------------------------------
RETAINED EARNINGS
Balance at January 1 $16,942 $17,185 $15,408
Net Income 2,070 1,339 3,256
Cash dividends (per-share amounts
1999: $2.48; 1998: $2.44; 1997: $2.28) (1,625) (1,596) (1,493)
Tax benefit from dividends paid on
unallocated ESOP shares 13 14 14
------- ------- -------
Balance at December 31 $17,400 $16,942 $17,185
- ----------------------------------------------------------------------------------------------------------------
TOTAL STOCKHOLDERS' EQUITY AT DECEMBER 31 $17,749 $17,034 $17,472
================================================================================================================
See accompanying notes to consolidated financial statements.
(1) ACCUMULATED OTHER COMPREHENSIVE INCOME:
Currency Translation Unrealized Holding Minimum Pension
Adjustment Gain on Securities Liability Adjustment Total
- -----------------------------------------------------------------------------------------------------------------------------
Balance at January 1, 1997 $ 118 $ 14 $ (36) $ 96
Change during year (173) (4) 4 (173)
- -----------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1997 $ (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)
=============================================================================================================================
FS-16
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Millions of dollars, except per-share amounts
Note 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Chevron Corporation is an international company that, through its subsidiaries
and affiliates, engages in fully integrated petroleum operations, chemicals
operations and coal mining in the United States and more than 100 countries.
Petroleum operations consist of exploring for, developing and producing crude
oil and natural gas; transporting crude oil, natural gas and products by
pipelines, marine vessels and motor equipment; refining crude oil into finished
petroleum products; and marketing crude oil, natural gas and refined petroleum
products. Chemicals operations include the manufacture and marketing of a wide
range of chemicals for industrial uses.
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.
Also, the company imports crude oil for its U.S. refining operations. 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.
Oil and Gas Accounting
The successful efforts method is used for oil and gas exploration and production
activities.
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."
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
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.
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 to 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.
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
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 or sales are included in income.
Expenditures for maintenance, repairs and minor renewals to maintain facilities
in operating condition are expensed. Major replacements and renewals are
capitalized.
FS-17
Note 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
- Continued
Environmental Expenditures
Environmental expenditures that relate to current 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 and gas and coal producing properties, a provision is made through
depreciation expense for anticipated abandonment and restoration costs at the
end of the 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 method
companies. 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 19 pro forma net income and
earnings per share data as if the accounting prescribed by SFAS No. 123,
"Accounting for Stock-Based Compensation," had been applied.
Note 2.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.
Year ended December 31
-------------------------
1999 1998 1997
- ------------------------------------------------------------------------------
Asset write-offs and revaluations
Asset impairments
- Oil and gas properties ......... $(204) $ (50) $ (68)
- Coal assets .................... (34) - -
U.S. refining, marketing and
transportation assets ............ - (22) -
Chemicals assets .......................... (43) (19) (10)
Real estate assets ........................ - (9) -
Other ..................................... (65) (59) (8)
--------------------------
(346) (159) (86)
- -------------------------------------------------------------------------------
Asset dispositions, net
Pipeline interests ........................ 75 - -
Real estate ............................... 60 - -
Coal assets ............................... 60 - -
Marketable securities ..................... 30 - -
Oil and gas assets ........................ 17 (9) 240
Caltex interest in equity affiliate ....... (31) - -
Chemicals affiliate ....................... - - 33
U.K. refining and marketing exit .......... - - (72)
Domestic shipping assets .................. - - (18)
--------------------------
211 (9) 183
- -------------------------------------------------------------------------------
Prior-year tax adjustments ......................... 109 271 152
- -------------------------------------------------------------------------------
Environmental remediation provisions, net .......... (123) (39) (35)
- -------------------------------------------------------------------------------
Restructurings and reorganizations
Corporate ................................. (158) - -
Caltex affiliate .......................... (25) (43) (6)
Dynegy affiliate .......................... - - (54)
--------------------------
(183) (43) (60)
- -------------------------------------------------------------------------------
LIFO inventory gains (losses) ...................... 38 (25) 5
- -------------------------------------------------------------------------------
Other, net
Litigation and regulatory issues* ......... 78 (682) (24)
Settlement of insurance claims ............ - 105 7
Caltex write-off of start-up costs (SOP 98-5) - (25) -
Performance stock options ................. - - (66)
--------------------------
78 (602) (83)
- -------------------------------------------------------------------------------
Total special items, after tax ..................... $(216) $(606) $ 76
===============================================================================
* 1999 and 1998 include effects related to Cities Service litigation.
FS-18
Note 2. SPECIAL ITEMS AND OTHER FINANCIAL INFORMATION - Continued
Other financial information is as follows.
Year ended December 31
------------------------
1999 1998 1997
- -----------------------------------------------------------------
Total financing interest and debt costs $ 481 $ 444 $ 411
Less: capitalized interest ............ 9 39 99
------------------------
Interest and debt expense ............. 472 405 312
Research and development expenses ..... 182 187 179
Foreign currency (losses) gains* ...... $ (38) $ (47) $ 246
=================================================================
*Includes $(15), $(68) and $177 in 1999, 1998 and 1997, respectively, for the
company's share of affiliates' foreign currency (losses) gains.
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
$871, $584 and $1,089 at December 31, 1999, 1998 and 1997, respectively.
Note 3. CUMULATIVE EFFECT ON NET INCOME FROM ACCOUNTING CHANGES
In April 1998, the AICPA released Statement of Position 98-5, "Reporting on the
Costs of Start-up Activities" (SOP 98-5), 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.
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 4. INFORMATION RELATING TO THE CONSOLIDATED STATEMENT OF CASH FLOWS
The Consolidated Statement of Cash Flows excludes the following significant
noncash transactions.
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.
During 1997, the company's Venice, Louisiana, natural gas facility was
contributed to a partnership with Dynegy Inc. (Dynegy). An increase in
"Investments and advances" resulted primarily from the contribution of
properties, plant and equipment.
The major components of "Capital expenditures" in the Consolidated Statement of
Cash Flows and the reconciliation of this amount to total capital and
exploratory expenditures, are presented in the following table.
Year ended December 31
-------------------------------
1999 1998 1997
- --------------------------------------------------------------------------------------
Additions to properties,
plant and equipment ......................... $ 5,018 $ 3,678 $ 3,840
Additions to investments ............................. 449 306 153
Payments for other liabilities
and assets, net(1)........................... (1,101) (104) (94)
- --------------------------------------------------------------------------------------
Capital expenditures ................................. 4,366 3,880 3,899
Expensed exploration expenditures .................... 413 438 462
Payments of long-term debt
and other financing obligations(2)........... 572 2 6
- --------------------------------------------------------------------------------------
Capital and exploratory expenditures,
excluding equity affiliates ........ $ 5,351 $ 4,320 $ 4,367
======================================================================================
(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.
Note 5. STOCKHOLDERS' EQUITY
Retained earnings at December 31, 1999 and 1998, include $2,048 and $2,121,
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 will be 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 amount of 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.
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 1999 made the
Rights exercisable. Rights associated with a 1988 dividend distribution expired
in 1998.
Note 6. 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
FS-19
Note 6. FINANCIAL AND DERIVATIVE INSTRUMENTS - Continued
crude oil purchases and sales and product sales, generally forecast to occur
within a 60- to 90-day period. Crude oil swaps are used to hedge sales
forecasted to occur within the next four 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 1999 had an average remaining maturity of 58 months. Gains and losses
on these derivative instruments offset and are recognized in income concurrently
with the recognition of the underlying physical transactions.
In addition, the company in 1998 entered into managed programs using swaps and
options to take advantage of perceived opportunities for favorable price
movements in natural gas. The results of these programs were reflected in income
and were not material in 1998. 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, 1999, there was one outstanding contract, with a remaining term
of five years and six months.
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 where available or, in
their absence, 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. At December 31, 1999 and 1998, the fair values of the
financial and derivative instruments were:
Long-term debt of $2,449 and $1,403 had estimated fair values of $2,430 and
$1,485.
The notional principal amounts of the interest rate swaps totaled $350 and $700,
with approximate fair values totaling $11 and $(21). The notional amounts of
these and other 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 $1,762 and $1,206. Of these
balances, $1,075 and $362 classified as cash equivalents had average maturities
under 90 days, while the remainder, classified as marketable securities, had
average maturities of approximately three years and two years.
For other derivatives the contract or notional values were as follows: Crude oil
and products futures had net contract values of $143 and $33. Forward exchange
contracts had contract values of $123 and $180. Gas swap contracts are based on
notional gas volumes of approximately 44 and 67 billion cubic feet. Crude oil
swap contracts are based on notional crude volumes of approximately 9 million
barrels. Fair values for all of these derivatives were not material in 1999 and
1998. Deferred gains and losses that were accrued on the Consolidated Balance
Sheet were not material.
Note 7. SUMMARIZED FINANCIAL DATA - CHEVRON U.S.A. INC.
At December 31, 1999, 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) and, effective February 1,
1998, the majority of its worldwide petrochemicals operations. In 1999, these
operations were conducted primarily by three divisions: Chevron U.S.A.
Production Company, Chevron Products Company and Chevron Chemical Company LLC.
Summarized financial information for Chevron U.S.A. Inc. and its consolidated
subsidiaries is presented below.
Year ended December 31
---------------------------
1999 1998 1997
- ------------------------------------------------------------------
Sales and other operating revenues $28,957 $24,440 $28,130
Total costs and other deductions ... 28,329 24,338 26,354
Net income ......................... 885 346 1,484
==================================================================
At December 31
-------------------
1999 1998*
- -------------------------------------------------
Current assets .... $ 3,889 $ 3,227
Other assets ...... 19,403 18,330
Current liabilities 4,676 3,809
Other liabilities . 8,455 6,541
Net equity ........ 10,161 11,207
=================================================
Memo: Total Debt $ 7,462 $ 3,546
* Certain amounts have been reclassified to conform to current presentation.
The primary cause of the reduction in net equity from 1998 to 1999 was a return
of $2,000 of capital to Chevron Corporation in exchange for a loan.
Note 8. 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
FS-20
Note 8. SUMMARIZED FINANCIAL DATA - CHEVRON TRANSPORT CORPORATION LIMITED -
Continued
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 where CTC is deemed to be an issuer. In accordance with the
Securities and Exchange Commission's disclosure requirements, summarized
financial information for CTC and its consolidated subsidiaries is presented
below. This information was derived from the financial statements prepared on a
stand-alone basis in conformity with generally accepted accounting principles.
During 1999, CTC's parent contributed an additional $62 of paid-in capital.
Separate CTC financial statements and other disclosures are omitted, as such
information is not material to investors in the debt securities deemed issued by
CTC. There were no restrictions on CTC's ability to pay dividends or make loans
or advances at December 31, 1999.
Year ended December 31
------------------------
1999 1998 1997
- --------------------------------------------------------------
Sales and other operating revenues.. $ 504 $ 573 $ 544
Total costs and other deductions ... 572 580 557
Net (loss) income .................. (50) 17 28
==============================================================
At December 31
-----------------
1999 1998
- ------------------------------------------------------
Current assets ......... $184 $270
Other assets ........... 742 982
Current liabilities..... 580 898
Other liabilities ...... 264 284
Net equity ............. 82 70
======================================================
Note 9. 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.
In February 2000, Chevron and Phillips Petroleum Company signed a letter of
intent and exclusivity agreement to combine most of their chemicals businesses
in a joint venture. Each company will own 50 percent of the joint venture, which
would have had 1999 sales of $6,000 and is expected to have total assets of
about $6,000. The combination is subject to final approval of the companies'
boards of directors, signing of definitive agreements and regulatory review, all
of which are expected to be completed by mid-2000.
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 for the years 1999, 1998 and 1997 are
presented in the following table.
Year ended December 31
------------------------------
1999 1998 1997
- --------------------------------------------------------------------
EXPLORATION AND PRODUCTION
United States ............. $ 526 $ 365 $ 1,001
International ............. 1,093 707 1,252
- --------------------------------------------------------------------
TOTAL EXPLORATION
AND PRODUCTION ............ 1,619 1,072 2,253
- --------------------------------------------------------------------
REFINING, MARKETING
AND TRANSPORTATION
United States ............. 357 572 601
International ............. 74 28 298
- --------------------------------------------------------------------
TOTAL REFINING, MARKETING
AND TRANSPORTATION ........ 431 600 899
- --------------------------------------------------------------------
CHEMICALS
United States ............. 44 79 138
International ............. 65 43 90
- --------------------------------------------------------------------
TOTAL CHEMICALS .................... 109 122 228
- --------------------------------------------------------------------
TOTAL SEGMENT INCOME ............... 2,159 1,794 3,380
- --------------------------------------------------------------------
Interest Expense ................... (333) (270) (189)
Interest Income .................... 21 63 75
Other .............................. 223 (248) (10)
- --------------------------------------------------------------------
NET INCOME ................ $ 2,070 $ 1,339 $ 3,256
====================================================================
NET INCOME - UNITED STATES $ 976 $ 642 $ 1,622
NET INCOME - INTERNATIONAL $ 1,094 $ 697 $ 1,634
- --------------------------------------------------------------------
TOTAL NET INCOME .......... $ 2,070 $ 1,339 $ 3,256
====================================================================
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, and coal mining
assets. Segment assets at year-end 1999 and 1998 are as follows.
