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1998
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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, 1998
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
(Exact name of registrant as specified in its charter)
575 Market Street,
Delaware 94-0890210 San Francisco, California 94105
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(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 28, 1999 - $50,044,000,000
Number of Shares of Common Stock outstanding
as of February 28, 1999 - 653,334,751
DOCUMENTS INCORPORATED BY REFERENCE
(To The Extent Indicated Herein)
Notice of Annual Meeting and Proxy Statement Dated March 22, 1999 (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) Industry Segment and Geographic Area Information....... 4
(c) Description of Business and Properties................. 4
Capital and Exploratory Expenditures................. 5
Petroleum - Exploration................................ 6
Petroleum - Oil and Natural Gas Production............. 10
Production Levels.................................. 10
Development Activities............................. 11
Petroleum - Natural Gas Liquids ....................... 16
Petroleum - Reserves and Contract Obligations.......... 16
Petroleum - Refining................................... 17
Petroleum - Refined Products Marketing................. 18
Petroleum - Transportation............................. 19
Chemicals.............................................. 20
Coal and Other Minerals................................ 21
Research and Environmental Protection.................. 21
2. Properties..................................................... 23
3. Legal Proceedings.............................................. 23
4. Submission of Matters to a Vote of Security Holders............ 23
Executive Officers of the Registrant........................... 24
PART II
5. Market for the Registrant's Common Equity
and Related Stockholder Matters................................ 25
6. Selected Financial Data........................................ 25
7. Management's Discussion and Analysis of Financial
Condition and Results of Operations............................ 25
8. Financial Statements........................................... 25
8. Supplementary Data - Quarterly Results....................... 25
- Oil and Gas Producing Activities........ 25
9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure......................... 25
PART III
10. Directors and Executive Officers of the Registrant............. 26
11. Executive Compensation......................................... 26
12. Security Ownership of Certain Beneficial Owners and Management. 26
13. Certain Relationships and Related Transactions................. 26
PART IV
14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K....................................... 26
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 90 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 a wide
range of chemicals for industrial uses.
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, 1998, Chevron had 39,191
employees, 77 percent of whom were employed in U.S. operations.
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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 margins 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
disruption or interruption of the company's production or manufacturing
facilities due to accidents or political events; potential disruption to the
company's operations due to untimely or incomplete resolution of Year 2000
issues by the company and other entities with which it has material
relationships; potential liability for remedial actions under existing or future
environmental regulations; 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.
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(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).
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 a large number
of factors, over some of which individual oil and gas companies have little
control. Governmental attitudes and 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
usually 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
- - ---------------------
The downward trend in crude oil and natural gas prices that began in 1997
continued throughout 1998. The average spot price for West Texas Intermediate
(WTI), an industry benchmark light crude oil, averaged $14.38 per barrel in
1998, compared with $20.60 for 1997. Prices were in the $13-$15 per barrel range
during most of the year and reached a low of $10.73 per barrel on December 10,
1998. The spot WTI price averaged $12.24 per barrel for the first two months of
1999 before rebounding somewhat in mid-March in response to reports that key
producers would agree to cut output at an upcoming OPEC meeting. At the March 23
meeting, the OPEC members and other producers agreed to cut worldwide production
by 2.6 percent for one year. On March 26, 1999, the spot WTI price was $16.18
per barrel.
A number of factors exerted downward pressure on crude oil prices in 1998.
Supplies increased as new producing fields came on stream and production from
existing fields increased. Iraq boosted its exports significantly while other
OPEC members raised their output in the first half of 1998 before reducing it in
the second half of the year. At the same time the growth in demand slowed
substantially as a result of the economic problems in Asia and continued warm
weather in the United States, Europe and Asia. The result was an oversupplied
world market with inventories remaining at high levels.
In early 1998, prices for natural gas were relatively low, mainly as a result of
the mild winter weather in the United States and remained so for the majority of
1998. The U.S. benchmark Henry Hub Louisiana spot price averaged $2.08 per
thousand cubic feet (MCF) in 1998 compared with $2.57 per MCF in 1997. Prices
remained in the $1.75 - $2.00 per MCF range for the first two months of the
1999, averaging $1.82 per MCF.
The company's average realization from U.S. crude oil production decreased to
$11.42 per barrel in 1998 from $17.68 in 1997, while average liquids
realizations from international liftings, including equity affiliates, decreased
$6.20 per barrel to $11.77. The company's average U.S. natural gas realizations
from production decreased by $0.40 per MCF in 1998 to $2.02 per MCF, while
average international natural gas realizations fell to $1.94 per MCF, compared
with $2.10 per MCF in 1997.
For the first two months of 1999, average natural gas realizations from the
company's U.S. operations were $1.67 per MCF, compared with $2.06 for the same
period in 1998. Average crude oil realizations from the company's U.S.
operations were $9.12 per barrel for the first two months of 1999, compared with
$12.99 for the same period in 1998.
In 1998, Chevron's refining, marketing and transportation results in the United
States were adversely affected by lower product margins and the September storms
that closed the company's Pascagoula, Mississippi refinery for most of the 1998
fourth quarter. These factors were partially offset by higher refined products
sales volumes and lower operating expenses. Chevron's refined product sales
volumes in the United States increased by about 4 percent to 1.243 million
barrels per day. Most of the increase in volumes reflected higher gasoline sales
volumes, including branded gasoline sales, which were up 5 percent from 1997.
The company's average sales price of refined products in the United States was
$22.37 per barrel in 1998, a decrease of $6.56 per barrel from 1997.
On March 25, 1999, there was an explosion and fire in a hydrocracking unit at
the company's Richmond, California, refinery. At the end of March, the company
was evaluating the extent of damages and the impact on the company's operations.
Other units at the refinery remained in operation.
-2-
The chemicals industry entered a cyclical downturn in the latter half of 1995
that continues to persist. Earnings from the company's chemicals operations in
1998, excluding special items, were about 33 percent lower than in 1997. The
decline in earnings reflected depressed margins arising from continued industry
over-capacity, high inventories and lower demand resulting primarily from the
Asian economic crisis. Product sales prices fell faster than feedstock and fuel
costs, resulting in lower margins for most of the company's major chemical
products. However, the company's sales volumes were about 10 percent higher in
1998 than in 1997, partially offsetting the lower margins. Sales and other
operating revenues from the company's chemicals operations, including sales to
other Chevron companies, totaled $3.216 billion, a decrease of $430 million from
the $3.646 billion in 1997.
During the first quarter 1999, the company announced various business
reorganizations, consolidations or relocations aimed at reducing costs and
improving performance. These changes are planned for the company's U.S. and
Canadian upstream, U.S. pipeline, chemicals and upstream technology operations.
The costs associated with these initiatives will be recognized primarily in
1999. In 1998, Chevron's equity affiliate Caltex Corporation announced a
reorganization plan involving the relocation of its management and
administrative functions to Singapore. Certain associated costs were accrued in
1998.
Chevron Strategic Direction
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Chevron's strategic objective is to exceed the financial performance of its
strongest industry competitors in terms of total stockholder return. The company
is following certain strategies to improve its financial performance and to
create superior value for its stockholders, customers and employees. The eight
"strategic intents" for 1999 are:
o Build a committed team to accomplish the Corporate Mission: The company
believes that the success of the other seven strategic intents is strongly
linked to the level of commitment and dedication that Chevron employees
bring to their jobs. Employees are guided by "The Chevron Way," a statement
of the company's Mission and Vision and other key principles including
Committed Team Values, Total Quality Management, Protecting People and the
Environment and Vision Metrics, that establish a standard of excellence for
each employee.
o Focus on reducing costs across all activities: The company continues to
focus on cost reductions to ensure that it remains competitive and to
improve profitability. Operating expenses, adjusted for special items,
decreased about $300 million in 1998 from 1997. Approximately $200 million
of this decline resulted from the company's 1997 exit from the U.K.
refining and marketing business. To help offset the impact on financial
results of low crude oil and natural gas prices, the company intends to
reduce its cost structure by another $500 million in 1999 and plans to
introduce further sustainable reductions that will be in place by 2000.
o Accelerate upstream growth in international areas: The company continues to
believe that its most promising area of financial and operational growth is
in its international E&P activities. In spite of current low oil prices,
the company does not plan to delay any major international projects,
although several of these are contingent upon the ability of Chevron's
partners to fund their respective shares. The 1999 C&E program provides
$2.6 billion for international E&P projects, an increase of 34 percent over
1998 expenditure levels. The company plans to grow production volumes from
existing businesses and focus exploration activities in high potential
areas where a production infrastructure already exists.
o Accelerate the growth of our Caspian area earnings by cooperatively
applying the skills and talents of all Chevron organizations: Chevron has
established itself as one of the pre-eminent international oil companies
operating in the Caspian region through its early involvement in the Tengiz
project in Kazakhstan. The company continues expanding its operations and
pursuing a range of other opportunities in the Caspian Sea region, as the
company believes that this area holds tremendous potential for long-term
growth.
o Generate cash from North American Upstream operations: The company will
focus exploration and development programs in two frontier areas: the
deepwater Gulf of Mexico and offshore eastern Canada, where the company
currently has several projects under way. Low oil prices have constrained
cash generation and dictated a slowdown in spending in all but major growth
areas. Exploration activities have been curtailed in western Canada, the
U.S. mid-continent region and California's San Joaquin Valley. In 1998, the
company
-3-
generated cash proceeds of approximately $300 million from the sale
of non-core U.S. and Canadian assets and may sell additional properties
over the next three years.
o Achieve top financial performance and generate cash from North American
Downstream: The U.S. refining industry continues to be a capital-intensive
and highly environmentally-regulated, commodity business where low cost,
reliable, incident-free operations are essential to remain competitive. The
company's strategies emphasize incident-free operations, brand management,
and cost management, without increasing capital employed. The company is
expanding its U.S. service station network to increase gasoline volumes,
while also stressing growth in convenience store goods.
o Caltex should achieve superior competitive financial performance, while
minimizing operating expenses and capital spending: Chevron's 50
percent-owned international downstream affiliate, Caltex Corporation,
operates in about 60 countries in the Middle East, Africa, and the
Asia-Pacific region. The effects of the Asian economic crisis, specifically
the slowdown in demand growth in the region, are likely to affect Caltex
for the next few years. Caltex has responded to the crisis by increasing
its focus on managing costs and investments. The company continues to
believe that long-term economic growth in the Pacific Rim will nonetheless
surpass that of most other regions.
o Improve financial performance in Chemicals: Financial results for the
company's chemicals operations continue to reflect the cyclical downturn in
the chemicals industry. Capital spending will be focused on existing
activities that provide long-term value, opportunities that improve cost
structure and enhance business performance, and opportunities that add
value to existing corporate assets or provide synergies with other areas of
Chevron. The company has undertaken several major projects to lower its
unit cost structure and position its operations to benefit from the next
industry upturn.
In addition to the above strategic intents, Chevron and its affiliates continue
to review and analyze their operations and may close, sell, exchange, acquire or
restructure assets to achieve operational or strategic benefits to improve
competitiveness and profitability. These activities may result in significant
gains or losses in future periods.
(b) Industry Segment and Geographic Area Information
The company's largest business segments are its exploration and production
operations and its refining, marketing and transportation operations. Other
significant operations include chemicals. 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, Australia, the United Kingdom, Indonesia, Norway, Republic of Congo,
China, and Venezuela. The company's Caltex affiliate, through its subsidiaries
and affiliates, conducts exploration and production and geothermal operations in
Indonesia and refining and marketing activities in Asia, Africa, the Middle
East, Australia and New Zealand, with major operations in Korea, Japan,
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 Sea area of Central Asia
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.
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.
The company's chemicals operations are concentrated in the United States, but
also include manufacturing facilities in France, Japan, Brazil, Singapore and
Mexico. Chemicals manufacturing facilities are under construction in China and
Saudi Arabia.
Tabulations of segment sales and other operating revenues, earnings, income
taxes and assets, by United States and International geographic areas, for the
years 1996 to 1998, may be found in Note 9 to the Consolidated Financial
Statements beginning on page FS-22 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-24 and FS-25.
-4-
(c) Description of Business and Properties
The petroleum industry is highly competitive in the United States and throughout
most of the world. This industry also competes with other industries in
supplying the energy needs of various types of consumers. To succeed in its
competitive environment, the company must identify and manage significant risks
in its various activities.
The company's worldwide operations can be affected significantly by changing
economic, 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.
The company utilizes various derivative instruments to manage its exposure to
price risk stemming from its international integrated petroleum activities. All
these instruments are commonly used in oil and gas trading activities and are
generally of a short-term duration. The company enters into forward exchange
contracts as a hedge against some of its foreign currency exposures. Interest
rate swaps are entered into as part of the company's overall strategy to manage
the interest rate risk on its debt. All commodity and financial derivative
instruments used by the company are relatively straightforward and involve
little complexity. Their impact on the company's results of operations has not
been material in the past and is not expected to be material in the future. The
results of operations and financial position of certain equity affiliates may be
affected by their business activities involving the use of derivative
instruments.
Capital and Exploratory Expenditures
Chevron's capital and exploratory (C&E) expenditures during 1998 and 1997 are
summarized in the following table:
Capital and Exploratory Expenditures
(Millions of Dollars)
1998 1997 Change %
------ ------ ------- ------
Exploration and Production - United States $1,213 $1,394 $ (181) (13)
International 1,647 1,574 73 5
------ ------ ------ ------
Sub-total 2,860 2,968 (108) (4)
Refining, Marketing
and Transportation - United States 654 512 142 28
International 92 60 32 53
------ ------ ------ ------
Sub-total 746 572 174 30
Chemicals - United States 385 470 (85) (18)
International 121 192 (71) (37)
------ ------ ------ ------
Sub-total 506 662 (156) (24)
All Other 208 165 43 26
------ ------ ------ ------
Total Consolidated Companies 4,320 4,367 (47) (1)
Chevron's Share in Affiliates 994 1,174 (180) (15)
------ ------ ------ ------
Total Including Affiliates ............... $5,314 $5,541 $ (227) (4)
====== ====== ====== ======
Noteworthy among the changes in C&E expenditures between years was the decrease
for U.S. exploration and production driven by lower development well and other
production-related expenditures. The increase between years for U.S. refining,
marketing and transportation, was driven primarily by the continued expansion of
the U.S. marketing network and the acquisition of Amoco's North American
lubricants operations. Chemicals expenditures
-5-
were 24 percent lower in 1998 as the majority of 1997's major expansion and
construction projects reached or neared completion in late 1997 and early 1998.
The company's Caltex affiliate accounted for nearly 50 percent of affiliates'
expenditures in 1998, although at lower levels than in 1997. In 1998, Caltex
continued to curtail C&E expenditures as a result of the Asian financial crisis.
The decrease in Caltex expenditures in 1998, together with a decrease from the
company's Dynegy Inc. affiliate, were slightly offset by increased expenditures
by the company's chemicals affiliate in Saudi Arabia, associated with the
construction of a new manufacturing facility in that country.
The company's 1999 C&E expenditures, including its share of equity affiliates'
expenditures, are projected at $5.1 billion, about $200 million, or 4 percent
lower than 1998 spending levels. Consolidated companies' expenditures are
planned to decrease slightly to $4.2 billion, while the company's share of
equity affiliates' expenditures is expected to decrease by 9 percent to $900
million. The company is planning to continue to develop international upstream
projects, while curtailing capital spending in the international chemicals and
downstream businesses.
Worldwide exploration and production C&E expenditures in 1999, including the
company's share of equity affiliates' expenditures, are expected to total $3.7
billion, an increase of about 13 percent over 1998 spending levels.
Approximately 70 percent, or about $2.6 billion, of the 1999 program will be for
international projects in alignment with the company's strategy to continue its
expansion in areas including Kazakhstan, Angola and Nigeria. In March 1999, the
company obtained natural gas interests in the Gulf of Thailand through
concluding its acquisition of the Rutherford-Moran Oil Corporation.
Worldwide refining, marketing and transportation C&E expenditures in 1999,
including the company's share of equity affiliates' expenditures, are estimated
at $870 million, down about 20 percent from 1998 spending levels. About $540
million is planned for projects in the United States, a majority of which are
marketing projects. Most of the international refining, marketing and
transportation capital program in 1999 will be concentrated in the Asia-Pacific
region, where the company's Caltex affiliate is upgrading its retail marketing
system.
Worldwide chemicals C&E expenditures in 1999, including the company's share of
equity affiliates' expenditures, are estimated at about $415 million, down about
50 percent from 1998 spending levels. This decrease reflects the deferral or
cancellation of a number of major international projects.