At December 31
------------------
1999 1998
- ------------------------------------------------
EXPLORATION AND PRODUCTION
United States ..... $ 5,566 $ 6,026
International ..... 13,748 10,794
- ------------------------------------------------
TOTAL EXPLORATION
AND PRODUCTION .... 19,314 16,820
- ------------------------------------------------
REFINING, MARKETING
AND TRANSPORTATION
United States ..... 8,178 8,084
International ..... 3,609 3,559
- ------------------------------------------------
TOTAL REFINING, MARKETING
AND TRANSPORTATION 11,787 11,643
- ------------------------------------------------
CHEMICALS
United States ..... 3,303 3,045
International ..... 923 828
- ------------------------------------------------
TOTAL CHEMICALS ............ 4,226 3,873
- ------------------------------------------------
TOTAL SEGMENT ASSETS ....... 35,327 32,336
- ------------------------------------------------
ALL OTHER
United States ..... 3,474 2,467
International ..... 1,867 1,737
- ------------------------------------------------
TOTAL All OTHER ............ 5,341 4,204
- ------------------------------------------------
TOTAL ASSETS - UNITED STATES 20,521 19,622
TOTAL ASSETS - INTERNATIONAL 20,147 16,918
- ------------------------------------------------
TOTAL ASSETS ...... $40,668 $36,540
================================================
FS-21
Note 9. OPERATING SEGMENTS AND GEOGRAPHIC DATA
- - Continued
Segment Income Taxes
Segment income tax expenses for the years 1999, 1998 and
1997 are as follows.
Year ended December 31
-----------------------------
1999 1998 1997
- -----------------------------------------------------------------
EXPLORATION AND PRODUCTION
United States .......... $ 266 $ 164 $ 559
International .......... 1,341 595 1,488
- -----------------------------------------------------------------
TOTAL EXPLORATION
AND PRODUCTION ......... 1,607 759 2,047
- -----------------------------------------------------------------
REFINING, MARKETING
AND TRANSPORTATION
United States .......... 135 309 346
International .......... 41 54 6
- -----------------------------------------------------------------
TOTAL REFINING, MARKETING
AND TRANSPORTATION ..... 176 363 352
- -----------------------------------------------------------------
CHEMICALS
United States .......... (13) 25 77
International .......... 45 14 57
- -----------------------------------------------------------------
TOTAL CHEMICALS ................. 32 39 134
- -----------------------------------------------------------------
All Other .............. (237) (666) (287)
- -----------------------------------------------------------------
TOTAL INCOME TAX EXPENSE $ 1,578 $ 495 $ 2,246
=================================================================
Segment Sales and Other Operating Revenues
Revenues for the exploration and production segments are derived primarily from
the production of crude oil and natural gas. Revenues for the refining,
marketing and transportation segments 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. Chemicals segment revenues are derived from the manufacture and sale
of petrochemicals, plastic resins, and lube oil and fuel additives.
"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 1999, 1998 and 1997 are presented in the table
that follows. Sales from the transfer of products between segments are at
estimated market prices.
Year ended December 31
-------------------------------
1999 1998(1) 1997(1)
- --------------------------------------------------------------------------------------------
EXPLORATION AND PRODUCTION
United States
Crude oil ...................................... $ - $ - $ (3)
Natural gas .................................... 1,578 1,599 1,978
Natural gas liquids ............................ 159 128 185
Other .......................................... 8 12 20
Intersegment ................................... 1,985 1,453 4,362
--------------------------------
Total United States ............................ 3,730 3,192 6,542
- --------------------------------------------------------------------------------------------
International
Refined products ............................... 2 1 2
Crude oil ...................................... 2,586 1,761 2,790
Natural gas .................................... 678 505 590
Natural gas liquids ............................ 116 89 170
Other .......................................... 205 130 116
Intersegment ................................... 2,876 1,984 2,810
--------------------------------
Total International ............................ 6,463 4,470 6,478
- --------------------------------------------------------------------------------------------
TOTAL EXPLORATION
AND PRODUCTION ............... 10,193 7,662 13,020
- --------------------------------------------------------------------------------------------
REFINING, MARKETING
AND TRANSPORTATION
United States
Refined products ............................... 12,765 10,148 12,586
Crude oil ...................................... 3,618 2,971 4,531
Natural gas liquids ............................ 133 100 158
Other .......................................... 654 622 592
Excise taxes ................................... 3,702 3,503 3,386
Intersegment ................................... 366 216 313
--------------------------------
Total United States ............................ 21,238 17,560 21,566
- --------------------------------------------------------------------------------------------
International
Refined products ............................... 975 1,312 2,998
Crude oil ...................................... 3,874 3,049 3,978
Natural gas liquids ............................ 24 5 40
Other .......................................... 248 299 390
Excise taxes ................................... 178 213 2,188
Intersegment ................................... 16 20 15
--------------------------------
Total International ............................ 5,315 4,898 9,609
- --------------------------------------------------------------------------------------------
TOTAL REFINING, MARKETING
AND TRANSPORTATION ........... 26,553 22,458 31,175
- --------------------------------------------------------------------------------------------
CHEMICALS
United States
Products ....................................... 2,794 2,468 2,933
Excise taxes ................................... 2 2 -
Intersegment ................................... 162 121 112
--------------------------------
Total United States ............................ 2,958 2,591 3,045
- --------------------------------------------------------------------------------------------
International
Products ....................................... 715 568 559
Other .......................................... 35 18 28
Excise taxes ................................... 28 38 13
Intersegment ................................... 1 1 2
--------------------------------
Total International ............................ 779 625 602
- --------------------------------------------------------------------------------------------
TOTAL CHEMICALS ....................... 3,737 3,216 3,647
- --------------------------------------------------------------------------------------------
ALL OTHER
United States - Coal .................................... 360 399 359
United States - Other ................................... 8 (1) 8
International ........................................... 3 4 1
Intersegment - United States ............................ 55 52 47
Intersegment - International ............................ 4 2 -
- --------------------------------------------------------------------------------------------
TOTAL ALL OTHER ....................... 430 456 415
- --------------------------------------------------------------------------------------------
Sales and Other Operating Revenues
- United States ................................ 28,349 23,793 31,567
- International ................................ 12,564 9,999 16,690
- --------------------------------------------------------------------------------------------
Total Segment Sales and
Other Operating Revenues ....................... 40,913 33,792 48,257
- --------------------------------------------------------------------------------------------
Elimination of Intersegment Sales ....................... (5,465) (3,849) (7,661)
- --------------------------------------------------------------------------------------------
Total Sales and
Other Operating Revenues ....................... $35,448 $29,943 $40,596
============================================================================================
(1) Certain amounts have been restated to conform to the 1999 presentation
Other Segment Information
Investments in and earnings from affiliated companies are included in the
segments in which the affiliates operate. Dynegy Inc. is included in U.S.
exploration and production, P.T. Caltex Pacific Indonesia (CPI) and
Tengizchevroil (TCO) are included in International exploration and production,
and Caltex Corporation is included in International refining, marketing and
transportation. The company's other affiliates are not material to any segment's
assets or results of operations. Information on equity affiliates, including
carrying value and equity earnings, is included in Note 12.
Additions to long-lived assets and depreciation expense, by operating segment,
are included in Note 13.
FS-22
Note 10. LITIGATION
The company is a party, along with other oil companies, to numerous lawsuits and
claims, including actions challenging oil and gas royalty and severance tax
payments based on posted prices, and actions related to the use of the chemical
MTBE in certain oxygenated gasolines. In some of these actions, plaintiffs may
seek to recover large and sometimes unspecified amounts. In others, the
plaintiffs may seek to have the company perform specific actions, 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 could be material with respect to earnings in any given period,
management believes that resolution of these matters will not result in any
significant liability to the company in relation to its consolidated financial
position or have a significant effect on its liquidity.
In a lawsuit in Los Angeles, Calif., brought in 1995, the company and five other
oil companies are contesting the validity of a patent granted to Unocal
Corporation (Unocal) for certain types of reformulated gasoline, which the
company sells in California during certain months of the year. The first two
phases of the trial were concluded in 1997, with the jury upholding the validity
of the patent and assessing damages at the rate of 5.75 cents per gallon of
gasoline produced in infringement of the patent between March 1 and July 1,
1996. In the third phase of the trial, the judge heard evidence to determine if
the patent was enforceable. In 1998, the judge ruled the patent was enforceable.
The defendants filed an appeal in January 1999 and oral arguments were made
before the court in July 1999. While the ultimate outcome of this matter cannot
be determined with certainty, the company believes Unocal's patent is invalid
and any unfavorable rulings should be reversed upon appeal. Unocal also has
filed for additional patents for alternate formulations. Should the jury's
finding and Unocal's patent ultimately be upheld, the company's financial
exposure includes royalties, plus interest, for past production of gasoline that
is ruled to have infringed the applicable patent and royalty payments for any
future production of gasoline that infringes this patent. The effect of
unfavorable rulings with respect to future reformulated gasoline production
would depend on the availability of alternate formulations and the industry's
ability to recover additional costs of production through prices charged to its
customers. The company believes that its ultimate exposure in this matter will
not materially affect its financial position or liquidity, although the costs of
resolution of any unfavorable ruling could be material with respect to earnings
in any given period.
Note 11. 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.
At December 31
---------------------
1999 1998
- -------------------------------------------------------------
Exploration and Production .......... $ 86 $ 5
Refining, Marketing and Transportation 779 757
- -------------------------------------------------------------
Total ....................... 865 762
Less: accumulated amortization ....... 425 398
- -------------------------------------------------------------
Net capitalized leased assets ........ $ 440 $ 364
=============================================================
Rental expenses incurred for operating leases during 1999, 1998 and 1997 were as
follows.
Year ended December 31
-------------------------------------
1999 1998 1997
- ----------------------------------------------------------------------
Minimum rentals ............ $465 $503 $443
Contingent rentals ......... 3 5 5
- ----------------------------------------------------------------------
Total ............. 468 508 448
Less: sublease rental income 3 3 5
- ----------------------------------------------------------------------
Net rental expense ......... $465 $505 $443
======================================================================
At December 31, 1999, the future minimum lease payments under operating and
capital leases are as follows.
At December 31
--------------------------
Operating Capital
Leases Leases
- ------------------------------------------------------------
Year
2000 $ 157 $ 81
2001 180 77
2002 180 72
2003 178 103
2004 177 46
Thereafter 312 889
- ------------------------------------------------------------
Total $1,184 1,268
=============================================
Less: amounts representing interest
and executory costs 625
- ------------------------------------------------------------
Net present values 643
Less: capital lease obligations
included in short-term debt 332
- ------------------------------------------------------------
Long-term capital lease obligations $ 311
============================================================
Future sublease rental income $ 1 $ -
============================================================
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 one 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.
Note 12. INVESTMENTS AND ADVANCES
Chevron owns 50 percent each of P.T. Caltex Pacific Indonesia, 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.
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
reduced from 50 percent to 45 percent in April 1997 through a sale of a portion
of its interest. The company has an obligation of $420, payable to the Republic
of Kazakhstan upon the 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. This amount was included in the value of the investment, as the
company believed at the time, and continues to believe, that its payment is
beyond a reasonable doubt given the original intent and continuing commitment
FS-23
Note 12. INVESTMENTS AND ADVANCES - Continued
of both parties to realizing the full potential of the venture over its 40-year
life.
Chevron owns 28 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.
The market value of Chevron's shares of Dynegy common stock at December 31,
1999, was $1,133 based on quoted closing market prices. In February 2000, Dynegy
completed a merger with Illinova Corporation, an energy services holding company
in Illinois. Chevron increased its investment by $200 to maintain a 28 percent
ownership in the merged company.
The company received dividends and distributions of $268, $254 and $335 in 1999,
1998 and 1997, respectively, including $212, $167 and $207 from the Caltex
Group. During 1998, Dynegy repaid a $155 loan from Chevron, which is reflected
as a decrease in the company's investment in the affiliate.
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.
"Accounts and notes receivable" in the Consolidated Balance Sheet include $277
and $156 at December 31, 1999 and 1998, respectively, of amounts due from
affiliated companies. "Accounts payable" includes $53 and $41 at December 31,
1999 and 1998, respectively, of amounts due to affiliated companies.
Year ended December 31
--------------------------
1999 1998 1997
- -------------------------------------------------------------------
Sales to Caltex Group .................. $ 687 $ 772 $1,335
Sales to Dynegy Inc. ................... 1,407 1,307 1,822
Sales to Fuel & Marine Marketing LLC* .. 234 22 -
Sales to other affiliates .............. 12 4 8
- -------------------------------------------------------------------
Total sales to affiliates .... $2,340 $2,105 $3,165
===================================================================
Purchases from Caltex Group ............ $ 867 $ 681 $ 932
Purchases from Dynegy Inc. ............. 785 642 854
Purchases from other affiliates ........ 6 2 16
- -------------------------------------------------------------------
Total purchases from affiliates $1,658 $1,325 $1,802
===================================================================
* Affiliate formed in November 1998 owned 31 percent by Chevron.
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.
Investments and Advances Equity in Earnings
-----------------------------------------------------
At December 31 Year ended December 31
-----------------------------------------------------
1999 1998 1999 1998 1997*
- ----------------------------------------------------------------------------------
Exploration and Production
Tengizchevroil ........ $1,722 $1,455 $ 177 $ 60 $ 169
Caltex Group .......... 455 452 139 107 171
Dynegy Inc. ........... 351 265 51 49 (17)
Other ................. 198 134 32 4 13
- ----------------------------------------------------------------------------------
Total Exploration
and Production 2,726 2,306 399 220 336
- ----------------------------------------------------------------------------------
Refining, Marketing and Transportation
Caltex Group .......... 1,683 1,751 56 (36) 252
Other ................. 379 124 70 24 57
- ----------------------------------------------------------------------------------
Total Refining,
Marketing and
Transportation 2,062 1,875 126 (12) 309
- ----------------------------------------------------------------------------------
Chemicals ............... 145 135 1 - 25
All Other ............... 31 74 - 20 18
- ----------------------------------------------------------------------------------
Total Equity Method ... $4,964 $4,390 $ 526 $ 228 $ 688
- ----------------------------------------------------------------------------------
Other at or Below Cost .. 267 214
Total Investments and
Advances .... $5,231 $4,604
==================================================================================
* Reclassified to conform to the 1998 presentation.
The following tables summarize the combined financial information for the Caltex
Group and all of the other equity-method companies, together with Chevron's
share. Amounts shown for the affiliates are 100 percent.
Caltex Group Other Affiliates Chevron's Share
----------------------------------------------------------------------------------------
Year ended December 31 1999 1998* 1997* 1999 1998 1997 1999 1998* 1997*
- --------------------------------------------------------------------------------------------------------------------------
Total revenues ................. $14,915 $11,506 $15,699 $20,645 $16,842 $16,574 $13,660 $11,194 $12,717
Total costs and other deductions 14,134 10,986 14,489 19,805 16,430 15,770 12,863 10,672 11,789
Net income ..................... 390 143 846 610 295 556 526 228 688
==========================================================================================================================
Caltex Group Other Affiliates Chevron's Share
----------------------------------------------------------------------------------------
At December 31 ................. 1999 1998 1997 1999 1998 1997 1999 1998 1997
- --------------------------------------------------------------------------------------------------------------------------
Current assets ................. $ 4,928 $ 1,974 $ 2,521 $ 4,640 $ 3,326 $ 3,232 $ 3,962 $ 2,015 $ 2,289
Other assets ................... 5,381 7,683 7,193 10,255 8,868 6,713 6,009 6,663 5,971
Current liabilities ............ 3,395 2,840 2,991 3,709 2,723 2,565 2,665 2,162 2,232
Other liabilities .............. 2,638 2,420 2,131 8,362 7,147 5,448 2,342 2,126 1,740
Net equity ..................... 4,276 4,397 4,592 2,824 2,324 1,932 4,964 4,390 4,288
==========================================================================================================================
*Caltex "Total revenues" and "Total costs and other deductions" have been
reclassified to net certain offsetting trading sale and purchase contracts. The
reclassifications conform to the 1999 presentation and have no impact on net
income.
FS-24
Note 13. PROPERTIES, PLANT AND EQUIPMENT
At December 31 Year ended December 31
---------------------------------------------------- ----------------------------------------------
Gross Investment at Cost Net Investment Additions at Cost(1) Depreciation Expense
--------------------------- ------------------------ ---------------------- ----------------------
1999 1998 1997 1999 1998 1997 1999 1998 1997 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------------------------
Exploration and Production
United States $17,947 $18,372 $18,104 $ 4,709 $ 5,237 $ 5,052 $ 710 $1,000 $1,166 $1,130 $ 818 $ 887
International 15,876 12,755 11,752 9,465 7,148 6,691 3,251 1,221 1,310 851 730 634
- -------------------------------------------------------------------------------------------------------------------------------
Total Exploration
and Production 33,823 31,127 29,856 14,174 12,385 11,743 3,961 2,221 2,476 1,981 1,548 1,521
- -------------------------------------------------------------------------------------------------------------------------------
Refining, Marketing
and Transportation
United States 12,025 11,793 11,378 6,196 6,268 6,186 515 665 538 478 483 464
International 1,838 2,005 2,063 1,030 1,139 1,210 30 50 57 79 81 111
- -------------------------------------------------------------------------------------------------------------------------------
Total Refining, Marketing
and Transportation 13,863 13,798 13,441 7,226 7,407 7,396 545 715 595 557 564 575
- -------------------------------------------------------------------------------------------------------------------------------
Chemicals
United States 3,689 3,436 3,039 2,354 2,211 1,931 326 385 470 174 109 92
International 714 662 549 453 414 309 59 116 157 19 10 12
- -------------------------------------------------------------------------------------------------------------------------------
Total Chemicals 4,403 4,098 3,588 2,807 2,625 2,240 385 501 627 193 119 104
- -------------------------------------------------------------------------------------------------------------------------------
All Other(2) 2,123 2,314 2,348 1,110 1,312 1,292 103 202 110 135 89 100
- -------------------------------------------------------------------------------------------------------------------------------
Total United States 35,783 35,915 34,867 14,369 15,028 14,461 1,654 2,252 2,284 1,917 1,499 1,543
Total International 18,429 15,422 14,366 10,948 8,701 8,210 3,340 1,387 1,524 949 821 757
- -------------------------------------------------------------------------------------------------------------------------------
Total $54,212 $51,337 $49,233 $25,317 $23,729 $22,671 $4,994 $3,639 $3,808 $2,866 $2,320 $2,300
===============================================================================================================================
(1) Net of dry hole expense related to prior years' expenditures of $126, $40 and $31 in 1999, 1998 and 1997, respectively.
(2) Primarily coal and real estate assets and management information systems.
Note 14. TAXES
Year ended December 31
---------------------------
1999 1998 1997
- -------------------------------------------------------------------------
Taxes other than on income
United States
Excise taxes on products
and merchandise $3,704 $3,505 $3,386
Property and other
miscellaneous taxes 272 262 274
Payroll taxes .............. 119 129 123
Taxes on production ........ 94 92 118
- -------------------------------------------------------------------------
Total United States 4,189 3,988 3,901
- -------------------------------------------------------------------------
International
Excise taxes on products
and merchandise ... 206 251 2,201
Property and other
miscellaneous taxes 145 137 185
Payroll taxes .............. 32 26 23
Taxes on production ........ 14 9 10
- -------------------------------------------------------------------------
Total International 397 423 2,419
- -------------------------------------------------------------------------
Total taxes other than on income ............. $4,586 $4,411 $6,320
=========================================================================
U.S. federal income tax expense was reduced by $89, $84 and $93 in 1999, 1998
and 1997, respectively, for low-income housing and other business tax credits.
In 1999, before-tax income, including related corporate and other charges, for
U.S. operations was $1,254, compared with $728 in 1998 and $2,054 in 1997. For
international operations, before-tax income was $2,394, $1,106 and $3,448 in
1999, 1998 and 1997, respectively.
The deferred income tax provisions included costs of $788, $470 and $304 related
to properties, plant and equipment in 1999, 1998 and 1997, respectively.
Year ended December 31
------------------------------
1999 1998 1997
- --------------------------------------------------------------------------------
Taxes on income
U.S. federal
Current .................... $ 135 $ (176) $ 369
Deferred ..................... 145 71 357
State and local ....................... (14) 20 81
- --------------------------------------------------------------------------------
Total United States . 266 (85) 807
- --------------------------------------------------------------------------------
International
Current ...................... 1,231 385 1,174
Deferred ..................... 81 195 265
- --------------------------------------------------------------------------------
Total International . 1,312 580 1,439
- --------------------------------------------------------------------------------
Total taxes on income $ 1,578 $ 495 $ 2,246
================================================================================
The company's effective income tax rate varied from the U.S. statutory federal
income tax rate because of the following.
Year ended December 31
-----------------------------
1999 1998 1997
- ----------------------------------------------------------------------------------
Statutory U.S. 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 .................... 15.6 7.6 9.6
State and local taxes on income, net
of U.S. federal income tax benefit (0.2) 0.2 1.3
Prior-year tax adjustments ..................... - (4.5) (0.3)
Tax credits ..................................... (2.4) (4.6) (1.7)
Other ........................................... (2.2) (6.4) (1.7)
- ----------------------------------------------------------------------------------
Consolidated companies ........ 45.8 27.3 42.2
Effect of recording equity in income
of certain affiliated companies
on an after-tax basis .................. (2.5) (0.3) (1.4)
- ----------------------------------------------------------------------------------
Effective tax rate ............ 43.3% 27.0% 40.8%
==================================================================================
FS-25
Note 14. TAXES - Continued
The increase in the 1999 effective tax rate from the prior year is primarily due
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 1998 and from
less beneficial prior-period tax adjustments on the 1998 tax return compared
with the 1997 tax return. The other effects on the 1999 effective tax rate
include settlement of outstanding issues, utilization of additional capital loss
benefits and permanent differences. These factors were 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.
At December 31, 1999 and 1998, deferred taxes were classified in the
Consolidated Balance Sheet as follows.
At December 31
-------------------
1999 1998
- --------------------------------------------------------------
Prepaid expenses and other current assets $ (546) $ (30)
Deferred charges and other assets ....... (195) (264)
Federal and other taxes on income ....... 1 -
Noncurrent deferred income taxes ........ 5,010 3,645
- --------------------------------------------------------------
Total deferred income taxes, net $ 4,270 $ 3,351
==============================================================
The reported deferred tax balances are composed of the following deferred tax
liabilities (assets).
At December 31
-------------------------
1999 1998
- -------------------------------------------------------------------
Properties, plant and equipment ....... $ 5,800 $ 5,150
Inventory ............................. 149 144
Miscellaneous ......................... 190 184
- -------------------------------------------------------------------
Total deferred tax liabilities 6,139 5,478
- -------------------------------------------------------------------
Abandonment/environmental reserves .... (611) (774)
Employee benefits ..................... (611) (592)
AMT/other tax credits ................. (588) (354)
Other accrued liabilities ............. (195) (408)
Miscellaneous ......................... (316) (294)
- -------------------------------------------------------------------
Total deferred tax assets .... (2,321) (2,422)
- -------------------------------------------------------------------
Deferred tax assets valuation allowance 452 295
- -------------------------------------------------------------------
Total deferred taxes, net .... $ 4,270 $ 3,351
===================================================================
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 $4,602 at December 31, 1999. 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 remittance 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 $187 would be payable upon
remittance of these earnings.
Note 15. 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 has entered into interest rate swaps on a portion of its short-term
debt. At December 31, 1999 and 1998, the company had swapped notional amounts of
$350 and $700 of floating rate debt to fixed rates. The effect of these swaps on
the company's interest expense was not material.
At December 31
--------------------------
1999 1998
- --------------------------------------------------------------------------
Commercial paper(1) .......................... $ 5,265 $ 4,875
Current maturities of long-term debt ......... 127 123
Current maturities of long-term capital leases 35 33
Redeemable long-term obligations
Long-term debt ...................... 301 301
Capital leases ...................... 297 273
Notes payable(2).............................. 134 285
- --------------------------------------------------------------------------
Subtotal(3).......................... 6,159 5,890
Reclassified to long-term debt ............... (2,725) (2,725)
- --------------------------------------------------------------------------
Total short-term debt ............... $ 3,434 $ 3,165
==========================================================================
(1) Weighted-average interest rates at December 31, 1999 and 1998, were 6.0
percent and 5.6 percent, respectively, including the effect of interest rate
swaps.
(2) Includes $10 guarantee of ESOP debt.