The actual C&E expenditures for 1999 will depend on various conditions affecting
the company's operations, including crude oil and natural gas prices, changing
economic conditions in the various countries in which it operates and the
ability of the company's joint venture partners, some of which are national
petroleum companies, to fund their share of project expenditures, particularly
in the international exploration and production segment. The company has the
ability to modify its C&E expenditures in the event the lower crude oil price
environment becomes more severe or prolonged.
Petroleum - Exploration
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, 1998. "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 $193 million of suspended exploratory wells included
in properties, plant and equipment at year-end 1998. 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 drilling activity and development decisions.
-6-
Exploratory Well Activity
Net Wells Completed (1)
Wells Drilling -----------------------------------------------
At 12/31/98 1998 1997 1996
----------------- ------------ ------------ ------------
Gross(2) Net(2) Prod. Dry Prod. Dry Prod. Dry
------- ------ ------ ----- ----- ----- ------ ----
United States 32 23 46 12 56 31 120 25
------- ------ ------ ----- ----- ----- ------ ----
Africa 8 3 7 2 5 1 3 2
Other International 27 7 9 8 12 6 32 22
------- ------ ------ ----- ----- ----- ------ --
Total International 35 10 16 10 17 7 35 24
------- ------ ------ ----- ----- ----- ------ --
Total Consolidated Companies 67 33 62 22 73 38 155 49
Chevron's Share in Affiliates 8 3 2 - 3 - - 1
------- ------ ------ ----- ----- ----- ------ ---
Total Including Affiliates 75 36 64 22 76 38 155 50
======= ====== ====== ===== ===== ===== ====== ===
(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.
At December 31, 1998, 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.
Acreage* At December 31, 1998
(Thousands of Acres)
Developed
Undeveloped Developed and Undeveloped
-------------------- -------------------- --------------------
Gross Net Gross Net Gross Net
--------- --------- --------- --------- --------- ---------
United States 5,442 3,933 2,713 1,842 8,155 5,775
--------- --------- --------- --------- --------- ---------
Canada 19,572 10,963 1,306 549 20,878 11,512
Africa 22,558 16,816 153 59 22,711 16,875
Asia 19,761 10,764 68 26 19,829 10,790
Europe 2,367 847 93 22 2,460 869
Other International 17,731 8,182 75 21 17,806 8,203
--------- --------- --------- --------- --------- ---------
Total International 81,989 47,572 1,695 677 83,684 48,249
======== ======== ========= ========= ========= =========
Total Consolidated Companies 87,431 51,505 4,408 2,519 91,839 54,024
Chevron's Share in Affiliates 2,687 1,296 254 123 2,941 1,419
--------- --------- --------- --------- --------- ---------
Total Including Affiliates 90,118 52,801 4,662 2,642 94,780 55,443
========= ========= ========= ========= ========= =========
* 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.
During 1998, the company incurred expenditures for oil and gas exploration in
the United States and about 20 other countries. The company's 1998 exploratory
expenditures, including affiliated companies' expenditures but excluding
unproved property acquisitions, were $890 million compared with $798 million in
1997. U.S. expenditures represented approximately 50 percent of the consolidated
companies' worldwide exploration expenditures, compared with 45 percent in 1997.
In addition, unproved properties of $72 million were acquired in 1998, compared
with $124 million in 1997. Significant activities in Chevron's exploration
program during 1997 include the following (numbers of wells are on a "gross"
basis):
-7-
United States: Exploratory expenditures, excluding unproved property
acquisitions, were $443 million in 1998, compared with $360 million spent in
1997. In addition, the company incurred costs of $58 million for unproved
property acquisitions in 1998, compared with $101 million in 1997. 1998
exploration efforts were concentrated primarily in the Gulf of Mexico, where the
potential for large discoveries has been demonstrated. In the March and August
1998 Gulf of Mexico Lease Sales, Chevron successfully bid, alone and with
partners, for the rights to 89 leases, 66 of which are in deep water, boosting
Chevron's deepwater lease inventory to 428 leases.
Africa: In Africa, the company spent $162 million during 1998 on exploratory
efforts, excluding the acquisition of unproved properties, compared with $147
million in 1997. The increase between years was driven by higher 1998
expenditures in Nigeria and Congo.
In Angola, the company is the operator of two concessions off the coast of
Angola's Cabinda enclave. Block 0 is a 2,100 square mile concession adjacent to
the Cabinda coastline and is divided into three areas: Area A, which began
production in late 1960, includes 19 major fields (15 currently producing) in
two major regions, Malongo and Takula; Area B, which began production in late
1994 with six major fields, includes the Kokongo, Nemba and Lomba fields; and
Area C, which began first production in 1997 has seven major fields, including
the Ndola and Sanha fields. Chevron has a 39.2 percent interest in the Block 0
concession. The 1998 exploration and appraisal well program in Area A consisted
of a four-well effort targeting open water prospects and extension of
established fields. All four exploratory wells were discoveries. In Areas B and
C, three exploration wells were drilled, one of which discovered oil. Chevron
has a 31 percent interest in the second Angolan concession, Block 14, acquired
in 1995. Block 14 is a 1,560 square mile concession located in waters west of
Areas B and C. The Block 14 exploration program continued in 1998 with four
exploration wells, resulting in four discoveries, including two significant
commercial finds, Benguela and Belize. The Block 14 partnership now has rights
to a second exploration period through February 2002. The exploration program
planned for Block 14 in 1999 includes drilling two exploratory wells in the
deeper water areas of the block. Additional exploratory wells to evaluate
prospects in the shallow water area of the block are also being considered. Two
appraisal wells are planned to assist the Benguela and Belize fields evaluation.
Over 360 square miles of 3-D seismic data north of Congo Canyon in deep water
was acquired in 1998. South Congo Canyon 3-D data processing was completed in
1998 and the interpretation resulted in 12 firm prospects and additional leads.
In Nigeria, the company's operations are managed by three subsidiaries. Chevron
Nigeria Limited (CNL) operates and holds a 40 percent interest in concessions
totaling approximately 2.2 million acres in the onshore swamp and near offshore
regions of the Niger Delta. CNL drilled four exploration wells in 1998. Four
additional wells are planned for 1999. Chevron Oil Company Nigeria Limited
(COCNL) holds a 20 percent interest in six concessions covering about 600
thousand acres, with six offshore oil fields operated by Texaco. COCNL did not
drill any exploration wells in 1998. Chevron Petroleum Nigeria Limited (CPNL)
oversees and manages new venture projects in Nigeria. CPNL has a sole interest
in six Benue Basin blocks and a 30 percent interest in two deepwater Niger Delta
blocks and three inland Benue Basin blocks operated by Elf. CPNL continued
preparations for the drilling of a Benue Trough obligation well in 2000 by
completing the processing and interpreting of 2-D seismic data recently
acquired. During 1998, CPNL participated in three joint venture deepwater
exploratory wells. Two of these wells discovered oil, and at year-end, the
economic feasibility of pursuing commercial development was being carried out.
Offshore Republic of Congo, the company has a 29.25 percent interest in the
partner-operated Marine VII license, which includes the Kitina and Sounda
developments, and a 30 percent interest in the Haute Mer license, which is
operated by a partner and includes the Nkossa and Moho fields. In the Haute Mer
Block, two exploration wells were drilled and a third well was started in 1998
in a geological setting similar to the Angola Block 14 discoveries. Two of the
wells confirmed the existence of potential commercial developments. Appraisal
wells were drilled on the Bilondo structure and in the Moho Field in Haute Mer
in 1998. Development options for the Bilondo and Moho fields are being
evaluated. The 1997 Haute Mer 3-D survey was further analyzed in 1998 and has
indicated a number of additional tertiary exploration targets. The drilling of
these prospects is under evaluation. In the Chevron-operated Marine IV Block,
drilling of the Poungou Marine-1 well was started in late 1998 but was
unsuccessful.
In Democratic Republic of Congo (formerly Zaire), the company has a 50 percent
interest in, and is the operator of, a 390 square mile offshore concession. A
3-D seismic program, which started in late 1997, was completed in 1998,
-8-
with data interpretation planned to begin in 1999. Approximately 95 percent of
the concession is now covered with 3-D seismic data. No exploration wells were
drilled in 1998.
Other International including affiliated companies: Exploration expenditures,
excluding unproved property acquisitions, outside the United States and Africa,
were $285 million in 1998, almost level with 1997 expenditures of $291 million.
In addition, unproved properties of $14 million were acquired in 1998 compared
with $23 million in 1997.
In Canada, Chevron continued to expand its offshore east coast lease position in
1998. In April 1998, the company acquired a 100 percent interest in a
740,000-acre deepwater license offshore Nova Scotia. Chevron also acquired four
parcels totaling 737,000 acres offshore Newfoundland in 1998, with the company's
interest in the parcels ranging from 30 to 50 percent. Two parcels are located
near existing Chevron assets in the Jeanne d'Arc Basin, while the others are in
a new deepwater area. Chevron plans to begin an exploration drilling program in
the Jeanne d'Arc Basin in 1999. Delineation drilling of the Hebron Field
commenced in December 1998 and has yielded encouraging results, with oil
discovered to the southwest and north east. Continued successful delineation
drilling will likely lead to development of the field, in which Chevron has an
approximate 30 percent interest.
In Australia, Chevron's primary interests are in two non-operated joint
ventures. The company has a 16.7 percent interest in the North West Shelf (NWS)
Project. Exploratory appraisal drilling continued in the NWS project concessions
in 1998 with two wells successfully delineating previous discoveries and another
exploration well drilling at year end some 25 miles south of the Goodwyn Field.
Chevron also holds 25 to 50 percent interests in permits operated by West
Australian Petroleum Pty. Ltd. (WAPET), including a 25 percent interest in one
Carnarvon Basin block acquired in 1997, adjacent to the Gorgon/Chrysaor/Dionysus
gas fields. In 1998, WAPET continued with preparations to drill in the recently
acquired Permit WA-267-P, in the deeper water area adjacent to the
Gorgon/Chrysaor/Dionysus gas fields. Separate from NWS and outside the
WAPET-operated area, Chevron holds 25 to 33 percent interests in four blocks in
the Browse Basin area, a 20 percent interest in an additional Browse Basin
permit awarded in 1998, and a 17.25 percent interest in an additional Carnarvon
Basin block.
In China, Chevron has an interest in five blocks in the South China Sea and
three blocks in the Bohai Gulf area. In 1998, the company commenced an
exploration drilling program on currently held acreage in China. Nine wildcat
exploration wells are anticipated as the program progresses. Two wells were
drilled in Block 02/31 in 1998 and into 1999, but did not yield positive
results. Additional drilling in Blocks 02/31 and 06/17 is scheduled for 1999. In
the onshore Zhanhuadong Block in the Bohai Gulf area, Chevron has identified
exploration prospects that lie beneath the existing Shengli Field production.
The Zhanhuadong Block contract represents Chevron's first onshore exploration
opportunity in China and requires that two wells be drilled in a three-year
period. The first well is scheduled for fourth quarter 1999. A 3-D seismic
survey, acquired in 1997, identified a large gas prospect in Block 63/15 in the
South China Sea. Drilling this prospect commenced in late 1998. In addition, the
company plans to drill an oil exploration well in early 1999 in the 16/08
contract area near the producing HZ fields, also in the South China Sea.
In Europe, Chevron has interests in about 40 exploration blocks in the United
Kingdom, Norway and Ireland. The U.K. Blocks are located in the North Sea, west
of Shetland Islands, offshore Wales, and in Liverpool Bay. In Ireland, the
company has acreage in the Porcupine Basin. In Norway, Chevron has interests in
five exploration licenses acquired in 1998 in an equity swap with Statoil. In
1998, Chevron focused on exploring the Greater Britannia area and growing the
exploration base in Norway.
Exploration activities took place in other areas in 1998. In Indonesia,
Chevron's interests are managed by its 50 percent owned P.T. Caltex Pacific
Indonesia (CPI) and Amoseas Indonesia (AI) affiliates. CPI is in the final
stages of a multi-year 3-D seismic acquisition effort in central Sumatra between
current producing fields. In Papua New Guinea, the company completed the
unsuccessful Nomad well in early 1998, and at year-end 1998 a seismic program
was in progress in the Gobe area. In Azerbaijan, where Chevron has a 30 percent
interest in a three-year exploration agreement signed in 1997, a 3-D seismic
survey was acquired in 1998. The survey will be interpreted in 1999. In the
Middle East, Chevron drilled two exploratory wells in Qatar, and plans to
acquire additional seismic data in 1999. In Bahrain, the company acquired a 3-D
seismic survey in 1998 and plans to begin exploratory drilling in 2000.
-9-
Petroleum - Oil and Natural Gas Production
The following table summarizes the company's and its affiliates' 1998 net
production of crude oil, natural gas liquids and natural gas.
1998 Net Production (*) Of Crude Oil And Natural Gas Liquids And Natural Gas
Crude Oil & Natural Gas
Natural Gas Liquids (thousands of
(barrels per day) cubic feet per day)
------------------ ------------------
United States
-California 116,200 122,000
-Gulf of Mexico 93,500 820,100
-Texas 57,900 331,100
-Colorado 10,600 700
-Wyoming 9,100 181,200
-New Mexico 12,500 60,400
-Louisiana 15,900 81,600
-Other States 9,400 141,800
------------ ------------
Total United States 325,100 1,738,900
------------ ------------
Africa 319,300 33,500
United Kingdom (North Sea) 39,200 73,900
Norway 13,000 400
Canada 63,000 180,300
Australia 38,400 223,400
Indonesia 17,500 -
Papua New Guinea 14,500 -
China 11,400 -
Colombia 12,200 -
Venezuela 1,400 -
Netherlands - 2,200
------------ ------------
Total International 529,900 513,700
------------ ------------
Total Consolidated Companies 855,000 2,252,600
Chevron's Share of Affiliates 252,300 140,000
------------ ------------
Total Including Affiliates 1,107,300 2,392,600
============ ============
* Net production excludes royalty interests owned by others.
Production Levels:
In 1998, worldwide net crude oil and natural gas liquids production, including
that of affiliates, increased for the sixth consecutive year. Production rose in
1998 by three percent to a record 1,107,300 barrels per day, compared with
1,074,400 barrels per day in 1997. International net liquids production,
including affiliates, increased by about seven percent to 782,200 barrels per
day in 1998, the ninth consecutive year of production increases. This increase
was due primarily to higher production in Canada, where 1998 saw the first full
year of production from the Hibernia Field; in Angola and Congo, where
development drilling continued in new and existing fields; in Norway, where the
company saw production from properties that were acquired in exchange for a
portion of its interest in the U.K. Alba Field; in Indonesia, where production
at the Duri Field grew; and in Kazakhstan, where the company's share of
production at the Tengiz Field increased as the plant expansion progressed.
These production increases were partially offset by a production decline in the
United Kingdom from the Alba Field following an exchange for Norwegian
properties.
-10-
Net production of natural gas, including affiliates, decreased by nearly 33
million cubic feet per day, or one percent, in 1998. United States production
fell by nearly 110 million cubic feet per day, or six percent, reflecting normal
field declines, property sales and production disruptions due to the September
1998 storms in the Gulf of Mexico. International volumes increased by 77 million
cubic feet per day in 1998. Increases between years came from new production
from the Britannia Field in the U.K. North Sea, increased production from the
Escravos Gas Project in Nigeria, and in Indonesia. These increases were slightly
offset by production declines in Western Canada. The company expects current
plans to develop the Norphlet trend in the U.S. Gulf of Mexico, to expand the
Escravos Gas Project in Nigeria, and to continue expansion and development of
its Australian projects, will mitigate further natural gas production declines
in its portfolio.
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 1998, 1997 and
1996. The following table summarizes gross and net productive wells at year-end
1998 for the company and its affiliates.
Productive Oil And Gas Wells At December 31, 1998
Productive(1) Productive(1)
Oil Wells Gas Wells
-------------------- --------------------
Gross(2) Net(2) Gross(2) Net(2)
--------- -------- --------- ---------
United States 23,833 12,853 4,481 2,222
--------- -------- --------- ---------
Canada 1,056 859 200 148
Africa 1,149 446 10 3
United Kingdom 102 8 17 5
Other International 1,309 443 50 11
--------- -------- --------- ---------
Total International 3,616 1,756 277 167
--------- -------- --------- ---------
Total Consolidated Companies 27,449 14,609 4,758 2,389
Chevron's Share of Affiliates 6,153 3,074 47 24
--------- -------- --------- ---------
Total Including Affiliates 33,602 17,683 4,805 2,413
========= ======== ========= =========
Multiple completion wells
included above: 656 368 309 192
(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.
Development Activities:
The company's development expenditures, including those of affiliated companies
but excluding proved property acquisitions, were $1,928 million in 1998 and
$2,219 million in 1997. The decrease between years resulted from lower 1998
expenditures in the United States and at the Tengiz Field.
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, 1998. (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.)
-11-
Development Well Activity
Wells Drilling Net Wells Completed(1)
----------------- -----------------------------------------------
At 12/31/98 1998 1997 1996
----------------- ------------ ------------ ------------
Gross(2) Net(2) Prod. Dry Prod. Dry Prod. Dry
------- ------ ------ ---- ----- ----- ------ ----
United States 336 151 324 5 617 6 485 8
------- ------ ------ ---- ----- ----- ------ ----
Africa 16 5 37 1 22 1 21 1
Other International 14 3 33 2 67 - 49 4
------- ------ ------ ---- ----- ----- ------ ----
Total International 30 8 70 3 89 1 70 5
------- ------ ------ ---- ----- ----- ------ ----
Total Consolidated Companies 366 159 394 8 706 7 555 13
Equity in Affiliates 25 11 272 - 150 - 262 -
------- ------ ------ ---- ----- ----- ------ ----
Total Including Affiliates 391 170 666 8 856 7 817 13
======= ====== ====== ==== ===== ===== ====== ====
(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.
During 1998, worldwide additions to proved reserves, excluding property sales
and acquisitions, including the company's share of equity affiliates, were 595
million barrels of crude oil and natural gas liquids and 345 billion cubic feet
of natural gas. Worldwide operations replaced 119 percent of net liquids and gas
production in 1998, excluding property sales and acquisitions. The replacement
rate for U.S. operations was 52 percent, while international operations replaced
165 percent of production.
Significant 1998 development activities include the following (production
volumes are gross unless otherwise stated.):
United States: Chevron's U.S. development expenditures were $680 million in
1998, a decrease of $238 million from $918 million in 1997. The company focused
its development activities in 1998 on prospects in the Gulf of Mexico, the
mid-continent and western United States. Additions to proved reserves during
1998, excluding property sales and acquisitions, were 78 million barrels of
crude oil and natural gas liquids and 228 billion cubic feet of natural gas.
U.S. operations replaced 52 percent of net liquids and gas production in 1998,
excluding property sales and acquisitions.
In the Gulf of Mexico, significant development activities in 1998 included the
completion of hull fabrication and the construction of the topsides and decks
for the Genesis project, Chevron's first deepwater operation in the Gulf of
Mexico, located in 2,600 feet of water. Chevron is the unit operator with a 57
percent working interest. First production occurred in January 1999, with peak
total production expected to reach 55,000 barrels of oil and 72 million cubic
feet of gas per day by 2000.
Chevron has a 40 percent interest in the Gemini deepwater development in the
Gulf of Mexico in a water depth of 3,400 feet. The discovery well, located on
Mississippi Canyon Block 292, was spudded in 1995. The project is a subsea
development tied back to Chevron's Viosca Knoll 900 Platform located 27.5 miles
northwest of Mississippi Canyon Block 292 in 340 ft. of water. The project plan
consists of drilling two development wells, completing an exploratory well and
building processing facilities. Initial production is scheduled for mid-1999,
with peak rates anticipated to reach over 150 million cubic feet of gas, and
over 2,000 barrels of condensate per day.
The Norphlet trend is a deep-gas trend, which stretches some 80 miles from the
Destin Dome area (offshore Florida) to the Mobile Block 861 area (offshore
Mississippi). Chevron's net production from Norphlet wells during 1998
-12-
averaged 95 million cubic feet of gas per day. In 1998, the company completed
one development well in the Mobile area, which was brought onto production in
early 1999. An additional exploratory well in the Mobile area will be completed
in early 1999 and is expected to be brought onto production later in the year.
Development plans and regulatory approvals are in progress for Destin Dome. The
MMS, in conjunction with other federal and state agencies, is in the process of
preparing an Environmental Impact Statement, which is required prior to
approving the Development and Production Plan. Initial production from Destin
Dome is anticipated approximately one year after obtaining all regulatory
approvals.
Offshore California, the company offered for sale all of its offshore California
platforms and related processing and transportation facilities. In February
1999, the sale of two platforms, associated onshore processing facility and
platform-to-shore pipelines was completed. In March 1999, the company reached
agreement to sell its remaining offshore California assets, which it expects to
complete in the second quarter 1999. If the sale is not consummated in the
second quarter, the company will evaluate other alternatives for exiting
offshore California operations. In the fourth quarter 1998, the company recorded
impairments and a provision for other liabilities relating to the anticipated
exit from offshore California operations.
Onshore California, Chevron continued to expand its employment of thermal
enhanced recovery methods to increase both the production rate and the amount of
oil ultimately recoverable from fields in California's San Joaquin Valley, with
efforts focused on the Cymric Field. Due to the current low oil price
environment, the company is presently restricting further expansion of Cymric
and its other heavy oil fields in the San Joaquin Valley.
Africa: Development expenditures in Africa were $561 million in 1998, compared
with $461 million in 1997. Higher 1998 expenditures in Angola and Nigeria were
partially offset by decreases in Congo and the Democratic Republic of Congo.
Additions to proved reserves, excluding property sales and acquisitions, were
286 million barrels of crude oil and natural gas liquids and 77 billion cubic
feet of natural gas. African operations replaced 252 percent of net liquids and
gas production in 1998, excluding property sales and purchases.
In Angola, the company's development activities are concentrated in Areas A, B
and C of Block 0 and deepwater Block 14. In Area A, 22 development wells were
drilled in 1998. Thirteen wells were in the Takula Area and nine were in the
Malongo Area. Several new waterflood projects are under development, including
waterflood optimization projects at the Numbi and Takula fields and a major new
waterflood project in the Malongo Area. Areas B and C continue to be the primary
areas of major new development activity in the Block 0 concession. In 1998,
development of the Lomba Field and the southern portion of the Nemba Field
continued with completion of platform installation and development drilling, and
initiation of production. Lomba and Nemba both achieved forecasted peak
production rates in 1998. In Area C, development of the Sanha and Ndola fields
continued. In Block 14 four fields have been discovered to date: Kuito and
Landana, both discovered in 1997; and Benguela and Belize, both discovered in
1998. The first production from Block 14 is expected to begin in late 1999 from
the initial phase of the Kuito Field development. Kuito is being developed using
a phased approach, with production expected to peak at over 100,000 barrels per
day in 2001. Further appraisal and study is required prior to development
planning at Landana, the second Block 14 field discovered. Evaluation of
development options for Benguela and Belize development planning are expected to
be completed in 1999. Since both fields are immediately south of the Kuito
Field, joint development with Kuito is being evaluated.
In Nigeria, total gross production from 33 CNL-operated fields, where Chevron
has a 40 percent equity interest, averaged 418,000 barrels of oil per day,
slightly lower than 1997. Production levels in Nigeria in 1998 were restricted
by OPEC-mandated curtailments, which began in April 1998 and prevented the
company from achieving its initial 1998 production target of 470,000 barrels per
day from operated fields. Production from non-operated fields, where Chevron has
a 20 percent equity interest, averaged approximately 61,000 barrels of oil per
day in 1998, a decrease of 11,000 barrels per day from 1997, driven by the OPEC
curtailments. The Opolo Field began production in March 1998 at a rate of 20,000
barrels per day. The Gbokoda and Dibi fields also began production in 1998 with
additional production facilities planned for installation at Dibi in 1999.
Combined production from Dibi and Gbokoda is expected to reach a peak of 160,000
barrels of oil per day by 2000. Phase Two of the Escravos Gas Project continued
during 1998 and is scheduled for completion in the second quarter 2000. This
project provides a commercial outlet for LPG derived from natural gas produced
with the company's crude oil operations. Phase Two will expand the gas
processing capacity of the facility to 285 million cubic feet per day of
-13-
gas previously flared. LPG and condensate exports will increase to 14,000
barrels a day. Processed gas from the Escravos Gas Project will feed a proposed
30,000 barrel-per-day gas-to-liquids plant for the conversion of natural gas to
synthetic crude oil, which will be processed further into high-quality diesel
and naphtha products.
Offshore Republic of Congo, development wells targeting the Sounda and Kitina
South fields were drilled in 1998. Tie-back of the wells to the Kitina
facilities is currently being evaluated.
Other International including affiliated companies: Development expenditures in
1998, outside the United States and Africa, were $662 million compared with $840
million in 1997. The decrease between years was driven by lower 1998
expenditures in Canada, the United Kingdom, Papua New Guinea, Australia and by
the company's TCO affiliate in Kazakhstan. These decreases were partially offset
by increased 1998 expenditures in China. Additions to proved reserves, excluding
property sales and acquisitions, were 231 million barrels of crude oil and
natural gas liquids and 40 billion cubic feet of natural gas. In 1998, other
international operations replaced 115 percent of net liquids and gas production,
excluding property sales and acquisitions. This was driven by revisions in
Indonesia associated with PT Caltex Pacific Indonesia's (CPI) cost recovery
formula arising from the drop in prices for crude oil and natural gas. Such
revisions are dependent on crude oil and natural gas price movements and these
upward revisions could be reversed when prices rebound.
In Indonesia, Chevron holds interests in six production-sharing contracts, all
of which are managed by its 50 percent-owned equity affiliate, PT Caltex Pacific
Indonesia. Total CPI crude oil and condensate production averaged more than
760,000 barrels per day in 1998. The Duri Steamflood Project, begun in 1985 to
assist the difficult production process for the relatively heavy, waxy Duri
crude, is being completed in 13 stages (Areas 1-13) with eight areas currently
on production. Total Duri production averaged over 295,000 barrels per day in
1998. Area 9 is currently under development and should be placed on injection in
1999. A waterflood project involving 21 fields in Central Sumatra continued in
1998, as the installation of the fourth area in the Minas pattern waterflood
project was completed and work was initiated on expansion of the waterflood to
the northwest area. Construction of the Light Oil Steamflood pilot at Minas,
which began in 1997, is almost complete with first steam injection targeted for
early 1999. Chevron's Amoseas Indonesia (AI) affiliate in Indonesia operates the
Darajat geothermal contract in central Java. Steam from the Darajat geothermal
field, located 115 miles southeast of Jakarta, was produced and sold to the
national power company, PLN, for electricity generation in the PLN-owned Darajat
I power plant, for the fourth full year. Construction of the Darajat II 70
megawatts power plant, to be owned and operated by AI and its Indonesian
partner, was completed in the first quarter 1999. Geothermal reserves to support
a third power plant have been proved with a successful drilling program, which
continued in 1998.
In Kazakhstan, TCO's average liquids production was 188,000 barrels per day for
the year, an increase of 33,000 barrels per day over 1997. TCO is midway through
a three-year $1.3 billion plant expansion program that will increase capacity to
approximately 240,000 barrels per day in 2000. In 1998, a 400 square mile 3-D
land seismic survey was shot over the Tengiz Field as part of an integrated
development program. TCO also drilled its first well, which is the deepest well
drilled to date in the Tengiz reservoir. Testing of the well will begin in
mid-1999. 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 $2.2 billion. Final government approvals for
construction were obtained in November 1998. CPC anticipates awarding the major
construction contracts for the project during the second quarter of 1999. Under
the current schedule, first oil will be delivered by mid-2001. Chevron has a 15
percent ownership in CPC. When completed, the CPC pipeline will allow for the
export of 1.5 million barrels of oil per day from the region. A diversified
marketing and sales program has enabled the growth of Tengiz production. Tengiz
crude is transported by a variety of means including pipeline, rail and barge.
Principal destinations include the Baltic Sea, the Black Sea through Odessa and
through the Azerbaijan-Georgia corridor, as well as Caspian-region sales. In
1998, Chevron announced an agreement with the Republic of Georgia to reconstruct
an existing section of pipeline across the Republic and to evaluate construction
of a new section of pipeline to connect existing pipelines in the
Azerbaijan-Georgia corridor, which together will link Ali Bairamly in Azerbaijan
with Georgia's Black Sea port of Batumi.
In Europe, Chevron has interests in four producing fields offshore United
Kingdom and Norway: operated interests in the U.K. Alba oil field and Britannia
gas field; and non-operated interests in the Norwegian Statfjord and Draugen oil
fields. Total crude oil production from the Alba Field averaged 81,000 barrels
per day in 1998. Chevron's equity was reduced from 33.17 percent to 21.17
percent following an asset swap with Statoil in early
-14-
1998 for a 7.56 percent equity interest in the Draugen Field in the Norwegian
North Sea and an interest in five Norwegian exploration blocks. The Alba Phase
II development continued in 1998 with the completion of facility modifications,
which increase both oil and gross fluids handling capacity. The Alba Phase II
development project will enable development of the southern area reserves by
using the existing Alba Northern Platform. A new gas pipeline was laid in 1998
from Alba to the nearby Britannia Platform to optimize use of gas resources.
This pipeline, commissioned in early 1999, initially provides a disposal route
for Alba's surplus gas, significantly reducing the amount of gas being flared,
and in later years will provide a secure source of fuel gas to support Alba's
power requirements. First gas was produced from the Britannia Field in August
1998. At peak demand, the field can produce 740 million cubic feet of gas per
day and in excess of 50,000 barrels per day of condensate. Chevron has a 30.2
percent interest in Britannia and shares operatorship with Conoco. Chevron also
has a 19.42 percent interest in the Clair Field, located west of the Shetland
Islands.
In Canada, the company continued to aggressively grow its position in east coast
offshore acreage, while maintaining focus on core areas in western Canada.
Offshore Newfoundland, the Hibernia Development Project, in which Chevron holds
a 26.9 percent interest, successfully completed the first full year of
production, averaging 65,000 barrels of oil per day, with peaks over 100,000
barrels per day by year-end 1998. Additional development drilling and gas
injection is expected to increase production to 150,000 barrels per day in 1999.
Future Hibernia development also includes the Avalon reservoir and its 2 billion
barrels of oil in place. In October 1998, the 1.5 million-barrel Newfoundland
transshipment facility became operational, receiving the first shipment of
Hibernia crude. Chevron has a 30 percent interest in the facility, which will
help lower the cost of moving offshore Newfoundland crude oil to world markets.
The facility is designed for expansion to accommodate future developments. In
1998, Chevron's operations in western Canada produced 43,600 barrels per day of
crude oil and natural gas liquids, and 185 million cubic feet of natural gas per
day.
In Venezuela, Chevron, as operator, and Maraven S.A., a subsidiary of Petroleos
de Venezuela (PDVSA), are in an alliance in the Boscan oil field. The alliance
was formed to further develop the Boscan Field and to provide heavy crude oil to
Chevron in the United States through several independent supply arrangements.
Under an operating services agreement, Chevron receives operating expense
reimbursement and capital recovery, plus interest and an incentive fee. At
year-end 1998, Boscan was producing 105,000 barrels per day. Current plans call
for production to increase to 115,000 barrels per day in 1999; however,
production at the field is currently subject to an OPEC curtailment and may
average a lower rate for the year if the curtailment is extended. Because of
specific contract provisions in the Boscan Field Operating Services Agreement,
production and reserves for this field are not included in the company's
reported production and reserve quantities. In 1997, a consortium consisting of
Chevron, Statoil, Arco, and Phillips, with Chevron as operator, successfully bid
to operate the LL-652 Field located in the northeast section of Lake Maracaibo
under a 20-year agreement between the consortium and PDVSA. Chevron took over
the LL-652 operation in May 1998. The LL-652 oil field is estimated to contain
recoverable reserves exceeding 500 million barrels. During 1998, the consortium
started fabrication of central processing facilities (water injection platforms,
gas compression platform and production platform) and two satellite wellhead
structures. Incremental production will start in mid-1999. The objective for
LL-652 is to increase production to 115,000 barrels of oil per day by 2007 and
to recover the estimated reserves over the life of the operating agreement. In
1998, EPIC, a Venezuelan state-sponsored mutual fund, exercised its option to
participate as a 10 percent partner in LL-652 reducing Chevron's and Statoil's
equity interests to 27 percent each, and Arco and Phillips to 18 percent each.
In Australia, in the NWS project, a major refit of the Cossack Pioneer floating
production vessel during early 1999 is expected to increase Wanaea/Cossack crude
oil production capacity by over 20 percent and liquid petroleum gas production
capacity by over 50 percent starting in mid-1999. Planning for the proposed
expansion of the NWS project to handle its significant uncommitted gas reserves
continued to move forward during 1998, despite the Asian economic downturn. The
Asian markets provide a primary outlet for the gas production from the NWS
project. However, the uncertain timing of an economic recovery in some Asian
markets may cause a review of the current expansion timetable. WAPET development
activities continued in 1998 with projects designed to significantly increase
Barrow Island water injection and to increase crude oil production. The partners
in the WAPET-operated assets continued to evaluate options for the commercial
development of the Gorgon and Chrysaor gas fields as liquefied natural gas and
domestic gas projects.