(3) Weighted-average interest rates at December 31, 1999 and 1998, were 5.8
percent for both years, including the effect of interest rate swaps.
Note 16. 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 1999, the company had $4,750 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.
At December 31, 1999 and 1998, 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 2000 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, 1999, is as follows: 2000-$127, 2001-$285, 2002-$172, 2003-$184 and
2004-$1,134.
FS-26
Note 16.LONG-TERM DEBT - Continued
At December 31
--------------------
1999 1998
- ------------------------------------------------------------------------
8.11% amortizing notes due 2004(1) ................ $ 620 $ 690
6.625% notes due 2004 ............................. 495 -
7.327% amortizing notes due 2014(2)................ 430 -
7.45% notes due 2004 .............................. 349 349
7.61% amortizing bank loans due 2003 .............. 143 172
LIBOR-based bank loan due 2001 .................... 134 100
7.677% notes due 2016(2)........................... 90 -
7.627% notes due 2015(2)........................... 80 -
6.92% bank loans due 2005 ......................... 51 51
6.98% bank loans due 2004(2)....................... 25 -
6.22% notes due 2001(2)............................ 10 -
Other foreign currency obligations (6.0%)(3)....... 75 94
Other long-term debt (6.6%)(3)..................... 74 70
- ------------------------------------------------------------------------
Total including debt due within one year . 2,576 1,526
Debt due within one year ........ (127) (123)
Reclassified from short-term debt 2,725 2,725
- ------------------------------------------------------------------------
Total long-term debt .............................. $ 5,174 $ 4,128
========================================================================
(1) Debt assumed from ESOP in 1999.
(2) Guarantee of ESOP debt.
(3) Less than $50 individually; weighted-average interest rates at December 31, 1999.
Note 17. OTHER COMPREHENSIVE INCOME
The components of changes in other comprehensive income and the related tax
effects are shown below.
Year ended December 31
-------------------------
1999 1998 1997
- ----------------------------------------------------------------------
Currency translation adjustment
Before-tax change ................ $ (43) $ (1) $(173)
Tax benefit (expense) ............. - - -
------------------------
Change, net of tax ................ (43) (1) (173)
Unrealized holding gain (loss) on securities
Before-tax change ................. 60 3 (4)
Tax benefit (expense) ............. (31) - -
------------------------
Change, net of tax ................ 29 3 (4)
Minimum pension liability adjustment
Before-tax change ................. (16) (24) 6
Tax benefit (expense) ............. 5 9 (2)
------------------------
Change, net of tax ................ (11) (15) 4
- ----------------------------------------------------------------------
TOTAL OTHER COMPREHENSIVE INCOME
Before-tax change ............... $ 1 $ (22) $(171)
Tax benefit (expense) ............. (26) 9 (2)
------------------------
Change, net of tax ................ $ (25) $ (13) $(173)
=======================================================================
Note 18. 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 table below.
The status of the company's pension plans and other postretirement benefit plans
for 1999 and 1998 is as follows.
Pension Benefits Other Benefits
-----------------------------------------
1999 1998 1999 1998
- -------------------------------------------------------------------------------------------
Change in benefit obligation
Benefit obligation at January 1 ................ $ 4,278 $ 4,069 $ 1,468 $ 1,362
Service cost .......................... 99 113 21 19
Interest cost ......................... 274 275 96 93
Plan participants' contributions ...... 1 1 - -
Plan amendments ....................... 60 - - -
Actuarial (gain) loss ................. (106) 248 (112) 72
Foreign currency exchange
rate changes ................. (33) (10) - -
Benefits paid ......................... (801) (418) (81) (78)
Special termination
benefits ..................... 205 - - -
------------------------------------------
Benefit obligation
at December 31 ........................ 3,977 4,278 1,392 1,468
- -------------------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets
at January 1 .......................... 4,741 4,454 - -
Actual return on plan assets .......... 720 675 - -
Foreign currency exchange
rate changes ................. (25) (6) - -
Employer contribution ................. 10 11 - -
Plan participants' contribution ....... 1 1 - -
Benefits paid ......................... (774) (394) - -
------------------------------------------
Fair value of plan assets
at December 31 ........................ 4,673 4,741 - -
- -------------------------------------------------------------------------------------------
Funded status .................................. 696 463 (1,392) (1,468)
Unrecognized net actuarial gain ....... (480) (155) (160) (46)
Unrecognized prior-service cost ....... 124 88 - -
Unrecognized net transitional
assets ....................... (44) (85) - -
- -------------------------------------------------------------------------------------------
Total recognized at December 31 ................ $ 296 $ 311 $(1,552) $(1,514)
===========================================================================================
Amounts recognized in the
Consolidated Balance Sheet
at December 31
Prepaid benefit cost ......... $ 495 $ 524 $ - $ -
Accrued benefit liability .... (298) (298) (1,552) (1,514)
Intangible asset ............. 10 12 - -
Accumulated other
comprehensive income(1) 89 73 - -
------------------------------------------
Net amount recognized .......................... $ 296 $ 311 $(1,552) $(1,514)
===========================================================================================
Weighted-average assumptions
as of December 31
Discount rate ................ 7.6% 6.7% 7.8% 6.8%
Expected return on plan assets 9.7% 9.1% - -
Rate of compensation increase 4.5% 4.6% 4.5% 4.5%
===========================================================================================
(1) Accumulated other comprehensive income includes deferred income tax of $31
and $26 in 1999 and 1998, respectively.
FS-27
Note 18. EMPLOYEE BENEFIT PLANS - Continued
For measurement purposes, separate health care cost-trend rates were used for
pre-age 65 and post-age 65 retirees. The 2000 annual rates of change were
assumed to be 5.2 percent and 9.7 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.
One-Percentage- One-Percentage-
Point Increase Point Decrease
- -----------------------------------------------------------------------
Effect on total service and interest
cost components $ 17 $ (19)
Effect on postretirement benefit
obligation $ 129 $(107)
=======================================================================
The components of net periodic benefit cost for 1999,
1998 and 1997 were:
Pension Benefits Other Benefits
------------------------------------------------
1999 1998 1997 1999 1998 1997
- -------------------------------------------------------------------------------
Service cost ............... $ 99 $ 113 $ 106 $ 21 $ 19 $ 17
Interest cost .............. 274 275 274 96 93 90
Expected return on
plan assets ....... (394) (397) (371) - - -
Amortization of
transitional assets (35) (38) (40) - - -
Amortization of prior-
service costs ..... 16 14 14 - - -
Recognized actuarial
losses (gains) .... 1 4 4 2 (5) (11)
Settlement gains ........... (104) (11) (29) - - -
Curtailment losses ......... 7 - - - - -
Special termination
benefit recognition 205 - 13 - - -
------------------------------------------------
Net periodic benefit cost $ 69 $ (40) $ (29) $ 119 $ 107 $ 96
===============================================================================
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 $428, $368 and $80, respectively, at December 31, 1999, and
$408, $364 and $87, respectively at December 31, 1998.
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 $86, $60 and $79 in 1999, 1998 and 1997, respectively.
Commencing in October 1997, the company's Savings Plus Plan contributions are
being 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 million. 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 $84, $58 and $53 in 1999, 1998 and
1997, respectively, including $49, $56 and $61 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 $33, $57 and $57 in 1999, 1998
and 1997, respectively.
The company made contributions to the ESOP of $64, $60 and $55 in 1999, 1998 and
1997, respectively, to satisfy ESOP debt service in excess of dividends received
by the ESOP. 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 year in
proportion to the total of current year and remaining debt service. The charge
(credit) to compensation expense was $36, $2 and $(8) in 1999, 1998 and 1997,
respectively. The ESOP shares as of December 31, 1999 and 1998, were as follows.
Thousands 1999 1998
- ------------------------------------------
Allocated shares 10,785 10,819
Unallocated shares 12,963 14,087
- ------------------------------------------
Total ESOP shares 23,748 24,906
==========================================
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, beginning with awards deferred in 1996, 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 man-
FS-28
Note 18. EMPLOYEE BENEFIT PLANS - Continued
agement incentive plans, excluding expense related to LTIP stock options, which
is discussed in Note 19, "Stock Options," were $41, $28 and $55 in 1999, 1998
and 1997, 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 $47, $51 and $116 in 1999, 1998 and
1997, respectively. In 2000, the maximum payout under the program increases to
10 percent.
Note 19. 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 SFAS No. 123, the company's net income and earnings
per share for 1999, 1998 and 1997 would have been the pro forma amounts shown
below.
1999 1998 1997
---------------------------
Net Income As reported $2,070 $1,339 $3,256
Pro forma $2,027 $1,294 $3,302
Earnings per share As reported - basic $3.16 $2.05 $4.97
- diluted $3.14 $2.04 $4.95
Pro forma - basic $3.09 $1.98 $5.04
- diluted $3.08 $1.97 $5.02
The effects of applying SFAS No. 123 in this pro forma disclosure are not
indicative of future amounts. SFAS 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.
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,
which are described in the following table. 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.
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 1999, 1998 and 1997 follows.
Weighted-
Average
Options Exercise
(000s) Price
- -----------------------------------------------------
Outstanding at December 31, 1996 7,277 $44.84
- -----------------------------------------------------
Granted 1,801 80.78
Exercised (710) 38.65
Forfeited (115) 72.18
- -----------------------------------------------------
Outstanding at December 31, 1997 8,253 $52.83
- -----------------------------------------------------
Granted 1,872 79.13
Exercised (796) 40.47
Forfeited (106) 80.70
- -----------------------------------------------------
Outstanding at December 31, 1998 9,223 $58.91
- -----------------------------------------------------
Granted 1,830 89.88
Exercised (1,298) 44.29
Forfeited (152) 83.12
- -----------------------------------------------------
Outstanding at December 31, 1999 9,603 $66.41
=====================================================
Exercisable at December 31
1997 6,502 $45.31
1998 7,367 $53.82
1999 7,839 $61.13
=====================================================
The weighted-average fair market value of options granted in 1999, 1998 and 1997
was $20.40, $21.10 and $17.64 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 1999, 1998 and 1997,
respectively: risk-free interest rate of 5.5, 4.5 and 6.1 percent; dividend
yield of 3.0, 3.1 and 2.8 percent; volatility of 20.1, 28.6 and 15.2 percent and
expected life of seven years in all years.
As of December 31, 1999, 9,602,900 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, 1999.
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
- -----------------------------------------------------------------------------------------
$31 to $ 41 614 2.12 $34.55 614 $34.55
41 to 51 3,128 4.72 45.18 3,128 45.18
51 to 61 15 6.31 56.49 15 56.49
61 to 71 766 6.83 66.25 766 66.25
71 to 81 3,299 8.34 79.91 3,297 79.91
81 to 91 1,758 9.80 89.80 19 82.80
91 to 101 23 9.55 92.14 - -
- -----------------------------------------------------------------------------------------
$31 to $101 9,603 6.91 $66.41 7,839 $61.13
=========================================================================================
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. When the options were issued in February
1996, vesting was contingent upon one of two conditions being met: By Decem-
FS-29
Note 19. STOCK OPTIONS - Continued
ber 31, 1998, the price of Chevron stock closed at or above $75.00 per share for
three consecutive business days or, alternatively, the company had the highest
annual total stockholder return of its competitor group for the years 1994
through 1998. The options vested in June 1997 when the share price performance
condition was met.
Options for 7,204,800 shares, including similar-termed LTIP awards, were granted
in 1996. Forfeitures of options for 820,050 shares and exercises of 4,171,300
reduced the outstanding option shares to 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 had reduced the
outstanding option shares to zero at March 31, 1999, the date of expiration.
Under APB Opinion No. 25, the company recorded expenses of $(2), $0 and $125 for
these options in 1999, 1998 and 1997, respectively.
The fair market value of each option share on the date of grant under SFAS 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 a new 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 were to vest in two years or, if the company had the highest total
stockholder return among its competitor group for the years 1994 through 1998,
in one year. Since the stockholders' return performance condition was not met,
the options vested 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,
at which date none was exercisable. The options expire on February 11, 2008.
Under APB Opinion No. 25, the company recorded expenses of $4 and $2 for these
options in 1999 and 1998, respectively.
The fair value of each option share on the date of grant under SFAS 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-Sholes 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.
Note 20. 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 19, "Stock Options").
The following table sets forth the computation of basic and diluted EPS.
1999 1998 1997
------------------------------------------------------------------------------------------------------
Net Shares Per-Share Net Shares Per-Share Net Shares Per-Share
Income (millions) Amount Income (millions) Amount Income (millions) Amount
- --------------------------------------------------------------------------------------------------------------------------------
Net income $ 2,070 $ 1,339 $ 3,256
Weighted-average common
shares outstanding 655.5 653.7 655.0
Dividend equivalents paid
on Chevron stock units 3 3 2
Deferred awards held
as Chevron stock units 1.0 1.2 1.3
- --------------------------------------------------------------------------------------------------------------------------------
BASIC EPS COMPUTATION $ 2,073 656.5 $3.16 $ 1,342 654.9 $2.05 $ 3,258 656.3 $4.97
Dilutive effects of
stock options 3.0 2.2 2.1
- --------------------------------------------------------------------------------------------------------------------------------
DILUTED EPS COMPUTATION $ 2,073 659.5 $3.14 $ 1,342 657.1 $2.04 $ 3,258 658.4 $4.95
================================================================================================================================
FS-30
Note 21.OTHER CONTINGENCIES AND COMMITMENTS
The U.S. federal income tax and California franchise tax liabilities of the
company have been settled through 1990 and 1991, respectively.
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, 1999, the company and its subsidiaries, as direct or indirect
guarantors, had contingent liabilities of $25 for notes of affiliated companies
and $362 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: 2000-$228; 2001-$297; 2002-$270; 2003-$253; 2004-$225;
2005 and after-$1,029. Total payments under the agreements were $258 in 1999,
$201 in 1998 and $243 in 1997.
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.
Areas in which the company has significant operations include the United States,
Canada, Australia, United Kingdom, Norway, Congo, Angola, Nigeria, Democratic
Republic of Congo, Papua New Guinea, China, Indonesia, Venezuela, Thailand and
Argentina. 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.
Note 22.EMPLOYEE TERMINATION BENEFITS AND OTHER RESTRUCTURING COSTS
The company recorded before-tax charges to income of $235 in 1999 for employee
termination benefits and other restructuring costs as part of a companywide
staff reduction program. The charge includes severance and other termination
benefits of $220 for 3,472 employees and $82 for employee and office relocation,
lease termination penalties, and other items. These charges were offset partly
by $67 of restructuring-related net pension settlement/curtailment gains for
payments made to terminated employees.
The staff reduction program affects primarily U.S.-based employees and is being
implemented in all of the company's operating segments across several business
functions. All identified employees will be separated by June 30, 2000.
Termination benefits for 3,070 of the 3,472 employees - accrued in accordance
with SFAS No. 88, "Employers' Accounting for Settlements and Curtailments of
Defined Benefit Plans and for Termination Benefits" - are payable from the
assets of the company's U.S. and Canadian pension plans. Payments to other
employees are from company funds. Accrual and payment activity for the employee
termination benefits is presented in the following table.
Restructuring Number of
Liability Employees
--------------------------------------------------------------
Balance at December 31, 1998 $ - -
Accruals 220 3,472
Cash Payments (135) 2,157
----------------------------
Balance at December 31, 1999 $ 85 1,315
==============================================================
Of the $82 for relocations, lease termination penalties and other costs,
approximately 13 percent remained unpaid at the end of 1999. These charges and
the restructuring-related pension gains were classified mainly as either
"operating expense" or "selling, general and administrative expense." Items are
either accrued or recognized as incurred under the guidelines of EITF Issue No.
94-3, "Liability Recognition for Certain Employee Termination Benefits and Other
Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)"
or SFAS No. 88, as applicable.
The company's net income for 1999 also included its $25 share of a restructuring
charge recorded by Caltex.
FS-31
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" (SFAS 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, 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, 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 (50 percent prior
to April 1997) equity share of Tengizchevroil (TCO), an exploration and
production partnership operating in the Republic of Kazakhstan.
TABLE I - COSTS INCURRED IN EXPLORATION, PROPERTY ACQUISITIONS AND DEVELOPMENT(1)
Consolidated Companies Affiliated Companies
Millions of dollars U.S. Africa Other Total CPI TCO Worldwide
--------------------------------------------------------------------------------
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
============================================================================================================================
YEAR ENDED DECEMBER 31, 1997
Exploration
Wells $ 278 $ 99 $ 149 $ 526 $ 2 $ - $ 528
Geological and geophysical 39 31 59 129 16 - 145
Rentals and other 43 17 65 125 - - 125
- ----------------------------------------------------------------------------------------------------------------------------
Total exploration 360 147 273 780 18 - 798
- ----------------------------------------------------------------------------------------------------------------------------
Property acquisitions(2)
Proved(4) 3 6 75 84 - - 84
Unproved 101 - 23 124 - - 124
- ----------------------------------------------------------------------------------------------------------------------------
Total property acquisitions 104 6 98 208 - - 208
- ----------------------------------------------------------------------------------------------------------------------------
Development 918 461 529 1,908 159 152 2,219
- ----------------------------------------------------------------------------------------------------------------------------
TOTAL COSTS INCURRED $1,382 $ 614 $ 900 $2,896 $177 $152 $3,225
============================================================================================================================
(1) Includes costs incurred whether capitalized or charged to earnings. 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.
FS-32
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
- ---------------------------------------------------------------------------------------------------------------------------
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
===========================================================================================================================
AT DECEMBER 31, 1997
Unproved properties .......................... $ 370 $ 58 $ 236 $ 664 $ - $ 378 $ 1,042
Proved properties and related producing assets 16,284 3,303 5,644 25,231 1,112 491 26,834
Support equipment ............................ 503 209 310 1,022 578 209 1,809
Deferred exploratory wells ................... 120 46 58 224 - - 224
Other uncompleted projects ................... 826 549 821 2,196 338 153 2,687
- ---------------------------------------------------------------------------------------------------------------------------
GROSS CAPITALIZED COSTS ...................... 18,103 4,165 7,069 29,337 2,028 1,231 32,596
- ---------------------------------------------------------------------------------------------------------------------------
Unproved properties valuation ................ 153 42 98 293 - - 293
Proved producing properties -
Depreciation and depletion .................. 11,657 1,459 2,521 15,637 626 51 16,314
Future abandonment and restoration .......... 926 304 177 1,407 44 6 1,457
Support equipment depreciation ............... 315 79 130 524 343 53 920
- ---------------------------------------------------------------------------------------------------------------------------
Accumulated provisions ....................... 13,051 1,884 2,926 17,861 1,013 110 18,984
- ---------------------------------------------------------------------------------------------------------------------------
NET CAPITALIZED COSTS ........................ $ 5,052 $ 2,281 $ 4,143 $11,476 $ 1,015 $ 1,121 $13,612
===========================================================================================================================
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 1999, 1998 and 1997 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
SFAS No. 69, income taxes in Table III are based on statutory tax rates,
reflecting allowable deductions and tax credits. Interest income and expense is
excluded from the results reported in Table III and from the net income amounts
on page FS-7.
FS-33
TABLE III - RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES (1) - Continued
Consolidated Companies Affiliated Companies
---------------------------------------- ----------------------
Millions of dollars U.S. Africa Other Iotal CPI TCO Worldwide
- --------------------------------------------------------------------------------------------------------------------------------
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 (expense)income(2).................. (307) (53) 5 (355) (2) (9) (366)
- --------------------------------------------------------------------------------------------------------------------------------
Results before income taxes ............. 810 1,249 863 2,922 282 212 3,416
Income tax expense ....................... (275) (848) (416) (1,539) (143) (63) (1,745)
- --------------------------------------------------------------------------------------------------------------------------------
RESULTS OF PRODUCING OPERATIONS .......... $ 535 $ 401 $ 447 $ 1,383 $ 139 $ 149 $ 1,671
================================================================================================================================
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)................. 96 48 85 229 2 (7) 224
- --------------------------------------------------------------------------------------------------------------------------------
Results before income taxes ............. 548 670 452 1,670 209 53 1,932
Income tax expense ....................... (178) (328) (323) (829) (102) (16) (947)
- --------------------------------------------------------------------------------------------------------------------------------
RESULTS OF PRODUCING OPERATIONS .......... $ 370 $ 342 $ 129 $ 841 $ 107 $ 37 $ 985
================================================================================================================================
YEAR ENDED DECEMBER 31, 1997
Revenues from net production
Sales ................................... $ 1,931 $ 1,782 $ 899 $ 4,612 $ 43 $ 283 $ 4,938
Transfers ............................... 1,799 273 656 2,728 634 - 3,362
- --------------------------------------------------------------------------------------------------------------------------------
Total ......... 3,730 2,055 1,555 7,340 677 283 8,300
Production expenses ...................... (1,272) (297) (278) (1,847) (197) (79) (2,123)
Proved producing properties: depreciation,
depletion and abandonment provision ..... (737) (256) (311) (1,304) (130) (37) (1,471)
Exploration expenses ..................... (227) (66) (200) (493) (16) - (509)
Unproved properties valuation ............ (16) (7) (10) (33) - - (33)
Other income (expense)(2)................. 87 (46) 196 237 10 (13) 234
- --------------------------------------------------------------------------------------------------------------------------------
Results before income taxes .............. 1,565 1,383 952 3,900 344 154 4,398
Income tax expense ...................... (555) (939) (365) (1,859) (173) (46) (2,078)
- --------------------------------------------------------------------------------------------------------------------------------
RESULTS OF PRODUCING OPERATIONS .......... $ 1,010 $ 444 $ 587 $ 2,041 $ 171 $ 108 $ 2,320
================================================================================================================================
(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, natural gas contract
settlements, 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., equity earnings of Dynegy Inc., net income from
technical and operating service agreements) and items identified in the
Management's Discussion and Analysis on page FS-7.
FS-34
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
- ------------------------------------------------------------------------------------------------------------------------------
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
==============================================================================================================================
YEAR ENDED DECEMBER 31, 1997
Average sales prices
Liquids, per barrel ................................... $17.33 $18.15 $16.88 $17.53 $15.35 $10.69 $16.82
Natural gas, per thousand cubic feet .................. 2.42 - 2.35 2.40 - 0.51 2.35
Average production costs, per barrel ................... 5.47 2.61 2.89 4.17 4.48 2.78 4.22
==============================================================================================================================
Average sales price for liquids ($/Bbl)
December 1999 ......................................... $22.25 $24.88 $24.06 $23.68 $23.68 $11.55 $22.65
December 1998 ......................................... 8.86 9.55 9.04 9.17 8.33 3.69 8.58
December 1997 ......................................... 15.63 15.60 15.09 15.48 14.16 9.40 14.91
==============================================================================================================================
Average sales price for natural gas ($/MCF)
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
December 1997 ......................................... 2.25 - 2.76 2.31 - 0.63 2.26
==============================================================================================================================
(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.
TABLE IV - RESERVE QUANTITY INFORMATION
The company's estimated net proved underground oil and gas reserves and changes
thereto for the years 1999, 1998 and 1997 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 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.
In June 1997, Chevron assumed operatorship under a risked service agreement for
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,
1999, had recorded 54 million barrels of proved crude oil reserves.
No reserve quantities have been recorded for the company's other service
agreement in Venezuela, which began in 1996, involving the Boscan Field.
FS-35
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 World- Consolidated Companies Affiliates World-
---------------------------- ------------ --------------------------- ------------
U.S. Africa Other Total CPI TCO wide U.S. Africa Other Total CPI TCO wide
- ---------------------------------------------------------------------------------------------------------------------------------
RESERVES AT
JANUARY 1, 1997 ........ 1,149 1,032 482 2,663 566 1,135 4,364 5,275 293 3,135 8,703 152 1,462 10,317
Changes attributable to:
Revisions ............. 8 (16) 38 30 37 92 159 (98) (67) 211 46 19 120 185
Improved recovery 139 72 7 218 27 - 245 111 - 1 112 5 - 117
Extensions
and discoveries .... 57 156 14 227 4 - 231 470 - 12 482 2 - 484
Purchases(1) .......... - - 51 51 - - 51 3 - 1 4 - - 4
Sales(2) .............. (32) - (1) (33) - (120) (153) (95) - (7) (102) - (156) (258)
Production ............. (125) (113) (72) (310) (56) (25) (391) (675) (3) (166) (844) (17) (25) (886)
- ---------------------------------------------------------------------------------------------------------------------------------
RESERVES AT
DECEMBER 31, 1997 ...... 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
=================================================================================================================================
Developed reserves
- ---------------------------------------------------------------------------------------------------------------------------------
At January 1, 1997 1,027 658 281 1,966 448 500 2,914 4,727 293 1,634 6,654 136 643 7,433
At December 31, 1997 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
=================================================================================================================================
(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.