-15-
In Papua New Guinea (PNG), Chevron (with an average 15 percent interest) and its
partners completed construction of production facilities associated with the
Gobe Petroleum Development Project in 1998. First oil production from Gobe Main
and South East Gobe occurred in March and April 1998, respectively. Peak
production of 45,000 barrels per day is expected in the second quarter 1999.
Evaluation of the Moran Central oil discovery continued in 1998 with the
completion of a successful third well and a successful two-mile step-out to the
northwest into Petroleum Prospecting License (PPL) -138, operated by Esso.
Extended well test production in Moran Central began in 1998. Production of
20,000 barrels per day in Moran Central is anticipated in 1999. Completion of
full field development is anticipated in 2000. During 1998, Chevron continued to
pursue the PNG to Queensland, Australia, Gas Pipeline Project, which would
permit commercialization of PNG natural gas reserves and the recovery of
substantial quantities of LPG's. A decision on the viability of the project is
expected in 1999.
Petroleum - Natural Gas Liquids
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)
1998 1997 1996
------- ------ ------
United States - Warren(1) - - 139
United States - Other 63 64 25
------- ------- ------
Total United States 63 64 164
Canada 26 30 27
Other International 7 13 9
------- ------- ------
Total Consolidated Companies 96 107 200
------- ------- ------
Share of Dynegy Affiliate 87 95 23
------- ------- ------
Total including Affiliate 183 202 223
======= ======= ======
(1) On September 1, 1996, the operations of Warren Petroleum were merged with
Dynegy Inc.
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. (formerly NGC) 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, significant natural
gas liquids sales take place in the company's Canadian upstream operations, with
lower sales levels in Africa, Australia and Europe. In 1998, 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.
Petroleum - 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, 1998, 1997, and 1996. During 1998, the company filed estimates of
oil and gas reserves with the Department of Energy, Energy Information Agency.
Those estimates were consistent with the reserve data reported on page FS-36 of
this Annual Report on Form 10-K.
The company sells 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. Outside the United States, the company is contractually committed to
deliver approximately 520 billion
-16-
cubic feet of natural gas through 2020 and 60 billion cubic feet of natural gas
through 2001 from Australian and U.K. reserves, respectively. 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.
Petroleum - Refining
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, 1998
-------------------
Refinery Inputs
Operable ---------------------------
Locations Number Capacity 1998 1997 1996
- - --------------------------------------------------- ------ -------- ------ ------ ------
Pascagoula, Mississippi 1 295 246 312 313
El Segundo, California 1 260 219 203 223
Richmond, California 1 225 201 220 220
El Paso,(1) Texas 1 65 62 60 60
Honolulu, Hawaii 1 54 49 53 54
Salt Lake City, Utah 1 45 40 41 40
Other(2) 3 102 52 44 41
--- ------ ------ ------ ------
Total United States 9 1,046 869 933 951
--- ------ ------ ------ ------
Burnaby, B.C., Canada 1 50 50 48 48
Milford Haven, Wales,(3) United Kingdom - - - 101 117
--- ------ ------ ------ ------
Total International 1 50 50 149 165
--- ------ ------ ------ ------
Total Consolidated Companies 10 1,096 918 1,082 1,116
Equity in Caltex Affiliate Various Locations 13 489 425 416 372
--- ------ ------ ------ ------
Total Including Affiliate 23 1,585 1,343 1,498 1,488
=== ====== ====== ====== ======
(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.
Based on refinery statistics published in the December 21, 1998, issue of The
Oil and Gas Journal, Chevron had the second largest U.S. refining capacity and
ranked number 11 in worldwide refining capacity, including its share of Caltex's
refining capacity. The company's 50 percent owned Caltex Corporation affiliate
owned or had interests in 13 operating refineries: Japan (2), Australia (2),
Thailand (2), Korea, the Philippines, New Zealand, Singapore, Pakistan, Kenya
and South Africa.
Distillation operating capacity utilization, adjusted for sales and closures, in
1998 averaged 83 percent in the United States (including asphalt plants) and 84
percent worldwide (including affiliate), compared with 89 percent in the United
States and 91 percent worldwide in 1997. Chevron's capacity utilization at its
U.S. fuels refineries averaged 86 percent in 1998, down from 94 percent in 1997.
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 75 percent in 1998, down from 80 percent in 1997.
The company's Pascagoula, Mississippi refinery was closed for nearly all of the
1998 fourth quarter following flooding caused by Hurricane Georges. The company
processed imported and domestic crude oil in its U.S. refining operations.
Imported crude oil accounted for 53 percent of Chevron's U.S. refinery inputs in
1998.
-17-
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," "Gulf" (principally in the United Kingdom prior to
the December 1997 disposition of that business) and "Caltex."
The following table shows the company's and its affiliate's refined product
sales volumes, excluding intercompany sales, over the past three years.
Refined Products Sales Volumes
(Thousands of Barrels Per Day)
1998 1997 1996
--------- --------- --------
United States
Gasolines 653 591 556
Jet Fuel 247 249 255
Gas Oils and Kerosene 198 204 186
Residual Fuel Oil 56 60 39
Other Petroleum Products(1) 89 89 86
--------- --------- --------
Total United States 1,243 1,193 1,122
--------- --------- --------
International
United Kingdom(2) 3 103 110
Canada 58 61 60
Other International 127 145 180
--------- --------- --------
Total International 188 309 350
--------- --------- --------
Total Consolidated Companies 1,431 1,502 1,472
Chevron's Share in Affiliate 597 577 594
--------- --------- --------
Total Including Affiliate 2,028 2,079 2,066
========= ========= ========
(1) Principally naphtha, lubes, asphalt and coke.
(2) Retail marketing assets in the United Kingdom were sold in December
1997
The company's Canadian sales volumes consist of refined product sales in British
Columbia and Alberta by the company's Chevron Canada Limited subsidiary. The
1998 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 affiliate's sales
consists of the company's interest in Caltex Corporation, which maintains an
interest in about 8,000 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.
Retail Outlets: In the United States, the company supplies, directly or through
jobbers, more than 7,900 motor vehicle retail outlets, of which more than 1,600
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 14
states, and is the top marketer of aviation fuel in the western United States.
Convenience store sales are an area of growth and opportunity for the company.
In 1998, the company increased the number of convenience stores in the United
States by ten percent to nearly 700 stores and experienced an overall
company-operated sales growth of over 30 percent.
In 1998, Chevron continued to implement an alliance with McDonald's to develop a
network of retail sites that combine Chevron stations and convenience stores
with McDonald's restaurants in 12 western and southwestern states. As of
year-end 1998, the two companies operated over 100 sites together in these
states.
-18-
Internationally, the company's branded products are sold in 191 stations (all
owned or leased) in British Columbia, Canada. The company also has interests in
three service stations in the Caspian Sea region, which sell products under the
Chevron brand.
Petroleum - Transportation
Tankers: Chevron's controlled seagoing fleet at December 31, 1998, is summarized
in the following table. All controlled tankers were utilized in 1998. In
addition, at any given time, the company has 25 to 35 vessels under charter on a
term or voyage basis.
Controlled Tankers At December 31, 1998
U.S. Flag Foreign Flag
-------------------------------- -------------------------------
Cargo Capacity Cargo Capacity
Number (Millions of Barrels) Number (Millions of Barrels)
------- -------------------- ------- ---------------------
Owned 2 0.8 20 19.5
Bareboat Charter 2 0.5 10 14.7
Time-Charter - - 1 0.5
------- ----- ------- -----
Total 4 1.3 31 34.7
======= ===== ======= =====
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 1998, the company's U.S. flag
fleet was engaged primarily in transporting crude oil from Alaska and California
terminals 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.
At year-end 1998, two of the company's controlled international flag vessels
were assigned for use as floating storage vessels. One of these vessels was in
dry-dock for periodic overhaul. 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 1998, the company completed the sale of one domestic tanker.
Additionally, in 1998 the company took delivery of one new 304,000 deadweight
ton, double-hull tanker, which it will operate under bareboat charter. The
tanker is the first in a series of four new double-hull tankers being built in
Korea. The second tanker was delivered in March 1999. The next vessel is
expected to be delivered later in 1999 and the last one in early 2000. Chevron
will operate these tankers under long-term bareboat charters.
The Federal Oil Pollution Act of 1990 (OPA) created federal authority to direct
private responses to oil spills, to improve preparedness and response
capabilities, and to impose monetary damages on those who spill for all damages,
including environmental restoration and loss of use of the resources during
restoration. Under OPA, owners or operators of vessels operating in U.S. waters
or transferring cargo in waters within the U.S. Exclusive Economic Zone are
required to possess a Certificate of Financial Responsibility for each of these
vessels. The U.S. Coast Guard issues the Certificate after the owner or operator
has demonstrated the ability to meet Coast Guard guidelines for financial
responsibility in the case of an oil spill. OPA also 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 2000, Chevron
will be operating a total of 14 double hull tankers. A separate single hull
phase-out schedule under the International Maritime Organization's Regulation 13
is leading to the utilization of more costly double-hull tankers in all other
parts of the world. 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
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addition, the company is a member of many oil-spill
response cooperatives in areas in which it operates around the world.
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:
Pipeline Mileage At December 31, 1998
Wholly Partially
Owned Owned(1) Total
--------- --------- --------
United States:
Crude oil(2) 3,651 445 4,096
Natural gas 477 165 642
Petroleum products 2,090 2,621 4,711
--------- --------- --------
Total United States 6,218 3,231 9,449
--------- --------- --------
International:
Crude oil - 1,038 1,038
Natural gas - 275 275
Petroleum products - 720 720
--------- --------- --------
Total International - 2,033 2,033
--------- --------- --------
Worldwide 6,218 5,264 11,482
========= ========= ========
(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 1998, Chevron owned and operated 15 U.S.
manufacturing facilities in nine states, owned manufacturing facilities in
Brazil, France and Mexico, and owned a majority interest in a manufacturing
facility in Japan. The principal U.S. plants are located at Cedar Bayou, Orange
and Port Arthur, Texas; St. James and Belle Chasse, Louisiana; Marietta, Ohio;
Pascagoula, Mississippi; and Richmond, California.
During 1998, the company completed plant expansions to increase paraxylene
production at Pascagoula, Mississippi and ethylene production at Cedar Bayou,
Texas. Planned expansions to polyethylene capacity at Orange, Texas and an
ethylbenzene project at Pascagoula, Mississippi are expected to be completed in
1999. These expansions are intended to position the company to take advantage of
future demand anticipated with the next upturn in the chemicals industry as well
as to further reduce unit operating costs.
In 1998, Chevron completed construction of a fuel and lube oil additives
manufacturing facility in Singapore, which began commercial production in
January 1999. 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, neared completion 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. This facility is expected to begin commercial operation in
mid-1999. The company also broke ground on a 100,000 tons per year
-20-
polystyrene plant in China. This plant, scheduled to begin production in early
2000, will represent the company's entry into the chemicals business in China.
The following table shows 1998 revenues and the number of owned or majority
owned chemicals manufacturing facilities and combined operating capacities as of
December 31, 1998.
Chemicals Operations
1998
Annual --------------------------------
Manufacturing Capacity Production Revenue*
Facilities (million lbs.) (million lbs) ($ Millions)
---------------- -------------- ------------- -------------
U.S. 15 16,032 13,211 $2,591
International 4 701 521 625
- ------- ------------ -------------
Total 19 16,733 13,732 $3,216
== ======= ============ =============
*Excludes intercompany sales.
Coal and Other Minerals
Coal: The company's wholly owned coal mining and marketing subsidiary, The
Pittsburg and Midway Coal Mining Co. (P&M), owned four surface and two
underground mines at year-end 1998. Two of the mines are located in New Mexico
and one each in Wyoming, Alabama, Texas and Kentucky. All mines were operating
at year-end 1998 with the exception of the Sebree mine in Kentucky, which was
idled in November 1998. In 1998, P&M acquired the Farco Mine and associated port
facilities in Texas. P&M also owns a 29.8 percent interest in Inter-American
Coal Holding N.V., which has interests in mining operations in Venezuela. P&M
also owned a 33 percent interest in the Black Beauty Coal Company, whose
principal operations are in Indiana and Illinois. Sales and other operating
revenues from P&M in 1998 were $402 million, an increase of 12 percent from
1997.
All of the company's coal assets were offered for sale in the third quarter
1998. In March 1999, P&M sold its interest in the Black Beauty Coal Company and
expects to record a gain in the first quarter 1999. The company's remaining coal
assets were still held for sale in late March 1999.
Research and Environmental Protection
Research: The company's principal research laboratories are at Richmond and La
Habra, California, and Houston, Texas. In February 1999, the company announced
its intention to relocate the activities carried out at La Habra, primarily to
the San Francisco Bay Area, California, commencing in the second quarter 1999.
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 La Habra and Houston facilities
conduct research and provide technical support in geology, geophysics and other
exploration sciences, as well as 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 1998
numbered more than 1,000, with approximately 500 additional employees working on
research activities in the company's other operating units.
Chevron's research and development expenses were $187 million, $179 million and
$182 million for the years 1998, 1997 and 1996, respectively.
Licenses under the company's patents are generally made available to others in
the petroleum and chemicals industries, but the company's business is not
dependent upon licensing patents.
-21-
Environmental Protection: One of Chevron's goals is to be recognized worldwide
for environmental protection excellence, and commitment to the environment
remains an integral part of the company's business philosophy. In 1992, Chevron
established a systematic approach for improving health, safety and environmental
performance. The program is called "Protecting People and the Environment" and
applies to operations worldwide. The program defines 10 categories of
performance, supported by 102 specific management practices, which have been
integrated into local management systems. In 1997, the company published a
report called "Protecting People and the Environment - A Report on Chevron's
Practices and Performance," which summarizes the company's health, environmental
and safety practices and performance.
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 the
United States, the company expects the enactment of additional federal and state
regulations addressing the issue of waste management and disposal and effluent
emission limitations for offshore oil and gas operations. While the costs of
operating in an environmentally responsible manner and complying with existing
and anticipated environmental legislation and regulations, including loss
contingencies for prior operations, are expected to be significant, the company
does not believe that such costs have had, or will have, a material impact on
its consolidated financial position, its liquidity, or its competitive position
relative to other domestic or international petroleum or chemicals concerns.
In California, the company uses the chemical MTBE to meet the federal and state
regulations requiring oxygenation of gasoline. There is currently an ongoing
public debate concerning the industry's use of MTBE and its potential
environmental impact through seepage into drinking water wells. On March 25,
1999, the Governor of California ordered a phase out of the use of MTBE in
gasoline sold in California, to be completed by December 31, 2002. Chevron's
ultimate exposure related to this issue will depend on the nature of any
increased regulations, the availability and costs of alternate formulations, and
it's ability to recover any additional costs of production through prices
charged to its customers.
In 1998, the company's U.S. capitalized environmental expenditures were $192
million, representing approximately seven percent of the company's total
consolidated U.S. capital and exploratory expenditures. The company's U.S.
capitalized environmental expenditures were $177 million and $157 million in
1997 and 1996, 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 1999,
the company estimates U.S. capital expenditures for environmental control
facilities will be approximately $212 million. The future annual capital costs
of fulfilling this commitment are uncertain, but are expected to remain close to
the estimated 1999 levels.
Under provisions of state and federal Superfund laws, Chevron has been
designated as a potentially responsible party (PRP) for remediation at 289
hazardous waste sites. Since remediation costs will vary from site to site as
will the company's share of responsibility for each site, the number of sites in
which the company has been identified as a PRP should not be used as a relevant
measure of total liability. No single site is expected to result in a material
liability for the company. At year-end 1998, the company's environmental
remediation reserve related to Superfund sites amounted to $48 million.
Forecasted expenditures for the largest of these sites, located in Texas,
amounts to approximately 19 percent of the reserve.
The company's 1998 environmental expenditures, remediation provisions and
year-end environmental reserves are discussed on pages FS-5 and FS-6 of this
Annual Report on Form 10-K. These pages also contain additional discussion of
the company's liabilities and exposure under Superfund laws and additional
discussion of the effects of the Clean Air Act Amendments of 1990.
-22-
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 1998, 1997 and 1996.
Item 3. Legal Proceedings
A. Cities Service Co. v. The Gulf Oil Corporation
Oklahoma State District Court for the District of Tulsa.
This is an action by Cities Service Company (now OXY USA Inc. as successor in
interest) against Gulf Oil Corporation (now Chevron U.S.A. Inc.) and GOC
Acquisition Corporation ("Gulf") alleging breach of contract, malicious breach
of contract, and fraud arising out of a terminated merger agreement. The
complaint was originally filed in August 1982 in Oklahoma State Court. Trial
commenced April 15, 1996.
On July 18, 1996, the jury returned a verdict for Gulf on Cities' fraud and
malicious breach of contract claims. On Cities' breach of contract claim, the
court directed verdicts that (1) Gulf had breached the contract, (2) Cities was
entitled to recover certain attorneys' fees related to the Gulf/Cities merger,
and (3) Cities was entitled to recover the cost of a settlement with and
repurchase of the stock from Mesa Petroleum Corporation if the jury found that
the settlement and repurchase were done in reliance on the merger agreement with
Gulf. In its verdict, the jury found against Gulf on the reliance issue.
Accordingly, on July 19, 1996, the court entered a judgment of $742,206,906
against Gulf, which included $512,585,506 in prejudgment interest awarded by the
court, which interest continues to accrue at 9.55 percent per year. No motions
for relief from the judgment were filed in the trial court. On July 31, 1996,
the court approved Gulf's supersedeas bond, thus staying enforcement of the
judgment during pendency of Gulf's appeal.
On August 14, 1996, Gulf appealed from the judgment. On December 31, 1996, the
Oklahoma Supreme Court granted the parties' motion to retain the appeal for
decision, rather than having it transferred to the Oklahoma Court of Appeals.
Gulf filed its opening brief on March 12, 1997; Cities filed its answering brief
on June 23, 1997 and Gulf filed its reply brief on August 4, 1997. On March 2,
1999, the Oklahoma Supreme Court affirmed the judgment against Gulf, and on
March 22, 1999 Gulf filed a petition for rehearing in the Oklahoma Supreme
Court.
B. El Segundo Refinery - Local Air District Rules.
In 1998, the United States Environmental Protection Agency issued a Notice of
Violation to the company alleging violations of a local air district rule at the
company's El Segundo refinery. The case has been referred to the Department of
Justice, but discovery has been stayed while the parties seek to negotiate a
settlement. Civil penalties are expected to exceed $100,000.
C. El Paso Refinery - Generation of Benzene.
In 1998, the Texas National Resource Conservation Commission proposed that the
company accept an administrative penalty of $550,000 for alleged violations of
Texas State Law requiring an accurate determination of the quantities of benzene
generated at the company's El Paso refinery for the years 1993 through 1996, and
for allegedly failing to install required benzene waste control equipment on a
timely basis. The company disputes these charges.
Other previously reported legal proceedings have been settled, not pursued, or
the issues resolved so 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 1998 to a vote of security
holders through the solicitation of proxies or otherwise.
-23-
Executive Officers of the Registrant at March 1, 1999
Name and Age Executive Office Held Major Area of Responsibility
K.T. Derr 62 Chairman of the Board since Chief Executive Officer
1989
Director since 1981
Executive Committee Member
since 1986
D.J. O'Reilly 52 Vice-Chairman of the Board Worldwide Exploration and
since 1998 Production Activities, Human
Director since 1998 Resources
Executive Committee Member
since 1994
J.N. Sullivan 61 Vice-Chairman of the Board Worldwide Refining,Marketing
since 1989 and Transportation Activities,
Director since 1988 Chemicals, Real Estate,
Executive Committee Member Environmental, Coal,
since 1986 Administrative Services,
Aircraft Services
H.D. Hinman 58 Vice-President and General Law
Counsel since 1993
Executive Committee Member
since 1993
M.R. Klitten 54 Vice-President and Chief Finance
Financial Officer
since 1989
Executive Committee Member
since 1989
R.H. Matzke 62 Vice-President since 1990 Overseas Exploration and
Director since 1997 Production
President of Chevron Overseas
Petroleum Inc.since 1989
Executive Committee Member
since 1993
D.W. Callahan 56 Vice-President since 1999 Chemicals
President of Chevron Chemical
Company since 1999
Executive Committee Member
since 1999
P.J. Robertson 52 Vice-President since 1994 North American Exploration and
President of Chevron U.S.A. Production,Natural Gas Liquids
Production Company
since 1997
Executive Committee Member
since 1997
P.A. Woertz 45 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.
-24-
D.W. Callahan - Senior Vice President, Chevron Chemical Company - 1991
- President, Chevron Chemical Company - 1999
D.J. O'Reilly - Vice-President for Strategic Planning and Quality,
Chevron Corporation - 1991
- Vice-President, Chevron Corporation and
President, Chevron U.S.A. Products Company - 1994
- Vice-Chairman of the Board - 1998
P.J. Robertson - President of Warren Petroleum Company - 1991
- 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 Ltd. - 1993
- President, Chevron International Oil Company - 1996
- Vice President, Logistics and Trading,
Chevron Products Company - 1996
- President, Chevron Products Company - 1998
PART II
Item 5. Market for the Registrant's Common Equity and
Related Stockholder Matters
The information on Chevron's common stock market prices, dividends, principal
exchanges on which the stock is traded and number of stockholders of record is
contained in the Quarterly Results and Stock Market Data tabulations, on page
FS-13 of this Annual Report on Form 10-K.
Item 6. Selected Financial Data
The selected financial data for years 1994 through 1998 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.
-25-
PART III
Item 10. Directors and Executive Officers of the Registrant
The information on Directors appearing on pages 5 through 8 of the Notice of
Annual Meeting of Stockholders and Proxy Statement dated March 22, 1999, is
incorporated herein by reference in this Annual Report on Form 10-K. See
Executive Officers of the Registrant on pages 24 and 25 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 13 of the Notice of Annual Meeting of
Stockholders and Proxy Statement dated March 22, 1999 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 1998.
Item 11. Executive Compensation
The information on pages 14 through 21 of the Notice of Annual Meeting of
Stockholders and Proxy Statement dated March 22, 1999, 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 13 of the Notice of Annual Meeting of Stockholders and
Proxy Statement dated March 22, 1999 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-14
Consolidated Statement of Income
for the three years ended December 31, 1998 FS-14
Consolidated Statement of Comprehensive Income
for the three years ended December 31, 1998 FS-14
Consolidated Balance Sheet at December 31,
1998 and 1997 FS-15
Consolidated Statement of Cash Flows
for the three years ended December 31, 1998 FS-16
Consolidated Statement of Stockholders' Equity
for the three years ended December 31, 1998 FS-17
-26-
Notes to Consolidated Financial Statements FS-18 to FS-31
(2) Financial Statement Schedules:
Caltex Group of Companies Combined
Financial Statements C-1 to C-27
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 29 and 30 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 23, 1998, was filed by
the company on November 25, 1998. In this report, Chevron announced
a new Stockholder Rights Agreement and an associated rights
dividend payable on shares of Chevron's Common Stock.
(2) A Current Report on Form 8-K, dated January 26, 1999, was filed by
the company on January 26, 1999. In this report Chevron announced
its preliminary, unaudited earnings for the year ended December 31,
1998.
(3) A Current Report on Form 8-K, dated February 2, 1999, was filed by
the company on February 2, 1999. In this report Chevron filed
consents of Independent Accountants.
(4) A Current Report on Form 8-K dated March 8, 1999, was filed by the
company on March 8, 1999. In this report Chevron announced its
revised earnings for the year ended December 31, 1998.
-27-
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 31st day of March
1999.
Chevron Corporation
By KENNETH T. DERR*
--------------------------------------
Kenneth T. Derr, 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 31st day of March 1999.
Principal Executive Officers (And Directors) Directors
KENNETH T. DERR* SAMUEL H. ARMACOST*
--------------------------------------------- -------------------------
Kenneth T. Derr, Chairman of the Board Samuel H. Armacost
JAMES N. SULLIVAN* SAM GINN *
--------------------------------------------- -------------------------
James N. Sullivan, Vice-Chairman of the Board Sam Ginn
DAVID J. O'REILLY* CARLA A. HILLS*
--------------------------------------------- -------------------------
David J. O'Reilly, Vice-Chairman of the Board Carla A. Hills
J. BENNETT JOHNSTON*
-------------------------
J. Bennett Johnston
RICHARD H. MATZKE*
-------------------------
Principal Financial Officer Richard H. Matzke
MARTIN R. KLITTEN* CHARLES M. PIGOTT*
--------------------------------------------- -------------------------
Martin R. Klitten, Vice-President Charles M. Pigott
and Chief Financial Officer
CONDOLEEZZA RICE*
-------------------------
Principal Accounting Officer Condoleezza Rice
STEPHEN J. CROWE* FRANK A. SHRONTZ*
--------------------------------------------- -------------------------
Stephen J. Crowe, Comptroller Frank A. Shrontz
CHANG-LIN TIEN *
-------------------------
Chang-Lin Tien
GEORGE H. WEYERHAEUSER *
-------------------------
George H. Weyerhaeuser
*By: /s/ LYDIA I. BEEBE JOHN A. YOUNG*
------------------------------------------ -------------------------
Lydia I. Beebe, Attorney-in-Fact John A. Young
-28-
EXHIBIT INDEX
Exhibit
No. Description
- - ------- ---------------------------------------------------------------------
3.1 Restated Certificate of Incorporation of Chevron Corporation,
dated November 23, 1998.
3.2 By-Laws of Chevron Corporation, as amended November 23, 1998.
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.
-29-
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 LLP (page E-4).
24.1 Powers of Attorney for directors and certain officers of Chevron
to Corporation, authorizing the signing of the Annual Report on
24.16 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.
-30-
INDEX TO MANAGEMENT'S DISCUSSION AND ANALYSIS
CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page(s)
-------------
Management's Discussion and Analysis FS-2 to FS-12
Quarterly Results and Stock Market Data FS-13
Report of Management FS-13
Consolidated Statement of Income FS-14
Consolidated Statement of Comprehensive Income FS-14
Report of Independent Accountants FS-14
Consolidated Balance Sheet FS-15
Consolidated Statement of Cash Flows FS-16
Consolidated Statement of Stockholders' Equity FS-17
Notes to Consolidated Financial Statements FS-18 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
1998 KEY INDICATORS
- - -------------------
* Net income of $1.339 billion for 1998 declined 59 percent from 1997's
record level
* Average 1998 U.S. crude oil realizations declined 35 percent to $11.42 per
barrel, the lowest in 20 years
* Average 1998 U.S. natural gas realizations declined 17 percent to $2.02 per
thousand cubic feet
* International liquids production increased for the ninth consecutive year,
increasing 7 percent during 1998
* Operating, selling, general and administrative expenses for 1998, excluding
special items, declined by $300 million
* Worldwide net oil and gas reserve additions exceeded production for the
sixth consecutive year
* Annual dividends increased for the 11th consecutive year
KEY FINANCIAL RESULTS
- - ---------------------
Millions of dollars,
except per-share amounts 1998 1997 1996
- - -------------------------------------------------------------------
Sales and
Other Operating Revenues ... $ 29,943 $ 40,596 $ 42,782
Net Income ................... $ 1,339 $ 3,256 $ 2,607
Special (Charges) Credits
Included in Net Income ....... $ (606) $ 76 $ (44)
Per Share:
Net income - basic......... $ 2.05 $ 4.97 $ 3.99
- diluted ...... $ 2.04 $ 4.95 $ 3.98
Dividends .................... $ 2.44 $ 2.28 $ 2.08
Return on:
Average Capital Employed ... 6.7% 15.0% 12.7%
Average Stockholders' Equity 7.8% 19.7% 17.4%
Chevron's net income for 1998 was $1.339 billion, down 59 percent from record
earnings of $3.256 billion in 1997 and down 49 percent from $2.607 billion in
1996. Excluding special items, earnings in 1998 were $1.945 billion, down 39
percent from $3.180 billion in 1997 and down 27 percent from $2.651 billion in
1996. Foreign currency losses were $47 million in 1998, compared with gains of
$246 million in 1997 and losses of $26 million in 1996.
Net income for 1998, compared with 1997 and 1996, also included more favorable
effects from income tax adjustments, including those resulting from the
finalization of the company's 1997 U.S. federal income tax return, larger net
gains from property sales and higher proceeds from favorable settlements of
insurance and other claims.
Net income for the company's individual business segments is discussed in the
Results of Operations section.
NET INCOME BY MAJOR OPERATING AREAS
- - -----------------------------------
Millions of dollars 1998 1997 1996
- - -------------------------------------------------------------------------------
Exploration and Production
United States ............................... $ 365 $ 1,001 $ 1,087
International ............................... 707 1,252 1,211
- - -------------------------------------------------------------------------------
Total Exploration and Production 1,072 2,253 2,298
- - -------------------------------------------------------------------------------
Refining, Marketing and Transportation
United States ............................... 572 601 193
International ............................... 28 298 226
- - -------------------------------------------------------------------------------
Total Refining, Marketing
and Transportation .......................... 600 899 419
- - -------------------------------------------------------------------------------
Chemicals ................................... 122 228 200
All Other ................................... (455) (124) (310)
- - -------------------------------------------------------------------------------
Net Income .................................. $ 1,339 $ 3,256 $ 2,607
- - -------------------------------------------------------------------------------
Special Items ............................... (606) 76 (44)
- - -------------------------------------------------------------------------------
Net Income, Excluding Special Items ......... $ 1,945 $ 3,180 $ 2,651
===============================================================================
OPERATING ENVIRONMENT AND OUTLOOK.
Crude oil prices fell dramatically during 1997 and 1998, with average prices for
1998 reaching their lowest levels in 20 years. The price of spot West Texas
Intermediate (WTI) crude oil averaged $22.15 per barrel for 1996. Prices fell
throughout 1997, averaging $20.60 per barrel for the year. The downward price
trend continued throughout 1998, with crude oil prices in the $13 to $15 range
most of the year. The average spot WTI price for 1998 fell to $14.38 per barrel
for the year and $11.28 for the month of December. Prices have not improved
significantly in 1999, averaging $12.24 per barrel through February and closing
at $13.35 on March 4, 1999. Chevron's U.S. crude oil realizations averaged
$11.42 per barrel for 1998, down 35 percent and 39 percent from average
realizations for 1997 and 1996, respectively.
A number of factors continue to exert downward pressure on crude oil prices.
Worldwide supplies have increased because of start-ups of new producing fields
and higher production from existing fields, while the growth in demand has
slowed, resulting in an oversupplied world market. In addition, inventories in
early 1999 remained high. It is uncertain how long these conditions will
continue. The low crude oil prices, if they persist, could hold down the
company's revenues and earnings, particularly in the exploration and production
(upstream) operations of the company.
The company does not expect significant improvements in the prices for crude
oil, natural gas and commodity chemicals in the near term. To help offset the
impact from low prices, Chevron intends to reduce its cost structure by an
additional $500 million in 1999 while selectively investing in areas that
provide the greatest opportunities for growth. During 1999, Chevron intends to
focus its capital spending on international exploration and production projects,
which the company considers its growth engine for the future. However, timely
completion of the planned projects will be dependent upon, among other factors,
the ability of our partners, some of which are national petroleum companies, to
fund their share of the costs. The company expects to minimize capital spending
in the international chemicals and downstream (refining, marketing and
transportation) businesses.
Increases in oil and equivalent gas (OEG) production, primarily in the company's
international areas such as West Africa, offshore eastern Canada, Indonesia and
the U.K. North Sea, have helped to offset partially the effects of low crude oil
and natural gas prices. Additional oil and gas production increases are expected
in the next few years from developments in West Africa, Hibernia and other
prospects offshore eastern Canada, the deep waters of the U.S. Gulf of Mexico,
and from continued expansion of production from the Tengiz Field in Kazakhstan.
Chevron's U.S. refining, marketing and transportation business was affected
adversely by lower product margins in 1998 and the September hurricane that
closed the company's Pascagoula, Mississippi, refinery for most of the 1998
fourth quarter. These factors were offset partially by higher refined products
sales volumes and lower operating expenses.
In the international refining, marketing and transportation segment, the
company's Caltex affiliate's earnings have been, and will continue to be,
affected by the economic slowdown in the Asia-Pacific region and fluctuations in
the value
FS-2
of Asian currencies. In western Canada, retail product margins declined in 1998
as a result of increased competition.
A cyclical downturn began in the worldwide chemicals industry in the second half
of 1995 and continues into 1999. The company's operating earnings from chemicals
operations continued to decline in 1998. Prices of chemicals products remain
depressed, reflecting industry overcapacity, stagnant demand - especially in
Asia - and increasing inventories.
SIGNIFICANT DEVELOPMENTS.
Chevron's 1998 worldwide net proved barrels of OEG reserves additions exceeded
production for the sixth consecutive year. The worldwide net proved OEG reserves
replacement was 119 percent for 1998, excluding sales and acquisitions.