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 SFAS 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 SFAS 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-36
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
- ---------------------------------------------------------------------------------------------------------------------------------
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
=================================================================================================================================
AT DECEMBER 31, 1997
Future cash inflows from production ... $ 28,270 $ 16,560 $ 16,860 $ 61,690 $ 9,240 $ 10,890 $ 81,820
Future production and development costs (14,030) (4,810) (5,090) (23,930) (6,340) (6,550) (36,820)
Future income taxes ................... (4,710) (6,630) (4,330) (15,670) (1,390) (600) (17,660)
- ---------------------------------------------------------------------------------------------------------------------------------
Undiscounted future net cash flows .... 9,530 5,120 7,440 22,090 1,510 3,740 27,340
10 percent midyear annual discount for
timing of estimated cash flows ....... (3,910) (1,780) (3,290) (8,980) (650) (2,710) (12,340)
- ---------------------------------------------------------------------------------------------------------------------------------
Standardized Measure of Discounted
Future Net Cash Flows ................ $ 5,620 $ 3,340 $ 4,150 $ 13,110 $ 860 $ 1,030 $ 15,000
=================================================================================================================================
TABLE VI - CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED RESERVES
Consolidated Companies Affiliated Companies Worldwide
------------------------------ -------------------------- --------------------------
Millions of dollars 1999 1998 1997 1999 1998 1997 1999 1998 1997
- ------------------------------------------------------------------------------------------------------------------------
PRESENT VALUE AT JANUARY 1 $ 8,460 $13,110 $22,270 $ 810 $1,890 $2,850 $ 9,270 $15,000 $25,120
- ------------------------------------------------------------------------------------------------------------------------
Sales and transfers of oil and gas
produced, net of production costs (5,385) (3,294) (5,493) (679) (429) (684) (6,064) (3,723) (6,177)
Development costs incurred 1,425 1,652 1,908 330 276 311 1,755 1,928 2,219
Purchases of reserves 2,811 208 173 - - - 2,811 208 173
Sales of reserves (344) (347) (238) - - (140) (344) (347) (378)
Extensions, discoveries and improved
recovery, less related costs 2,886 813 2,161 385 49 104 3,271 862 2,265
Revisions of previous
quantity estimates (503) 262 535 84 280 980 (419) 542 1,515
Net changes in prices, development
and production costs 25,457 (11,321) (20,440) 6,938 (2,159) (3,521) 32,395 (13,480) (23,961)
Accretion of discount 1,165 2,096 3,673 135 289 516 1,300 2,385 4,189
Net change in income tax (14,332) 5,281 8,561 (2,503) 614 1,474 (16,835) 5,895 10,035
- ------------------------------------------------------------------------------------------------------------------------
Net change for the year 13,180 (4,650) (9,160) 4,690 (1,080) (960) 17,870 (5,730) (10,120)
- ------------------------------------------------------------------------------------------------------------------------
PRESENT VALUE AT DECEMBER 31 $21,640 $ 8,460 $13,110 $5,500 $ 810 $1,890 $27,140 $ 9,270 $15,000
========================================================================================================================
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-37
FIVE-YEAR FINANCIAL SUMMARY (1)
Millions of dollars, except per-share amounts 1999 1998 1997 1996 1995
- ----------------------------------------------------------------------------------------------------------------------------
CONSOLIDATED STATEMENT OF INCOME DATA
REVENUES
Sales and other operating revenues
Refined products ............................................ $ 13,742 $ 11,461 $ 15,586 $ 15,785 $ 13,471
Crude oil ................................................... 10,078 7,781 11,296 12,397 9,376
Natural gas ................................................. 2,256 2,104 2,568 3,299 2,019
Natural gas liquids ......................................... 432 322 553 1,167 1,285
Other petroleum ............................................. 1,115 1,063 1,118 1,184 1,144
Chemicals ................................................... 3,544 3,054 3,520 3,422 3,758
Coal and other minerals ..................................... 360 399 359 340 358
Excise taxes ................................................ 3,910 3,756 5,587 5,202 4,988
Corporate and other ......................................... 11 3 9 (14) (89)
- ----------------------------------------------------------------------------------------------------------------------------
Total sales and other operating revenues ..................... 35,448 29,943 40,596 42,782 36,310
Income from equity affiliates ................................ 526 228 688 767 553
Other income ................................................. 612 386 679 344 219
- ----------------------------------------------------------------------------------------------------------------------------
TOTAL REVENUES ............................................... 36,586 30,557 41,963 43,893 37,082
COSTS, OTHER DEDUCTIONS AND INCOME TAXES ..................... 34,516 29,218 38,707 41,286 36,152
INCOME BEFORE CUMULATIVE EFFECT
OF CHANGES IN ACCOUNTING PRINCIPLES ......................... $ 2,070 $ 1,339 $ 3,256 $ 2,607 $ 930
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES ........ - - - - -
- ----------------------------------------------------------------------------------------------------------------------------
NET INCOME ................................................... $ 2,070 $ 1,339 $ 3,256 $ 2,607 $ 930
============================================================================================================================
PER SHARE OF COMMON STOCK:
INCOME BEFORE CUMULATIVE EFFECT
OF CHANGES IN ACCOUNTING PRINCIPLES - BASIC ................. $ 3.16 $ 2.05 $ 4.97 $ 3.99 $ 1.43
- DILUTED ............... $ 3.14 $ 2.04 $ 4.95 $ 3.98 $ 1.43
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES ........ - - - - -
- ----------------------------------------------------------------------------------------------------------------------------
NET INCOME PER SHARE OF COMMON STOCK - BASIC ................. $ 3.16 $ 2.05 $ 4.97 $ 3.99 $ 1.43
- DILUTED ............... $ 3.14 $ 2.04 $ 4.95 $ 3.98 $ 1.43
============================================================================================================================
CASH DIVIDENDS PER SHARE ..................................... $ 2.48 $ 2.44 $ 2.28 $ 2.08 $ 1.925
============================================================================================================================
CONSOLIDATED BALANCE SHEET DATA (AT DECEMBER 31)
Current assets ............................................... $ 8,297 $ 6,297 $ 7,006 $ 7,942 $ 7,867
Properties, plant and equipment (net) ........................ 25,317 23,729 22,671 21,496 21,696
Total assets ................................................. 40,668 36,540 35,473 34,854 34,330
Short-term debt .............................................. 3,434 3,165 1,637 2,706 3,806
Other current liabilities .................................... 5,455 4,001 5,309 6,201 5,639
Long-term debt and capital lease obligations ................. 5,485 4,393 4,431 3,988 4,521
Stockholders equity .......................................... 17,749 17,034 17,472 15,623 14,355
Per share .................................................. $ 27.04 $ 26.08 $ 26.64 $ 23.92 $ 22.01
============================================================================================================================
SELECTED DATA
Return on average stockholders equity ........................ 11.9% 7.8% 19.7% 17.4% 6.4%
Return on average capital employed ........................... 9.4% 6.7% 15.0% 12.7% 5.3%
Total debt/total debt plus equity ............................ 33.4% 30.7% 25.8% 30.0% 36.7%
Capital and exploratory expenditures (2) ..................... $ 6,133 $ 5,314 $ 5,541 $ 4,840 $ 4,800
Common stock price - High ............................... $104 15/16 $90 3/16 $89 3/16 $68 3/8 $53 5/8
- Low ................................ $73 1/8 $67 3/4 $61 3/4 $51 $43 3/8
- Year-End ........................... $86 5/8 $82 15/16 $77 $65 $52 3/8
Common shares outstanding at year-end (in thousands) ......... 656,345 653,026 655,931 653,086 652,327
Weighted-average shares outstanding for the year (in thousands 655,468 653,667 654,991 652,769 652,084
Number of employees at year-end (3) 36,490 39,191 39,362 40,820 43,019
============================================================================================================================
(1) Comparability between years is affected by changes in accounting methods:
1995 and subsequent years reflect adoption of Statement of Financial
Accounting Standards (SFAS) No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed of."
(2) Includes equity in affiliates expenditures. $ 782 $ 994 $ 1,174 $ 983 $ 912
(3) Includes service station personnel.
FS-38
CALTEX GROUP OF COMPANIES
COMBINED FINANCIAL STATEMENTS
December 31, 1999
C-1
CALTEX GROUP OF COMPANIES
COMBINED FINANCIAL STATEMENTS
DECEMBER 31, 1999
INDEX
Page
General Information C-3 - C-5
Independent Auditors' Report C-6
Combined Balance Sheet C-7 - C-8
Combined Statement of Income C-9
Combined Statement of Comprehensive Income C-9
Combined Statement of Stockholders' Equity C-10
Combined Statement of Cash Flows C-11
Notes to Combined Financial Statements C-12 - C-24
Note: Financial statement schedules are omitted as permitted by Rule 4.03 and
Rule 5.04 of Regulation S-X.
C-2
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 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
55 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 1999, it had total assets of
$7.9 billion, sales of 1.8 million barrels of crude oil and petroleum products
per day, and total revenues of $13.8 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
1999, 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 11 refineries with equity
refining capacity of approximately 850,000 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 1999, CPI had total assets of $2.4 billion, which generated total
revenues of $1.1 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 1999 was over 746,000 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 1999, CPI had approximately 5,900 employees, all located in
Indonesia.
American Overseas Petroleum Limited (AOPL)
- -----------------------------------------
AOPL and its subsidiary provide services for CPI and manage certain
exploration, production operations, and geothermal and power generation projects
in Indonesia in which Chevron and Texaco have interests, but not necessarily
jointly. At year-end 1999, AOPL had approximately 213 employees, of which 8%
were located in the United States.
C-3
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 $2.2 billion and $2.0 billion,
before the effects of related net interest rate swaps of $0.4 billion and $0.5
billion, at December 31, 1999 and 1998, 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, 1999 and 1998, a hypothetical change in the
interest rates of 2% would change net income by approximately $25 million and
$21 million in 1999 and 1998, 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 sales contracts of
approximately $127 million at December 31, 1999, and net open petroleum
derivative purchase contracts of approximately $68 million at December 31, 1998.
As a sensitivity for these contracts, a hypothetical 10% change in crude oil and
petroleum product prices would change net income by approximately $9 million and
$5 million in 1999 and 1998, 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 $279 million and $370 million at
December 31, 1999 and 1998 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 1999 or 1998.
C-4
CALTEX GROUP OF COMPANIES
GENERAL INFORMATION
New Accounting Standard
Statement of Financial Accounting Standards No. 133 (SFAS No. 133),
"Accounting for Derivative Instruments and Hedging Activities", was issued by
the Financial Accounting Standards Board (FASB) in 1998. SFAS No. 133
establishes new accounting rules and disclosure requirements for derivative
instruments and hedge transactions. In June 1999, the FASB issued SFAS No. 137,
which deferred the effective date of SFAS 133. The Group will adopt SFAS No. 133
effective January 1, 2001, and is currently assessing the effects of adoption on
its results of operations and financial position.
Year 2000 Compliance
The Group and its subsidiaries and affiliates experienced no major
disruptions or other system or equipment problems resulting from the Year 2000
(Y2K) issue. During the year 1999 and the first few weeks of 2000, the Group,
including its share of affiliates, spent approximately $17 million on Y2K
issues, bringing the total spent since 1998 to approximately $32 million. The
Group does not anticipate spending any significant additional funds on Y2K
related activities.
C-5
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, 1999 and 1998, 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, 1999, 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, 1999 and 1998 and the results of its
operations and its cash flows for each of the years in the three-year period
ended December 31, 1999, in conformity with accounting principles generally
accepted in the United States of America.
As discussed in Note 12 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 LLP
------------
KPMG
Singapore
February 7, 2000
C-6
CALTEX GROUP OF COMPANIES
COMBINED BALANCE SHEET
ASSETS
As of December 31,
------------------------
(Millions of U.S. dollars)
1999 1998
------- -------
Current assets:
Cash and cash equivalents, including time deposits of
$12 in 1999 and $17 in 1998 $ 225 $ 178
Marketable securities 117 106
Accounts and notes receivable, less allowance for doubtful accounts of $43
in 1999 and $31 in 1998:
Trade 1,048 629
Affiliates 541 256
Other 132 194
--------- -------
1,721 1,079
Inventories:
Crude oil 170 167
Petroleum products 427 418
Materials and supplies 26 26
--------- -------
623 611
Deferred income taxes 19 -
--------- -------
Total current assets 2,705 1,974
Investments and advances:
Equity in affiliates 2,127 2,254
Miscellaneous investments and long-term receivables,
less allowance of $24 in 1999 and $21 in 1998 96 109
--------- -------
Total investments and advances 2,223 2,363
Property, plant, and equipment, at cost:
Producing 4,732 4,386
Refining 1,350 1,319
Marketing 3,194 3,125
Other 14 15
--------- -------
9,290 8,845
Accumulated depreciation, depletion and amortization (4,120) (3,747)
--------- -------
Net property, plant and equipment 5,170 5,098
Prepaid and deferred charges 211 223
--------- -------
Total assets $ 10,309 $ 9,658
========= =======
See accompanying notes to combined financial statements.
C-7
CALTEX GROUP OF COMPANIES
COMBINED BALANCE SHEET
LIABILITIES AND STOCKHOLDERS' EQUITY
As of December 31,
------------------------
(Millions of U.S. dollars)
1999 1998
------- ------
Current liabilities:
Short-term debt $ 1,588 $ 1,475
Accounts payable:
Trade and other 1,440 1,005
Stockholders 44 28
Affiliates 61 39
--------- -------
1,545 1,072
Accrued liabilities 163 181
Deferred income taxes - 25
Estimated income taxes 99 86
--------- -------
Total current liabilities 3,395 2,839
Long-term debt 1,054 930
Employee benefit plans 85 122
Deferred credits and other non-current liabilities 1,271 1,130
Deferred income taxes 206 208
Minority interest in subsidiary companies 23 31
--------- -------
Total 6,034 5,260
Stockholders' equity:
Common stock 355 355
Capital in excess of par value 2 2
Retained earnings 4,117 4,151
Accumulated other comprehensive loss (199) (110)
--------- -------
Total stockholders' equity 4,275 4,398
--------- -------
Total liabilities and stockholders' equity $ 10,309 $ 9,658
========= =======
See accompanying notes to combined financial statements.
C-8
CALTEX GROUP OF COMPANIES
COMBINED STATEMENT OF INCOME
Year ended December 31,
------------------------------------------
(Millions of U.S. dollars)
1999 1998 1997
--------- --------- --------
Revenues:
Sales and other operating revenues(1) $ 14,583 $ 11,300 $ 15,262
Gain on sale of investment in affiliate 18 - -
Income in equity affiliates 252 108 390
Dividends, interest and other income 62 97 47
--------- --------- ---------
Total revenues 14,915 11,505 15,699
Costs and deductions:
Cost of sales and operating expenses(2) 12,775 9,541 13,251
Selling, general and administrative expenses 582 676 580
Depreciation, depletion and amortization 459 431 421
Maintenance and repairs 154 147 143
Foreign exchange - net 11 16 (55)
Interest expense 152 172 146
Minority interest 2 3 3
--------- --------- ---------
Total costs and deductions 14,135 10,986 14,489
--------- --------- ---------
Income before income taxes 780 519 1,210
Provision for income taxes 390 326 364
--------- --------- ---------
Income before cumulative effect of accounting change 390 193 846
Cumulative effect of accounting change (no tax benefit) - (50) -
--------- --------- ---------
Net income $ 390 $ 143 $ 846
========= ========= =========
(1) Includes sales to:
Stockholders $1,916 $1,333 $1,562
Affiliates 3,970 2,121 2,906
(2) Includes purchases from:
Stockholders $1,491 $1,233 $2,041
Affiliates 1,121 1,353 1,701
CALTEX GROUP OF COMPANIES
COMBINED STATEMENT OF COMPREHENSIVE INCOME
Year ended December 31,
-----------------------------------------
(Millions of U.S. dollars)
1999 1998 1997
------- ------- -------
Net income $ 390 $ 143 $ 846
Other comprehensive income:
Currency translation adjustments:
Change during the year (5) (10) (84)
Reclassification to net income for sale of investment in affiliate (63) - -
Unrealized gains/(losses) on investments:
Change during the year 32 8 (23)
Reclassification of gains included in net income (64) - (3)
Related income tax benefit (expense) 11 (1) 14
--------- --------- ---------
Total other comprehensive loss (89) (3) (96)
--------- --------- ---------
Comprehensive income $ 301 $ 140 $ 750
========= ========= =========
See accompanying notes to combined financial statements.
C-9
CALTEX GROUP OF COMPANIES
COMBINED STATEMENT OF STOCKHOLDERS' EQUITY
Year ended December 31,
------------------------------------------
(Millions of U.S. dollars)
1999 1998 1997
--------- ------- -------
Common stock and capital in excess of par value $ 357 $ 357 $ 357
========= ========= =========
Retained earnings:
Balance at beginning of year $ 4,151 $ 4,342 $ 3,910
Net income 390 143 846
Cash dividends (424) (334) (414)
--------- --------- ---------
Balance at end of year $ 4,117 $ 4,151 $ 4,342
========= ========= =========
Accumulated other comprehensive loss:
Cumulative translation adjustments:
Balance at beginning of year $ (130) $ (120) $ (36)
Change during the year (5) (10) (84)
Reclassification to net income for sale
of investment in affiliate (63) - -
--------- --------- ---------
Balance at end of year $ (198) $ (130) $ (120)
========= ========= =========
Unrealized holding gain on investments, net of tax:
Balance at beginning of year $ 20 $ 13 $ 25
Change during the year 19 7 (11)
Reclassification of gains included in net income (40) - (1)
--------- --------- ---------
Balance at end of year $ (1) $ 20 $ 13
========= ========= =========
Accumulated other comprehensive loss - end of year $ (199) $ (110) $ (107)
========= ========= =========
Total stockholders' equity - end of year $ 4,275 $ 4,398 $ 4,592
========= ========= =========
See accompanying notes to combined financial statements.
C-10
CALTEX GROUP OF COMPANIES
COMBINED STATEMENT OF CASH FLOWS
Year ended December 31,
--------------------------------------
(Millions of U.S. dollars)
1999 1998 1997
----- ----- -----
Operating activities:
Net income $ 390 $ 143 $ 846
Reconciliation to net cash provided by operating activities:
Depreciation, depletion and amortization 459 431 421
Dividends less than income in equity affiliates (181) (8) (347)
Net losses on asset disposals/write-downs 34 50 16
Deferred income taxes (58) 92 (51)
Prepaid charges and deferred credits 154 59 103
Changes in operating working capital (190) 316 (150)
Gain on sale of investment in affiliate (18) - -
Other (25) 35 (13)
--------- --------- ---------
Net cash provided by operating activities 565 1,118 825
Investing activities:
Capital expenditures (580) (761) (905)
Investments in and advances to affiliates (1) (211) (10)
Purchase of investment instruments (11) (114) (39)
Sale of investment instruments - 90 73
Proceeds from sale of investments in affiliates 249 - -
Proceeds from asset sales 16 9 156
--------- --------- ---------
Net cash used for investing activities (327) (987) (725)
Financing activities:
Debt with terms in excess of three months :
Borrowings 959 849 845
Repayments (824) (701) (628)
Net increase (decrease) in other debt 118 (22) 323
Funding provided by minority interest - 17 -
Dividends paid, including minority interest (424) (334) (414)
--------- --------- ----------
Net cash (used for) provided by financing activities (171) (191) 126
Effect of exchange rate changes on cash and cash equivalents (20) (44) (150)
--------- --------- ---------
Cash and cash equivalents:
Net change during the year 47 (104) 76
Beginning of year balance 178 282 206
--------- --------- ---------
End of year balance $ 225 $ 178 $ 282
========= ========= =========
See accompanying notes to combined financial statements.
C-11
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. Prior to October 1, 1997,
the Group used the local currency as the functional currency for its affiliates
in Korea and Japan due to the regulatory environments in those countries. The
regulatory environments in Korea and Japan changed in 1997. The Group concluded
that deregulation in Korea and Japan represented a significant change in
economic facts and circumstances. Accordingly, effective October 1, 1997, the
Group changed the functional currency for its affiliates in Japan and Korea from
the local currency to the U. S. dollar. The change in functional currency was
applied on a prospective basis.
Estimates: The preparation of financial statements in conformity with 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. Depreciation, depletion and
amortization expenses for capitalized costs relating to producing properties,
including intangible development costs, are determined using the
unit-of-production method. All other assets are depreciated by class on a
straight-line basis using rates based upon the estimated useful life of each
class.
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.
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, and impaired assets held for sale are recorded at their
fair value less cost to sell.
C-12
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
Note 1 - Summary of significant accounting policies - continued
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 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.
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.
C-13
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
Note 1 - Summary of significant accounting policies - continued
Reclassifications: Certain reclassifications have been made to the prior year
amounts of sales and cost of sales in the combined statement of income to
conform to the 1999 presentation of gains and losses related to certain
commodity contracts.
Note 2 - Asset Sale
In 1997 Caltex Trading and Transport Corporation, a subsidiary of the
Group, sold for cash its 40% interest in its Bahrain refining joint venture plus
related assets at net book value of approximately $140 million.
Note 3 - Inventories
The reported value of inventory at December 31 1999, was less than its
current cost by approximately $104 million. The reported value of inventory at
December 31, 1998 approximated its current cost. In 1998 and 1997, certain
inventories were recorded at market, which was lower than the LIFO carrying
value. Adjustments to market reduced net income $18 million in 1998 and $36
million in 1997. The market valuation adjustment reserves established in prior
years were eliminated as market prices improved in 1999 and the physical units
of inventory were sold. Elimination of these reserves increased net income in
1999 by $71 million. At December 31, 1999, inventories were reported at LIFO
carrying cost.
Inventory quantities valued on the LIFO basis were reduced at certain
locations during the periods presented. Such inventory reductions increased net
income in 1999 by $41 million, and decreased net income by $4 million and $5
million (net of related market valuation adjustments of $1 million and $14
million) in 1998 and 1997, respectively.
Note 4 - Equity in affiliates
Investments in affiliates at equity include the following:
As of December 31,
--------------------------
(Millions of U.S.
dollars)
Equity % 1999 1998
-------- ---- ----
Caltex Australia Limited 50% $ 260 $ 324
Koa Oil Company, Limited (sold August, 1999) 50% - 298
LG-Caltex Oil Corporation 50% 1,441 1,170
Star Petroleum Refining Company, Ltd. 64% 269 304
All other Various 157 158
--------- ---------
$ 2,127 $ 2,254
========= =========
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.
C-14
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
Note 4 - Equity in affiliates - continued
On December 31, 1997, Caltex Australia Limited (CAL), then a subsidiary of
the Group, acquired the remaining 50% of Australian Petroleum Pty. Limited
(APPL) from a subsidiary of Pioneer International Limited, for approximately
$186 million in cash plus the issuance of an additional 90 million shares of CAL
stock. As a result of this transaction, the Group's equity in CAL declined from
75% to 50% and its indirect equity in APPL increased to 50% from 37.5%. This
transaction was recorded as a purchase. CAL is now classified as an affiliate
and the individual assets and liabilities are excluded from the Group's
consolidated financial statements.
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, it is likely that this
requirement will be 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):
100% Equity Share
---------------------- ----------------------
1999 1998 1999 1998
--------- --------- -------- ---------
Current assets $ 3,005 $ 3,689 $ 1,535 $ 1,855
Other assets 6,333 7,689 3,287 4,004
Current liabilities 3,351 3,547 1,816 1,795
Other liabilities 1,883 3,505 937 1,866
------- -------- ------- -------
Net worth $ 4,104 $ 4,326 $ 2,069 $ 2,198
======= ======== ======= =======
100% Equity Share
---------------------------- -----------------------------
1999 1998 1997 1999 1998 1997
-------- -------- --------- --------- --------- ---------
Operating revenues $ 12,796 $ 11,811 $ 14,669 $ 6,511 $ 5,968 $ 7,452
Operating income 726 1,101 1,078 358 539 532
Net income 539 193 853 252 58 390
Cash dividends received from these affiliates were $71 million, $50
million, and $43 million in 1999, 1998, and 1997, respectively.
The summarized combined financial information shown above includes the
cumulative effect of the accounting change in 1998 as described in Note 12.
Retained earnings as of December 31, 1999 and 1998 includes $1.4 billion
which represents the Group's share of undistributed earnings of affiliates at
equity.
Note 5 - 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, 1999
and 1998 were 6.5% and 7.3%, respectively. Unutilized lines of credit available
for short-term financing totaled $0.8 billion as of December 31, 1999.
C-15
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
Note 6 - Long-term debt
Long-term debt, with related interest rates for 1999 and 1998 consist of
the following:
As of December 31,
----------------------
(Millions of U.S.
dollars)
1999 1998
---- ----
U.S. dollar debt:
Variable interest rate loans with average rates
of 6.4% and 5.5%, due 2001-2009 $ 481 $ 454
Fixed interest rate term loans with average rates of 6.1%
and 6.4%, due 2001-2004 246 130
Australian dollar debt:
Fixed interest rate loan with 12.4% rate due 2001 205 211
New Zealand dollar debt:
Variable interest rate loans with average rates
of 5.6% and 5.0%, due 2001-2003 70 78
Fixed interest rate loan with 8.09% rate - 5
Malaysian ringgit debt:
Fixed interest rate loans with average rates of 7.81%
and 9.16%, due 2001 24 33
South African rand debt:
Fixed interest rate loan with 17.8% rate due 2003 8 8
Other - variable interest rate loans with average rates
of 15.3% and 5.8%, due 2001-2007 20 11
-------- -------
$ 1,054 $ 930
======== =======
Aggregate maturities of long-term debt by year are as follows (in millions
of U.S. dollars): 2000 - $148 (included in short-term debt); 2001 - $508; 2002 -
$333; 2003 - $110; 2004 - $21; and thereafter - $82.