Worldwide OEG production was up 2 percent in 1998, with international net
liquids production increasing 7 percent.
Total liquids production from the Tengiz Field in Kazakhstan in 1998 averaged
188,000 barrels per day (BPD), an increase of 21 percent over 1997 average
production of 155,000 BPD. Production from the field averaged 218,000 BPD in
December 1998. Chevron operates the facilities at Tengiz for Tengizchevroil, in
which the company has a 45 percent ownership interest. Final local government
approvals were secured in late 1998, permitting construction to begin in 1999,
on the Caspian Pipeline Consortium's (CPC) pipeline that will deliver crude oil
from the Tengiz Field to the Black Sea port of Novorossiysk. Chevron has a 15
percent interest in CPC. The completion of this pipeline in 2001 will provide
additional transportation outlets for Kazakh crude oil and is critical for
future expansion of production capacity at the Tengiz Field.
The daily rate of production at Block 0 in Angola, in which Chevron has a 39
percent interest, reached a record 514,000 BPD in December 1998. New production
commenced during the year at the South Nemba and Lomba fields. In deepwater
Angola Block 14, in which the company has a 31 percent interest, the third and
fourth commercial discoveries were made in 1998. First production in Block 14 is
expected by year-end 1999 from the initial phase of the Kuito Field development,
while the company prepares its overall Block 14 development plan.
Chevron's share of net liquids production in Nigeria declined slightly to
150,000 BPD in 1998 as a result of OPEC-directed production curtailments. New
production began from the Dibi, Gbokoda and Opolo oil fields during the year. In
early 1999, the government of Nigeria announced it will fund only a portion of
the budgets submitted for oil and gas activities for 1999. New exploration and
development projects, as well as ongoing projects, may be delayed as a result of
this funding decision.
Offshore eastern Canada, the Hibernia Field completed its first full year of
operation. For 1998, production averaged 65,000 BPD, with daily peaks over
100,000 BPD by year-end. After additional development drilling and gas
injection, Hibernia peak daily production rates are expected to reach 150,000
BPD in 1999. Chevron holds a 26.9 percent interest in Hibernia.
International average natural gas production increased by about 14 percent in
1998, primarily reflecting increases in the United Kingdom and Nigeria. In
August 1998, natural gas production began at the Britannia Field, in which
Chevron holds a 30.2 percent interest, in the U.K. North Sea. In December 1998,
the field produced over 600 million cubic feet of gas per day and about 45,000
barrels per day of condensate. In Nigeria, Phase 2 of the Escravos Gas Project
is under construction. The Escravos Gas Project processes natural gas, which was
previously flared into the atmosphere, into liquefied petroleum gas for use in
the domestic market and as condensate for export.
The company signed agreements to explore in Qatar and Bahrain during the first
quarter of 1998. In the same quarter, production began at the Moran and Gobe
fields in Papua New Guinea. In December, Chevron announced it had executed a
purchase agreement with Rutherford-Moran Oil Corporation, which owns a 46
percent interest in Block B8/32 in the Gulf of Thailand. This acquisition in
Southeast Asia may lead to other investments in the area.
Chevron acquired 66 additional deepwater tracts at U.S. federal lease sales
during the year, furthering its intent to be a major participant in the
development of the U.S. Gulf of Mexico deep waters. The company's deepwater
inventory consisted of 428 tracts at year-end 1998. Construction and
installation of production facilities at the company's first deepwater Gulf
operation, Genesis, were completed, and production began in January 1999.
Chevron is the operator with a 57 percent working interest. Another of the
company's deepwater projects, Gemini, is expected to begin production later in
1999.
Chevron completed the sale of platforms Gail and Grace, located in federal
waters in the southeast end of the Santa Barbara Channel, and their associated
platform-to-shore pipelines in February 1999. In March 1999, the company
received approval from its partners to sell its interests in the producing,
processing and transportation assets in the Point Arguello area, completing the
sale of its entire offshore California operations.
In February 1999, Chevron and a unit of Atlantic Richfield, ARCO Permian,
announced an agreement to exclusively pursue a combination of the two companies'
oil and gas producing assets in the Permian Basin of West Texas and southeast
New Mexico. If a final agreement is reached, ARCO and Chevron will each own 50
percent of a new company to be headquartered in Midland, Texas. The new entity
is expected to develop and produce oil and natural gas, and market crude oil,
natural gas, natural gas liquids and related products in the Permian Basin.
Operations will consist of more than 7,000 wells and 150 fields, representing
600 million barrels of proved reserves and producing over 170,000 BPD of oil
equivalents. In addition, the company would produce, transport and market carbon
dioxide from assets contributed by ARCO and Chevron in Colorado.
Chevron Chemical Company began commercial production in January 1999 at its new
$215 million Singapore plant, the largest fuel and lubricating additives
manufacturing plant in Asia. The plant will manufacture 26 additive components
from over 40 different raw materials and make more than 150 additive package
blends tailored to customer needs. The company expects to begin commercial sales
from the Singapore plant in March 1999.
On January 1, 1999, 11 of the 15 member countries of the European Union began
converting to the "euro" by establishing fixed conversion rates between their
existing sovereign currencies and the euro. Chevron has evaluated the
FS-3
impact of the conversion of the euro and has concluded that, based on the
company's current level of activity, the conversion will not have a material
impact on its business or financial condition.
YEAR 2000 PROBLEM.
The Year 2000 problem is the result of computer systems and other equipment with
embedded chips or processors using two digits, rather than four, to define a
specific year and potentially being unable to process accurately certain data
before, during or after 2000. This could result in system failures or
miscalculations, causing disruptions to various activities and operations.
Chevron has established a corporate-level Year 2000 project team to coordinate
the efforts of teams in the company's operating units and corporate departments
to address the Year 2000 issue in three major areas: information technology,
embedded systems and supply chain. Information technology includes the computer
hardware, systems and software used throughout the company's facilities.
Embedded systems exist in automated equipment and associated software, which are
used in the company's exploration and production facilities, refineries,
transportation operations, chemical plants and other business operations. Supply
chain includes the third parties with whom Chevron conducts business. The
company also is monitoring the Year 2000 efforts of its equity affiliates and
joint-venture partners. Progress reports on the Year 2000 project are presented
regularly to the company's senior management and periodically to the Board Audit
Committee.
The company is addressing the Year 2000 issue in three overlapping phases: (1)
the identification and assessment of all critical equipment, software systems
and business relationships that may require modification or replacement prior to
2000; (2) the resolution of critical items through remediation and testing of
modifications, replacement, or development of alternative business processes;
and (3) the development of contingency and business continuation plans for
critical items to mitigate any disruptions to the company's operations.
Chevron intends to address all critical items prior to 2000. Phase 1 -
identification and assessment - is essentially complete. The company estimates
that at December 31, 1998, it had completed approximately 30 percent of Phase 2
activities. Phase 2 is expected to be about 75 percent complete by the end of
the second quarter 1999 and essentially finished by the end of the third quarter
1999. Phase 3 is also scheduled for completion at the end of the third quarter.
The company is using a risk-based analysis of its operations to identify those
items deemed to be "mission critical," defined as having the potential for
significant adverse effects in one or more of five areas: environmental, safety,
ongoing business relationships, financial and legal exposure, and company
credibility and image. To date, over 300 items of varying degrees of complexity
in the company's own operations and about 1,000 third-party relationships have
been deemed mission-critical. Many mission-critical items already have been
found to be compliant, while others are undergoing remediation and testing. The
company's major financial systems and desktop computer systems were upgraded in
separate projects and are already compliant. Chevron is corresponding with all
mission-critical third parties and expects to meet with a large percentage of
them, either alone or with other potentially affected parties, to determine the
relative risks of major Year 2000-related problems and to determine how to
mitigate such risks. Additional items and third-party relationships may be added
to or removed from this population as more information becomes available.
Using practical risk assessment and testing techniques, Chevron is dividing its
list of more than 300 internal items into three categories: (1) those that are
expected to be tested and made Year 2000 compliant prior to 2000; (2) items that
will be removed from service without testing and replaced with Year 2000
compliant items; and (3) items to be "worked around," if found not to be Year
2000 compliant, until the items can be replaced or made compliant. Because of
the scope of Chevron's operations, the company believes it is impractical to
eliminate all potential Year 2000 problems before they arise. As a result,
Chevron expects that for non mission-critical items, Year 2000 remedial efforts
will continue into the year 2000.
In the normal course of business, the company has developed and maintains
extensive contingency plans to respond to equipment failures, emergencies and
business interruptions. However, contingency planning for Year 2000 issues is
complicated by the possibility of multiple and simultaneous incidents, which
could significantly impede efforts to respond to emergencies and resume normal
business functions. Such incidents may be outside of the company's control, for
example, if mission-critical third parties do not successfully address their own
material Year 2000 problems.
The company is enhancing existing plans, where necessary, and in some cases
developing new plans specifically designed to mitigate the impact on its
operations of potential failures from the Year 2000 issue. The company expects
to complete and test, where appropriate, its contingency plans by the end of the
third quarter 1999. These plans will be designed to protect the company's
assets, continue safe operations, protect the environment and enable the
resumption of any interrupted operations in a timely and efficient manner. The
company's contingency plans will be focused on: third-party relationships as
necessary; internal mission- critical items, if any, that are not remediated or
otherwise addressed as expected by the end of the third quarter 1999; and other
internal mission-critical items that have been remediated but will not be fully
tested prior to 2000.
The company utilizes both internal and external resources in its Year 2000
efforts. The total estimated cost to achieve Year 2000 compliance is
approximately $250 million, mostly for expense-type items, not all of which are
incremental to the company's operations. Approximately $75 million had been
spent through December 31, 1998. Most of the remaining expenditures will be
incurred in 1999, with the rate of expenditure expected to increase
significantly in 1999. The foregoing amounts include the company's share of
expenditures by its major affiliates.
As part of the Securities and Exchange Commission's reporting requirements on
the Year 2000 problem, companies must include a description of their "most
reasonably likely worst-case scenarios" from potential Year 2000 issues. For
Chevron, its business diversity is expected to reduce the risk of widespread
disruptions to its worldwide operations from Year 2000-related incidents. The
company does not expect unusual risks to public safety or to the environment to
arise from potential Year 2000-related failures. While the
FS-4
company believes that the impact of any individual Year 2000 failure most likely
will be localized and limited to specific facilities or operations, it is not
yet able to fully assess the likelihood of significant business interruptions
occurring in one or more of its operations around the world. Such interruptions
could delay the company from being able to manufacture and deliver refined
products and chemicals products to customers. The company could also face
interruptions in its ability to produce crude oil and natural gas. While not
expected, failures to address multiple critical Year 2000 issues, including
failures to implement contingency plans in a timely manner, could materially and
adversely affect the company's results of operations or liquidity in any one
period. The company is currently unable to predict the aggregate financial or
other consequences of such potential interruptions.
The foregoing disclosure is based on Chevron's current expectations, estimates
and projections, which could ultimately prove to be inaccurate. Because of
uncertainties, the actual effects of the Year 2000 issues on Chevron may be
different from the company's current assessment. Factors, many of which are
outside the control of the company and that could affect Chevron's ability to be
Year 2000 compliant by the end of 1999, include: the failure of customers,
suppliers, governmental entities and others to achieve compliance, and the
inability or failure to identify all critical Year 2000 issues, or to develop
appropriate contingency plans for all Year 2000 issues that ultimately may
arise. The foregoing disclosure is made pursuant to the Federal Year 2000
Information and Readiness Disclosure Act.
ENVIRONMENTAL MATTERS.
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. Most of the costs of complying with
myriad laws and regulations pertaining to its operations and products are
embedded in the normal costs of conducting its business.
Using definitions and guidelines established by the American Petroleum
Institute, Chevron estimates its worldwide environmental spending in 1998 was
about $974 million for its consolidated companies. Included in these
expenditures were $275 million of environmental capital expenditures and $699
million of costs associated with the control and abatement of hazardous
substances and pollutants from ongoing operations. The total spent includes
spending charged against reserves established in prior years for environmental
cleanup programs, but not noncash provisions to increase these reserves or
establish new ones during the year. For 1999, total worldwide environmental
capital expenditures are estimated at $264 million. These capital costs are in
addition to the ongoing costs of complying with environmental regulations and
the costs to remediate previously contaminated sites.
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, as well as third-party
waste disposal sites used by the company. Accidental leaks and spills requiring
cleanup may occur in the ordinary course of business. In addition, an obligation
may arise when operations are closed or sold, or at non-Chevron sites where
company products have been handled or disposed of. Most of the expenditures to
fulfill these obligations relate to facilities and sites where past operations
followed practices and procedures that were considered acceptable at the time
but now require investigative and/or remedial work to meet current standards.
The company retained certain environmental cleanup obligations when it sold the
Port Arthur, Texas, refinery in 1995, and anticipated costs were accrued at the
time of sale. Previously recorded reserves remain adequate.
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 289 hazardous waste sites. The company has made
provisions or payments in 1998 and prior years for approximately 195 of these
sites. No single site is expected to result in a material liability for the
company at this time. For the remaining sites, investigations are not yet at a
stage where the company is able to quantify a probable liability or determine a
range of reasonably possible exposures. The Superfund law provides for joint and
several liability. Any future actions by the EPA and other regulatory agencies
to require Chevron to assume other 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.
During 1998, the company recorded $73 million of net before-tax provisions ($46
million after tax) for environmental remediation efforts, including Superfund
sites. Actual expenditures charged against these provisions and other previously
established reserves amounted to $234 million in 1998. At year-end 1998, the
company's environmental remediation reserves were $826 million, including $48
million related to Superfund sites.
It is likely that the company will continue to incur additional charges, beyond
those reserved, for environmental remediation relating to past operations. These
future costs are indeterminable due to such factors as the unknown magnitude of
possible contamination, the unknown timing and extent of the corrective actions
that may be required, the determination of the company's liability in proportion
to other responsible parties and the extent to which such costs are recoverable
from third parties. While the amounts 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 environmentally related. Provisions are
recognized on a unit-of-production basis as the properties are produced. The
amount of these reserves at year-end 1998 was $1.4 billion and is included in
accumulated depreciation, depletion and amortization on the company's
consolidated balance sheet.
FS-5
For the company's other ongoing operating assets, such as refineries, 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.
During 1998, the company received proceeds - reflected in operating expenses -
from settlements with various insurers related to environmental cost-recovery
claims. As part of these settlements, Chevron has released rights to assert
claims under certain policies, including rights to assert claims in the future
under policies previously issued. Additional proceeds may be received in future
periods under settlements with other insurers, but the amounts are not expected
to be material to the company's results of operations or liquidity.
OTHER CONTINGENCIES.
The company is a defendant in a lawsuit that OXY U.S.A. brought in its capacity
as successor in interest to Cities Service Company. The lawsuit claims damages
resulting from the allegedly improper termination of a tender offer made by Gulf
Oil Corporation, acquired by Chevron in 1984, to purchase Cities Service in
1982. A 1996 trial resulted in a judgment against the company of $742 million,
including interest that continues to accrue at 9.55 percent per year while this
matter is pending. The Oklahoma Supreme Court affirmed the lower court's
decision in March 1999, and accordingly, the company recorded in 1998 results a
litigation reserve of $637 million, substantially all of which pertained to this
lawsuit. The ultimate outcome of this matter cannot be determined presently with
certainty, and the company will seek further review of this case in the
appropriate courts.
Chevron and five other oil companies are contesting, so far unsuccessfully, the
validity of a patent granted to Unocal Corporation for reformulated gasoline,
which Chevron sells in California in certain months of the year. Chevron
believes Unocal's patent is invalid and any unfavorable rulings should be
reversed upon appeal. Unocal continues to file for additional patents for
alternate formulations. Should Unocal's patents be upheld, Chevron's ultimate
exposure with respect to reformulated gasoline sales would depend on the
availability and costs of alternate formulations and the industry's ability to
recover additional costs of production through prices charged to its customers.
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. Caltex believes the underlying excise tax claim is
wrong, and therefore, the claim for penalties and interest is wrong. The IRS
claim relates to crude oil sales to Japanese customers beginning in 1980. Caltex
is challenging the claim and fully expects to prevail. In early 1998, Caltex
provided an initial letter of credit for $2.33 billion to the IRS to pursue the
claim. The letter of credit was renewed in February 1999 for $2.52 billion.
Caltex's owners, Chevron and Texaco, guaranteed the letter of credit.
The company is the subject of various lawsuits and claims and other contingent
liabilities including, along with other oil companies, actions challenging oil
and gas royalty and severance tax payments based on posted prices and others
related to the use of the chemical MTBE in certain oxygenated gasolines. These
lawsuits and other contingent liabilities are discussed in the notes to the
accompanying consolidated financial statements. The company believes that the
resolution of these matters will not materially affect its financial position or
liquidity, although costs associated with their resolution could be material
with respect to earnings in any given period.