Note 7 - Operating leases
The Group has operating leases involving various marketing assets for which
net rental expense was $112 million, $103 million, and $105 million in 1999,
1998, and 1997, 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): 2000 - $66; 2001 - $42; 2002 - $30; 2003 - $13; 2004 - $10; and 2005
and thereafter - $37.
C-16
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
Note 8 - 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, and inclusive of affiliates at equity.
As of December 31,
----------------------------------------
(Millions of U.S. dollars)
Other Post-retirement
Pension Benefits Benefits
------------------ ------------------
1999 1998 1999 1998
------ ------ ------ ------
Change in benefit obligations:
Benefit obligation at January 1, $ 400 $ 405 $ 79 $ 64
Service cost 23 19 1 2
Interest cost 26 31 8 6
Actuarial (gain) loss 7 32 (5) 11
Benefits paid (39) (72) (4) (4)
Settlements and curtailments (117) (26) - 5
Foreign exchange rate changes 7 11 (1) (5)
------ ------ ------ -----
Benefit obligation at December 31, $ 307 $ 400 $ 78 $ 79
====== ====== ====== =====
Change in plan assets:
Fair value at January 1, $ 333 $ 322 $ - $ -
Actual return on plan assets 37 47 - -
Group contribution 42 62 4 4
Benefits paid (39) (72) (4) (4)
Settlements (105) (26) - -
Foreign exchange rate changes 11 - - -
----- ----- ------ -----
Fair value at December 31, $ 279 $ 333 $ - $ -
===== ===== ====== =====
Accrued benefit costs:
Funded status $ (28) $ (67) $ (78) $ (79)
Unrecognized net transition liability 2 4 - -
Unrecognized net actuarial losses 23 11 17 23
Unrecognized prior service costs 7 9 - -
----- ----- ------ -----
Prepaid (accrued) benefit cost recognized $ 4 $ (43) $ (61) $ (56)
===== ===== ====== =====
Amounts recognized in the Combined Balance Sheet:
Prepaid benefit cost $ 32 $ 27 $ - $ -
Equity in affiliates - (30) - -
Accrued benefit liability (28) (40) (61) (56)
----- ----- ------- ------
Prepaid (accrued) benefit cost recognized $ 4 $ (43) $ (61) $ (56)
===== ===== ====== ======
Weighted average rate assumptions:
Discount rate 8.9% 7.6% 10.9% 10.0%
Rate of increase in compensation 6.9% 5.4% 4.0% 4.0%
Expected return on plan assets 10.4% 9.6% n/a n/a
Settlements and curtailments in 1999 include sale of investment in Koa. (See Note 4)
C-17
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
Note 8 - Employee benefit plans - continued
As of December 31,
--------------------------
(Millions of U.S.
dollars)
1999 1998
------ ------
Pension plans with accumulated benefit obligations in excess of assets
Projected benefit obligation $ 25 $184
Accumulated benefit obligation 13 157
Fair value of assets - 87
The 1999 reduction is due to sale of investment in Koa (see Note 4)
Year ended December 31,
-------------------------------
(Millions of U.S. dollars)
1999 1998 1997
----- ----- -----
Components of Pension Expense
Service cost $ 23 $ 19 $ 26
Interest cost 26 31 44
Expected return on plan assets (27) (28) (36)
Amortization of prior service cost 3 1 3
Recognized net actuarial loss 1 5 3
Curtailment/settlement loss 16 21 -
----- ----- ------
Total $ 42 $ 49 $ 40
===== ===== ======
Components of Other Post-retirement Benefits
Service cost $ 1 $ 2 $ 2
Interest cost 8 6 6
Special termination benefit recognition - 3 -
Curtailment recognition - 3 -
----- ----- ------
$ 9 $ 14 $ 8
===== ===== ======
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 8.9% would change the post-retirement benefit obligation
by $8 million and would not have a material effect on aggregate service and
interest components.
Note 9 - Commitments and contingencies
In 1997, Caltex received a claim from the United States Internal Revenue
Service (IRS) for $292 million in excise tax, along with penalties and interest,
bringing the total to approximately $2 billion. Caltex was required to provide
the IRS with a standby letter of credit securing the performance of Caltex's
obligations to the IRS if the claim was upheld by the courts. Pursuant to
Caltex's ongoing discussions with the IRS and the Justice Department, Caltex'
offer to settle the claim was accepted and the remaining amount of the
assessment was conceded. On December 22, 1999, Caltex settled the claim in the
amount of tax of $9.1 million plus accrued interest of $55.7 million due under
the terms of the settlement. Accordingly, the letter of credit was terminated
and the parties filed a stipulation with the United States Court of Federal
Claims to dismiss the case and the case was dismissed. The majority of the
settlement was applied against reserves established prior to 1999 and there was
no significant impact on 1999 net income.
Caltex also is involved in IRS tax audits for years 1987 to 1993. While no
claims by the IRS are outstanding for these years, in the opinion of management,
adequate provision has been made for income taxes for all years either under
examination or subject to future examination.
C-18
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
Note 9 - Commitments and contingencies - continued
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) does not mention a specific monetary recovery although the pleadings
contain a variety of demands for various categories of compensatory as well as
punitive damages. Consequently, no reasonable estimate of damages involved or
being sought can be made at this time. 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. Caltex is also seeking
dismissal of the Louisiana litigation in reliance on various statutory,
procedural and substantive grounds.
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.
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 $700 million per
year. Purchases (in billions of U.S. dollars) under this and other similar
contracts were $0.7, $0.8 and $1.0 in 1999, 1998 and 1997, respectively.
Caltex is contingently liable for sponsor support funding for a maximum of
$278 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 1999, 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,
1999 of $149 million.
C-19
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
Note 10 - 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:
As of December 31,
--------------------------
(Millions of U.S.
dollars)
1999 1998
---- ----
Interest rate swaps - Pay Fixed, Receive Floating $ 632 $ 653
Interest rate swaps - Pay Floating, Receive Fixed 245 202
Commitments to purchase foreign currencies 360 395
Commitments to sell foreign currencies 81 25
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 ten years. Net unrealized gains and (losses) on
contracts outstanding at December 31, 1999 and 1998 were $4 million and ($7
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) hedging existing liabilities have maturities of up to two
years. Net unrealized losses applicable to outstanding forward exchange
contracts at December 31, 1999 and 1998 were $5 million and $23 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 gains on hedging contracts outstanding at year-end were
$4 million in 1999 and $8 million in 1998.
The Group's recorded value of long-term debt exceeded the fair value by
$22 million and $34 million as of December 31, 1999 and 1998, 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 current liabilities
approximate fair value because of their short maturities.
The Group had investments in debt securities available-for-sale at
amortized costs of $120 million and $105 million at December 31, 1999 and 1998,
respectively. The fair value of these securities at December 31, 1999 and 1998
approximated amortized costs. As of December 31, 1999 and 1998, investments in
debt securities available-for-sale had maturities less than ten years. The
Group's carrying amount for investments in affiliates accounted for at equity
included $2 million and $19 million, as of December 31, 1999 and 1998,
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-20
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
Note 11 - Taxes
Taxes charged to income consist of the following:
Year ended December 31,
---------------------------------------
(Millions of U.S. dollars)
1999 1998 1997
---- ---- ----
Taxes other than income taxes:
Duties, import and excise taxes $ 1,077 $ 1,218 $ 1,409
Other 16 17 19
-------- -------- -------
Total taxes other than income taxes $ 1,093 $ 1,235 $ 1,428
======== ======== =======
Income taxes:
U.S. taxes :
Current $ 72 $ 6 $ 8
Deferred - 23 (2)
-------- -------- -------
Total U.S. 72 29 6
-------- -------- -------
International taxes:
Current $ 376 $ 228 $ 407
Deferred (58) 69 (49)
-------- -------- -------
Total International 318 297 358
-------- -------- -------
Total provision for income taxes $ 390 $ 326 $ 364
======== ======== =======
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:
Year ended December 31,
-----------------------------------------
1999 1998 1997
---- ---- ----
Computed "expected" tax rate 35.0% 35.0% 35.0%
Effect of recording equity in net income
of affiliates on an after tax basis (11.3) (7.3) (11.3)
Effect of dividends received from
subsidiaries and affiliates 0.4 (0.3) (0.3)
Income subject to foreign taxes at other
than U.S. statutory tax rate 18.4 26.0 5.2
Effect of sale of investment in an affiliate 6.6 - -
Deferred income tax valuation allowance 2.4 8.7 1.4
Other (1.5) 0.7 -
------- ------- ------
Effective tax rate 50.0% 62.8% 30.0%
======= ======= ======
For 1999, the increase in 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. The 1998 increase in effective tax
rate is
C-21
primarily due to the larger proportion of earnings from higher tax rate
foreign jurisdictions, and the effect of foreign currency translation on pre-tax
income.
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:
Year ended December 31,
---------------------------
(Millions of U.S. dollars)
1999 1998
----- -----
Depreciation $ 322 $ 316
Miscellaneous 17 38
----- -----
Deferred tax liabilities 339 354
----- -----
Inventory (24) (1)
Investment allowances (62) (62)
Tax loss carry-forwards (100) (63)
Foreign exchange (13) (8)
Retirement benefits (33) (48)
Miscellaneous (11) (11)
----- -----
Deferred tax assets (243) (193)
Valuation allowance 91 72
----- -----
Net deferred taxes $ 187 $ 233
===== =====
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 $3.4 billion as of
December 31, 1999 and December 31, 1998, 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 12 - 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.
C-22
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
Note 13 - 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. Less than 100 of the affected employees remained as of the end of
1999 and almost all of these are scheduled to leave by the end of March, 2000.
The charges also included $12 million and $10 million for asset and lease
commitment write-offs, and other reorganization costs of $2 million and $16
million, in 1999 and 1998, respectively. In addition, 1999 net income includes a
$27 million after tax charge for restructuring activities of affiliates.
Approximately $22 million of the total restructuring and reorganization
charges remained as recorded liabilities as of December 31, 1999, which
primarily relates to future lease commitments on vacated office space over the
remaining lease term ending in 2002, and severance payments to be paid to
affected employees during the first quarter of 2000. Adjustments made in 1999 to
the liability recorded at December 31, 1998 were insignificant.
The following table summarizes the restructuring/reorganization costs
related to severance and other termination benefits for 1999 and 1998 (millions
of U.S. dollars):
1999 1998
--------------------------------- --------------------------------
Balance at Balance at
December 31 Payments Accruals December 31 Payments Accrual
----------- -------- -------- ----------- -------- -------
U.S. Headquarters and expatriates:
Severance and
other termination benefits $ 8 $ (19) $ 3 $ 24 $ (2) $ 26
Employee benefit
curtailment/settlement 2 (35) 17 20 (6) 26
Foreign staff severance benefits - (3) 3 - (8) 8
----- ----- ----- ----- ----- -----
$ 10 $ (57) $ 23 $ 44 $ (16) $ 60
===== ===== ===== ===== ===== =====
Note 14 - 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
$30 million in both 1999 and 1998, and $12 million in 1997 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, 1999 is approximately $25 million. The effect
of suspending depreciation on assets held for sale in 1999, 1998 and 1997 was
not material.
C-23
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
Note 15 - Combined statement of cash flows
Changes in operating working capital consist of the following:
Year ended December 31,
---------------------------------
(Millions of U.S. dollars)
1999 1998 1997
------ ------ ------
Accounts and notes receivable $ (653) $ 404 $ 33
Inventories (12) (28) 85
Accounts payable 484 (105) (252)
Accrued liabilities (23) 41 1
Estimated income taxes 14 4 (17)
------ ------- --------
Total $ (190) $ 316 $ (150)
======= ======= ========
Net cash provided by operating activities includes the following cash
payments for interest and income taxes:
Year ended December 31,
---------------------------------
(Millions of U.S. dollars)
1999 1998 1997
------ ------ ------
Interest paid (net of capitalized interest) $ 142 $ 182 $ 138
Income taxes paid $ 404 $ 237 $ 440
The deconsolidation of Caltex Australia Limited as of December 31, 1997,
as described in Note 4, resulted in a non-cash reduction in the following
combined balance sheet captions for 1997, which have not been included in the
combined statement of cash flows (millions of U.S. dollars):
Net working capital $ 60
Equity in affiliates 94
Long-term debt 45
Minority interest 109
No significant non-cash investing or financing transactions occurred in
1999 and 1998.
Note 16 - 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-24