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 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 concurrently with, gains and losses from the
underlying transactions. The company believes it has no material market or
credit risks to its operations, financial position or liquidity as a result of
its commodities and other derivatives activities, including forward exchange
contracts and interest rate swaps. Its control systems are designed to monitor
and manage its financial exposures in accordance with company policies and
procedures. 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 can be affected by changing economic, regulatory and
political environments in the various countries where it operates. Political
uncertainty and civil unrest may, at times, threaten the safety of employees and
the company's continued presence in a country. These factors are carefully
considered 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. These
activities may result in significant losses or gains in future periods.
NEW ACCOUNTING STANDARDS.
The company adopted five new accounting standards in 1998. Effective January 1,
1998, the company adopted Statement of Financial Accounting Standards (SFAS) No.
130, "Reporting Comprehensive Income." The statement introduces the concept of
comprehensive income, which includes net income plus changes in stockholders'
equity other than stockholder transactions (certain foreign currency translation
effects, unrealized market value gains/losses for certain debt and equity
securities, and minimum pension liability adjustments). Chevron elected to
present a Consolidated Statement of Comprehensive Income, along with a
disclosure providing details of the changes in the components of other
comprehensive income in the audited financial statements.
Chevron adopted SFAS No. 131, "Disclosures About Segments of an Enterprise and
Related Information," effective for year-end 1998 reporting. SFAS No. 131
requires that the operating segments reported externally be essentially the same
as those management uses to assess performance and allocate resources.
Geographic disclosures are only required on a companywide basis for the
company's country of domicile and other material countries. No countries meet
the materiality tests for reporting other than the United States. However, the
company will provide geographic disclosures of United States and International
for the company's operating
FS-6
segments, which include Exploration and Production; Refining, Marketing and
Transportation; and Chemicals.
Also effective for year-end 1998 reporting, the company adopted SFAS No. 132,
"Employers' Disclosures About Pensions and Other Postretirement Benefits." SFAS
No. 132 standardizes the disclosure requirements for pensions and other
postretirement benefits, requires additional information on changes in benefit
obligations and fair values of plan assets that will facilitate financial
analysis, and eliminates some disclosures.
The adoptions of SFAS Nos. 130, 131 and 132 did not change the measurement or
recognition of income or expense.
In March 1998, the American Institute of Certified Public Accountants (AICPA)
released a new pronouncement for the accounting for certain software costs,
Statement of Position (SOP) 98-1, "Accounting for the Costs of Computer Software
Developed or Obtained for Internal Use." In the fourth quarter 1998, Chevron
adopted this new standard effective January 1, 1998. The company's past practice
had been to expense, when incurred, the cost of internally developed software.
SOP 98-1 requires that the costs incurred to develop, upgrade and enhance
software for internal use be capitalized and depreciated over a suitable useful
life. The net effect of implementing this pronouncement was not material.
In April 1998, the AICPA released SOP 98-5, "Reporting on the Costs of Start-up
Activities." The pronouncement introduced a broad definition of items to be
expensed as incurred for start-up activities, including one-time activities
related to opening a new facility, introducing new products/ services, entering
new territories, initiating new processes or commencing new operations. Previous
accounting standards were not definitive about the expense-vs.-capitalization
treatment of these costs. Chevron already was materially in compliance with the
pronouncement, and it had no impact on the company's accounting practices.
However, Caltex capitalized these types of costs during the 1992-1996 period for
a refinery construction project in Thailand. Chevron, accordingly, restated its
1998 quarterly financial statements for its $25 million share of the charge
associated with Caltex's implementation of SOP 98-5.
In the fourth quarter 1998, Chevron changed its method of calculating certain
Canadian deferred income taxes, effective January 1, 1998. The benefit from this
change was $32 million and resulted in the restatement of first quarter 1998 net
income.
The net benefit to Chevron's restated first quarter 1998 net income for the
cumulative effect of adopting SOP 98-5 by Caltex and the change in Chevron's
method of calculating Canadian deferred taxes was immaterial.
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities." The new standard
requires companies to record derivatives on the balance sheet as assets or
liabilities, measured at fair value. Changes in the fair value of derivatives
are to be recorded each period in current earnings or other comprehensive
income, depending on whether a derivative is designated as part of a hedge
transaction. The company will adopt SFAS No. 133 on January 1, 2000, and does
not believe the adoption of this standard will have a material effect on its
results of operations or financial position.
In November 1998, the Emerging Issues Task Force (EITF) released Issue No.
98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management
Activities." This consensus requires companies to record at their fair value
contracts involved in energy trading and risk management activities. Changes in
the fair value of those contracts are recorded each period in current earnings.
The company will adopt EITF 98-10 on January 1, 1999, and does not believe this
consensus will have a material effect on its results of operations or financial
position.
RESULTS OF OPERATIONS.
Sales and other operating revenues were $29.9 billion in 1998, compared with
$40.6 billion in 1997 and $42.8 billion in 1996. In 1998, revenues fell due
primarily to lower crude oil, natural gas and refined products prices and lower
U.S. natural gas production. Increased U.S. refined products sales volumes
partially mitigated these factors. The company's exit from the U.K. refining and
marketing business in the fourth quarter 1997 contributed approximately 27
percent of the decline. In 1997, revenues declined from 1996 levels on lower
crude oil and refined products prices and lower U.S. natural gas production,
partially offset by increased refined products sales volumes and higher natural
gas prices.
Purchased crude oil and products costs were 31 percent lower in 1998, compared
with 1997, because of lower prices for crude oil, natural gas, refined products
and chemicals feedstock, and the company's exit from the U.K. refining and
marketing business. Lower crude oil, refined products and chemicals feedstock
prices also accounted for the 11 percent decrease in purchased crude oil and
products costs in 1997, compared with 1996.
Other income totaled $386 million in 1998, $679 million in 1997 and $344 million
in 1996. Changes in net gains from the disposition of assets and changes in
interest income caused the fluctuations between years.
Year ended December 31,
------------------------------
Millions of dollars 1998 1997 1996
- - ---------------------------------------------------------------------
Operating Expenses $4,834 $5,280 $6,007
Selling, General and
Administrative Expenses 2,239 1,533 1,377
- - ---------------------------------------------------------------------
Total 7,073 6,813 7,384
Less: Special Charges
Before Tax 822 264 437
- - ---------------------------------------------------------------------
Adjusted Operating, Selling, General
and Administrative Expenses $6,251 $6,549 $6,947
=====================================================================
Operating, selling, general and administrative expenses of $6,251 million,
excluding the effects of special items, which were primarily reserves for
litigation, declined from $6,549 million in 1997 and $6,947 million in 1996.
Approximately $200 million of the 1998 decline resulted from the company's exit
from the U.K. downstream business.
Depreciation, depletion and amortization expense increased to $2,320 million
from $2,300 million in 1997 and $2,216 million in 1996. In 1998 and 1997, about
$100 million of depreciation expense was related to asset impairments, while
1996 included a minor amount for impairments.
Taxes on income were $495 million in 1998, $2,246 million in 1997 and $2,133
million in 1996, reflecting effective income tax rates of 27 percent, 41 percent
and 45 per-
FS-7
cent, respectively. The lower tax rate in 1998, compared with 1997, reflects
favorable prior-period tax adjustments; favorable adjustments associated with
the finalization of income tax returns for the year 1997; tax-related credits
connected with the utilization of capital loss benefits; lower effective tax
rates in West Africa resulting from credits associated with crude oil reserve
additions; a shift in the international earnings mix to lower-tax-rate
countries; and tax expense reductions associated with provisions for litigation.
These effects were offset partially by a decrease in the proportion of the
company's share of its equity affiliates' after-tax earnings included in the
company's before-tax income. The lower tax rate in 1997, compared with 1996,
primarily reflects a shift in the international earnings mix to lower-tax-rate
countries and shifts from foreign earnings to U.S. earnings.
SELECTED OPERATING DATA
1998 1997 1996
- - -------------------------------------------------------------------------------
U.S. EXPLORATION AND PRODUCTION
Net Crude Oil and Natural Gas
Liquids Production (MBPD) ................. 325 343 341
Net Natural Gas
Production (MMCFPD) ....................... 1,739 1,849 1,875
Natural Gas Sales (MMCFPD) (1) ............ 3,303 3,400 3,588
Natural Gas Liquids Sales (MBPD) (1) ...... 130 133 187
Revenues from Net Production
Crude Oil ($/Bbl) ......................... $11.42 $17.68 $18.80
Natural Gas ($/MCF) ....................... $ 2.02 $ 2.42 $ 2.28
INTERNATIONAL
EXPLORATION AND PRODUCTION (1)
Net Crude Oil and Natural Gas
Liquids Production (MBPD) ................. 782 731 702
Net Natural Gas
Production (MMCFPD) ....................... 654 576 584
Natural Gas Sales (MMCFPD) ................ 1,504 1,209 778
Natural Gas Liquids Sales (MBPD) .......... 53 69 36
Revenues from Liftings
Liquids ($/Bbl) ........................... $11.77 $17.97 $19.48
Natural Gas ($/MCF) ....................... $ 1.94 $ 2.10 $ 1.86
Other Produced Volumes (MBPD) (2) ......... 95 82 79
U.S. REFINING, MARKETING
AND TRANSPORTATION
Gasoline Sales (MBPD) ..................... 653 591 556
Other Refined Products Sales (MBPD) ....... 590 602 566
Refinery Input (MBPD) ..................... 869 933 951
Average Refined Products
Sales Price ($/Bbl) ....................... $22.37 $28.93 $29.94
INTERNATIONAL REFINING, MARKETING
AND TRANSPORTATION (1)
Refined Products Sales (MBPD) ............. 785 886 944
Refinery Input (MBPD) ..................... 475 565 537
Chemicals Sales and Other
Operating Revenues (3)
United States ............................. $2,591 $3,046 $2,936
International ............................. 625 600 605
- - -------------------------------------------------------------------------------
Worldwide ................................. $3,216 $3,646 $3,541
===============================================================================
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)Total field production under Boscan operating service agreement in Venezuela
beginning July 1, 1996.
(3)Millions of dollars. Includes sales to other Chevron companies.
Foreign currency effects decreased net income $47 million in 1998, increased net
income $246 million in 1997 and decreased net income $26 million in 1996. These
amounts include the company's share of affiliates' currency transactions. The
most significant losses in 1998 were incurred in Caltex's operations in Korea,
Thailand and Japan. The foreign currency gains for 1997 occurred primarily in
Australia and in the Asian operating areas of Caltex, where the currencies
generally weakened against the U.S. dollar. The largest currency impact for 1997
was in Korea, as a result of local net deferred tax benefits on local currency
losses from U.S. dollar-denominated liabilities. The loss on currency
transactions in 1996 resulted from fluctuations in the value of the U.K. and
Australian currencies relative to the U.S. dollar.
Effective October 1, 1997, Caltex's management changed the functional currency
for its Korean and Japanese equity affiliates from their local currencies to the
U.S. dollar, based on significantly changed economic facts and circumstances.
With the local currency as the functional currency, Caltex's total reported
foreign currency losses from its Korean and Japanese affiliates were $62 million
for the first nine months of 1997. After the change in functional currency to
the U.S. dollar, Caltex reported foreign currency gains of $167 million for the
full year 1997 from operations in Korea and Japan. In 1998, Caltex's foreign
currency losses from Korea and Japan were $145 million.
U.S. exploration and production earnings in 1998, excluding special items,
declined more than 60 percent from 1997 earnings and 66 percent from 1996
levels, due primarily to lower crude oil and natural gas sales realizations and
lower production. Partially offsetting these factors in 1998 were lower
operating and exploration expenses and benefits from property sales. The
earnings decline of 12 percent in 1997, relative to 1996's record earnings, was
a result of lower crude oil prices, lower natural gas production and higher
exploration expenses.
The company's average 1998 U.S. crude oil realization of $11.42 per barrel was
$6.26 lower than the $17.68 average for 1997 and $7.38 lower than the 1996
average. Chevron's crude oil realizations increased steadily during 1996, but in
early 1997 began a decline that continued into early 1999.
Average 1998 U.S. natural gas prices of $2.02 per thousand cubic feet (MCF) were
40 cents lower than the $2.42 averaged in 1997 and 26 cents lower than the 1996
average price. Warmer weather and abundant supplies depressed prices in 1998.
Net liquids production for 1998 averaged 325,000 BPD, down about 5 percent from
343,000 BPD in 1997 and from 341,000 BPD in 1996. Net natural gas production in
1998 averaged 1.739 billion cubic feet per day, down 6 percent from 1.849
billion cubic feet per day in 1997 and about 7 percent from 1.875 billion cubic
feet per day in 1996. Lower liquids and natural gas production between years
primarily reflected normal field declines, property sales and, in 1998, reduced
production due to September storms in the Gulf of Mexico.
The effect on net income from special items for the years 1996 through 1998 is
shown in the following table.
FS-8
U.S. Exploration and Production
Millions of dollars ........................ 1998 1997 1996
- - -------------------------------------------------------------------------------
Earnings, Excluding Special Items .......... $ 381 $ 972 $ 1,109
- - -------------------------------------------------------------------------------
Asset Write-Offs and Revaluations ........ (44) (68) (19)
Asset Dispositions ....................... 47 190 17
Environmental Remediation Provisions ..... 26 (6) (10)
Restructurings and Reorganizations ....... -- (60) 1
Other .................................... (45) (27) (11)
- - -------------------------------------------------------------------------------
Total Special Items ...................... (16) 29 (22)
- - -------------------------------------------------------------------------------
Reported Net Income ...................... $ 365 $ 1,001 $ 1,087
===============================================================================
International exploration and production earnings of $717 million in 1998,
excluding special items, declined 40 percent from $1,197 million earned in 1997
and fell 37 percent from $1,142 million in 1996. Earnings declined in 1998,
despite increased production, as a result of depressed crude oil prices and
lower natural gas sales realizations. The earnings increase in 1997, relative to
1996, was primarily due to higher volumes.
Earnings for 1998, excluding special items, also benefited from net favorable
tax adjustments for the prior year.
Earnings for the year 1998 included net foreign currency gains of $29 million,
compared with gains of $77 million for the year 1997 and losses of $27 million
in 1996. The 1998 gains reflect primarily currency rate fluctuations of the U.S.
dollar relative to the Canadian and Australian currencies. In 1997 and 1996, the
swings were related to the Australian dollar and the British pound.
The effect on net income from special items for the years 1996 through 1998 is
shown in the following table.
International Exploration and Production
Millions of dollars ..................... 1998 1997 1996
- - -------------------------------------------------------------------------------
Earnings, Excluding Special Items ...... $ 717 $ 1,197 $ 1,142
- - -------------------------------------------------------------------------------
Asset Write-Offs and Revaluations ..... (6) -- (17)
Asset Dispositions .................... (56) 50 91
Prior-Year Tax Adjustments ............ 56 10 --
Other ................................. (4) (5) (5)
- - -------------------------------------------------------------------------------
Total Special Items ................... (10) 55 69
- - -------------------------------------------------------------------------------
Reported Net Income ................... $ 707 $ 1,252 $ 1,211
===============================================================================
Chevron's average liquids realizations, including equity affiliates, was $11.77
per barrel in 1998, compared with $17.97 per barrel in 1997 and $19.48 in 1996.
Average natural gas realizations fell to $1.94 per thousand cubic feet in 1998,
compared with $2.10 in 1997 and $1.86 in 1996.
For the year 1998, net liquids production, including production from equity
affiliates, increased 7 percent to 782,000 BPD. Operations in Kazakhstan,
offshore eastern Canada, Indonesia, Angola and Congo were the principal sources
of the increases. Net natural gas production increased about 14 percent for the
year to 654 million cubic feet per day in 1998. Net natural gas production
increased for the year in the United Kingdom, due to the August 1998 start-up of
production at the Britannia Field, as well as in Indonesia and Nigeria.
Partially offsetting these increases was a decline in natural gas production in
western Canada.
This was the ninth consecutive year that international net production and proved
reserves increased, reflecting the company's success in expanding its
international upstream operations. In 1998, the company estimated it replaced
165 percent of its international oil and gas production through increases to
proved reserves, excluding sales and acquisitions. Further production increases
are expected in 1999 as new developments come on stream in West Africa and from
production increases at the Tengiz Field in Kazakhstan.
In 1997, net liquids production increased 4 percent over 1996 levels to 731,000
BPD. Production growth in Nigeria, Congo and Kazakhstan accounted for most of
the increase. Net natural gas production declined about 1 percent in 1997 to 576
million cubic feet per day compared with 1996 due mainly to lower rates in
Canada, Kazakhstan, the United Kingdom and Indonesia.
U.S. refining, marketing and transportation earnings in 1998, excluding special
items, decreased slightly to $633 million after a strong year in 1997. Declines
in refined product margins and Hurricane Georges' adverse effects on earnings
were offset mostly by decreases in operating expenses and increases in refined
products sales volumes. Also included in 1998 results were benefits to income
that included a partial payment of business interruption insurance proceeds for
losses associated with Hurricane Georges and prior-year tax adjustments.
Earnings in 1997 more than doubled to $662 million, compared with $290 million
in 1996. The 1997 increase was driven by higher demand for refined products and
improved sales margins, reflecting both lower crude oil costs and lower
operating expenses. Earnings for 1996 were depressed by competitive conditions
that did not allow the full recovery of all crude oil and manufacturing costs.
Although refined products sales realizations declined in 1998 and 1997, sales
volumes increased 4 percent to 1.243 million BPD in 1998, compared with 1.193
million BPD in 1997 and 1.122 million BPD in 1996. Most of the increases in 1998
reflected higher gasoline sales volumes, including branded gasoline sales, which
increased 5 percent from 1997 and 8 percent from 1996.
In 1998, average U.S. refined products sales realizations declined to $22.37 per
barrel from $28.93 per barrel in 1997 and $29.94 per barrel in 1996, reflecting
the steep slide in crude oil prices.
The effect on net income from special items for the years 1996 through 1998 is
shown in the following table.
U.S. Refining, Marketing and Transportation
Millions of dollars ........................ 1998 1997 1996
- - -------------------------------------------------------------------------------
Earnings, Excluding Special Items .......... $ 633 $ 662 $ 290
- - -------------------------------------------------------------------------------
Asset Write-Offs and Revaluations ........ (22) -- (48)
Asset Dispositions ....................... -- (18) 4
Environmental Remediation ................ (39) (12) (29)
Other .................................... -- (31) (24)
- - -------------------------------------------------------------------------------
Total Special Items ...................... (61) (61) (97)
- - -------------------------------------------------------------------------------
Reported Net Income ...................... $ 572 $ 601 $ 193
===============================================================================
International refining, marketing and transportation earnings include
international marine operations and equity earnings of Caltex, in addition to
earnings from its consolidated international refining and marketing
subsidiaries. Excluding special items, 1998 earnings of $123 million were down
66 percent from $367 million earned in 1997 and were also down from $167 million
earned in 1996. Results included
FS-9
foreign currency losses of $69 million in 1998, compared with foreign currency
gains of $169 million in 1997 and losses of $17 million in 1996.
The effect on net income from special items for the years 1996 through 1998 is
shown in the following table.
International Refining, Marketing and Transportation
Millions of dollars ........................ 1998 1997 1996
- - -------------------------------------------------------------------------------
Earnings, Excluding Special Items .......... $ 123 $ 367 $ 167
- - -------------------------------------------------------------------------------
Asset Write-Offs and Revaluations ........ -- -- (200)
Asset Dispositions ....................... -- (72) 279
Environmental Remediation ................ (11) -- (15)
Restructurings and Reorganizations ....... (43) -- 1
LIFO Inventory (Losses) Gains ............ (16) 6 (6)
Other .................................... (25) (3) --
- - -------------------------------------------------------------------------------
Total Special Items ...................... (95) (69) 59
- - -------------------------------------------------------------------------------
Reported Net Income ...................... $ 28 $ 298 $ 226
===============================================================================
The company's share of Caltex's losses was $36 million in 1998 compared with
earnings of $252 million and $408 million for 1997 and 1996, respectively.
Chevron's share of Caltex results in 1998 included special charges of $14
million for Last-In, First-Out (LIFO) inventory adjustments and $43 million for
the company's share of Caltex's costs of restructuring its management and
administrative functions and the associated relocation to Singapore. In
addition, net income included a special charge of $25 million from Caltex's
adoption, effective January 1, 1998, of a new accounting standard - SOP 98-5,
"Reporting on the Costs of Start-up Activities." Accordingly, the company has
restated its 1998 quarterly results. Excluding special items, the company's
share of earnings from Caltex's activities were $46 million, $247 million and
$127 million for 1998, 1997 and 1996, respectively.
Included in Chevron's share of Caltex's 1998 earnings were foreign currency
losses of $68 million, compared with foreign currency gains of $177 million in
1997 and losses of $24 million in 1996. The largest swing in foreign currency
effects in all years was in Korea. Other operating factors for 1998 included
inventory valuation losses of about $40 million stemming from the fall in oil
prices.
Partially offsetting Caltex's large currency gains in 1997 were inventory
valuation losses associated with that year's decline in oil prices and higher
provisions for uncollectible receivables in Asia.
Chevron's international refined products sales volumes declined in 1998 to
785,000 barrels per day from 886,000 barrels per day in 1997 and 944,000 barrels
per day in 1996. During the fourth quarter of 1997, the company withdrew from
the refining and marketing business in the United Kingdom. Excluding the 1997
sales volumes from this discontinued business, refined products sales volumes
for 1998 were essentially flat compared with 1997. Declines in international
trading and Canadian refined products sales volumes were offset by increases
from Caltex's operations. The primary reason for the decline in 1997 volumes,
compared with 1996, was Caltex's sale of its interest in two Japanese refineries
in early 1996.
Chemicals earnings, excluding special items, were $151 million in 1998, down
about 33 percent from $224 million in 1997, and $228 million in 1996. Earnings
continued to decline in response to industry over-capacity and lower demand
resulting from the Asian economic crisis. Sales volumes remained strong,
increasing 10 percent in 1998. However, product sales prices fell faster than
feedstock and fuel costs, resulting in lower margins for most of the company's
major chemicals products. Earnings for 1998 benefited from prior-year tax
adjustments, which were partially offset by lower earnings from equity
affiliates following a fourth quarter 1997 sale of an investment.
Earnings for 1998 and 1997 benefited from reduced depreciation expense,
resulting from a reassessment of the useful lives of certain assets. Lower
industry prices and higher operating expenses related to maintenance and
expansion activities during 1997 more than offset this depreciation benefit.
Earnings for 1996 reflected the receipt of insurance proceeds. A cyclical
downturn in the chemicals industry that began in the second half 1995 caused
earnings to fall throughout the three-year period.
The effect on net income from special items for the years 1996 through 1998 is
shown in the following table.
Chemicals
- - ---------
Millions of dollars ........................ 1998 1997 1996
- - -------------------------------------------------------------------------------
Earnings, Excluding Special Items .......... $ 151 $ 224 $ 228
- - -------------------------------------------------------------------------------
Asset Write-Offs and Revaluations ........ (19) (10) (12)
Asset Dispositions ....................... -- 33 --
Environmental Remediation ................ (5) (9) --
LIFO Inventory Losses .................... (5) (1) --
Other .................................... -- (9) (16)
- - -------------------------------------------------------------------------------
Total Special Items ...................... (29) 4 (28)
- - -------------------------------------------------------------------------------
Reported Net Income ...................... $ 122 $ 228 $ 200
===============================================================================
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 operating charges, excluding special
items, were $60 million in 1998, compared with charges of $242 million in 1997
and $285 million in 1996.
The effect on net income from special items for the years 1996 through 1998 is
shown in the following table.
All Other
- - ---------
Millions of dollars ........................ 1998 1997 1996
- - -------------------------------------------------------------------------------
Charges, Excluding Special Items ........... $ (60) $(242) $(285)
- - -------------------------------------------------------------------------------
Asset Write-Offs and Revaluations ........ (68) (8) (41)
Environmental Remediation ................ (10) (8) --
Prior-Year Tax Adjustments ............... 215 142 52
Restructurings and Reorganizations ....... -- -- (10)
Other .................................... (532) (8) (26)
- - -------------------------------------------------------------------------------
Total Special Items ...................... (395) 118 (25)
- - -------------------------------------------------------------------------------
Reported Charges ......................... $(455) $(124) $(310)
===============================================================================
Special items include litigation reserves, prior-year tax adjustments, resulting
from the settlement of tax audit issues or the revaluation by the company of its
tax liabilities as a result of new developments, and proceeds from insurance
settlements related to environmental cost recovery claims.
Earnings, excluding special items, from the company's coal operations were $77
million in 1998, $41 million in 1997 and $47 million in 1996. Sales volumes
improved at most of the company's mines in 1998. In addition, 1998 results
FS-10
included favorable adjustments of about $20 million, related primarily to
depreciation expense and reserves for certain claims. The company reached
agreement in February 1999 to sell its 33 percent interest in Black Beauty Coal
Company, for which a gain is expected. The company's remaining coal assets, with
a net book value of $340 million, are held for sale. Revenues from coal
operations were about $400 million in 1998.
Included in the 1998 earnings, excluding special items, for the balance of the
All Other segment 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. 1998 also included other more favorable
tax-related adjustments than 1997. Partially offsetting these items were higher
interest expenses on increased debt levels and lower interest income. 1997 net
charges were lower than in 1996 due primarily to lower interest expense on
reduced debt levels, combined with higher interest income and lower insurance
costs.
LIQUIDITY AND CAPITAL RESOURCES.
Cash, cash equivalents and marketable securities totaled $1.413 billion at
year-end 1998, down 15 percent from $1.670 billion at year-end 1997. Cash
provided by operating activities in 1998 was $3.731 billion, compared with
$4.880 billion in 1997 and $5.947 billion in 1996. Severely affecting cash flow
in 1998 were the low crude oil price environment and the resulting impact on the
company's earnings, cash distributions from equity affiliates and working
capital requirements. In 1998, cash provided by operating activities was not
sufficient to fund investing activities. This shortfall and the cash required to
fund the company's dividend payments to stockholders resulted in an increase in
borrowings in 1998. In 1997 and 1996, cash provided by operating activities was
sufficient to fund the company's investing activities and dividend payments, and
to reduce debt balances.
In January 1999, the company declared a quarterly dividend of 61 cents a share
on its common stock for an annual rate of $2.44 a share.
The company's total debt and capital lease obligations were $7.558 billion at
December 31, 1998, an increase of 25 percent from $6.068 billion at year-end
1997. Significant debt transactions in 1998 were net additions of $1.528 billion
in short-term debt, primarily commercial paper, and newly issued long-term
variable-rate obligations of $224 million. Partially offsetting these increases
were long-term debt repayments of $356 million and a scheduled $60 million
non-cash retirement of 8.11 percent ESOP debt in January 1998.
On December 31, 1998, Chevron had $4.050 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 1998. In addition, Chevron and one of
its subsidiaries each have existing "shelf" registrations on file with the
Securities and Exchange Commission that together would permit registered
offerings of up to $1.3 billion of debt securities.
The company's short-term debt, consisting primarily of commercial paper and the
current portion of long-term debt, totaled $5.890 billion at December 31, 1998.
Of the total short-term debt, $2.725 billion was reclassified to long-term debt
at year-end 1998. Settlement of these obligations is not expected to require the
use of working capital in 1999 because 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 its capital spending
program, results of operations and eventual outcome of the Cities Service
lawsuit. The company currently expects its debt level to increase during 1999
and 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, and 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 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 its outstanding common stock for use in its employee stock option
programs. During 1998, the company purchased 5.2 million shares of its stock at
a cost of $392 million under the repurchase program, bringing the total
repurchased to 6.4 million shares at a total cost of $484 million.
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, which at year-end 1998 were lower
than current costs by $584 million. Also, the company continually refinances its
commercial paper. At year-end 1998, approximately $2.150 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. During 1997, the company increased its committed credit arrangements,
which permitted the reclassification of an additional $925 million of short-term
debt to long-term debt and provided an improvement to the company's current
ratio.
Financial Ratios
- - ----------------
1998 1997 1996
-----------------------
Current Ratio 0.9 1.0 0.9
Interest Coverage Ratio 5.1 14.3 10.9
Total Debt/Total Debt Plus Equity 30.7% 25.8% 30.0%
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 declined in 1998
due to higher interest expense and lower before-tax income. The
FS-11
company's debt ratio (total debt to total debt plus equity) increased in 1998,
as a result of the increase in total debt.
CAPITAL AND EXPLORATORY EXPENDITURES.
Worldwide capital and exploratory expenditures for 1998 totaled $5.314 billion,
including the company's equity share of affiliates' expenditures. Capital and
exploratory expenditures were $5.541 billion in 1997 and $4.840 billion in 1996.
Expenditures for exploration and production accounted for 61 percent of total
outlays in 1998, compared with 65 percent in 1997 and 62 percent in 1996.
International exploration and production spending was 60 percent of worldwide
exploration and production expenditures in 1998, compared with 54 percent in
1997 and 61 percent in 1996, reflecting the company's continuing focus on
international exploration and production activities.
The company projects 1999 capital and exploratory expenditures at $5.1 billion,
including Chevron's share of spending by affiliates. This is down about 4
percent from 1998 spending levels. The 1999 program provides $3.7 billion for
exploration and production investments, of which about 70 percent is for
international projects. Major areas of emphasis for exploration and production
are Kazakhstan, West Africa and the deep waters of the Gulf of Mexico.
Successful implementation of the planned expenditure program for 1999 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.
Refining, marketing and transportation expenditures are estimated at about $870
million, with $540 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 will be focused on Asia-Pacific countries where the
company's Caltex affiliate is upgrading its retail marketing system. The company
plans to invest $380 million in the worldwide chemicals business, down about 50
percent from 1998 spending levels.
Capital and Exploratory Expenditures
- - ------------------------------------
1998 1997 1996
------------------------ ------------------------ ------------------------
Inter- Inter- Inter-
Millions of dollars U.S. national Total U.S. national Total U.S. national Total
- - --------------------------------------------------------------------------------------------------------------------------
Exploration and Production ............ $1,320 $1,942 $3,262 $1,659 $1,956 $3,615 $1,168 $1,854 $3,022
Refining, Marketing and Transportation 654 431 1,085 520 602 1,122 429 781 1,210
Chemicals ............................ 385 359 744 470 194 664 377 120 497
All Other ............................ 223 - 223 140 - 140 101 10 111
- - --------------------------------------------------------------------------------------------------------------------------
Total ................................ $2,582 $2,732 $5,314 $2,789 $2,752 $5,541 $2,075 $2,765 $4,840
- - --------------------------------------------------------------------------------------------------------------------------
Total, Excluding Equity Affiliates ... $2,460 $1,860 $4,320 $2,487 $1,880 $4,367 $2,037 $1,820 $3,857
==========================================================================================================================
FORWARD-LOOKING STATEMENTS
This annual report 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; inability of the company's joint-venture
partners to fund their share of operations and development activities; potential
failure to achieve expected production from existing and future oil and gas
development projects; potential disruption or interruption of the company's
production or manufacturing facilities due to accidents or political events;
potential disruptions to the company's operations due to untimely or incomplete
resolution of Year 2000 issues by the company and other entities with which it
has mutual relationships; potential liability for remedial actions under
existing or future environmental regulations; 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.
FS-12
QUARTERLY RESULTS AND STOCK MARKET DATA
Unaudited
---------------------------------------
1998 1997
------------------------------------------------------------------------------
Millions of dollars, except per-share amounts 4TH Q 3RD Q 2ND Q 1ST Q(3) 4TH Q 3RD Q 2ND Q 1ST Q
- - ------------------------------------------------------------------------------------------------------------------------------------
REVENUES
Sales and other operating revenues (1) ............ $ 7,164 $ 7,561 $ 7,754 $ 7,464 $9,725 $10,130 $ 9,947 $10,794
(Loss) income from equity affiliates .............. (66) 13 155 126 153 164 193 178
Other income ...................................... 184 104 60 38 390 34 134 121
- - ------------------------------------------------------------------------------------------------------------------------------------
TOTAL REVENUES .................................... 7,282 7,678 7,969 7,628 10,268 10,328 10,274 11,093
- - ------------------------------------------------------------------------------------------------------------------------------------
COSTS AND OTHER DEDUCTIONS
Purchased crude oil and products,
operating and other expenses .................... 5,978 5,100 5,314 5,195 6,603 6,792 6,623 7,511
Depreciation, depletion and amortization .......... 646 563 557 554 657 548 549 546
Taxes other than on income1 ....................... 1,115 1,145 1,140 1,011 1,525 1,670 1,630 1,495
Interest and debt expense ......................... 109 103 99 94 85 69 76 82
- - ------------------------------------------------------------------------------------------------------------------------------------
TOTAL COSTS AND OTHER DEDUCTIONS .................. 7,848 6,911 7,110 6,854 8,870 9,079 8,878 9,634
- - ------------------------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAX .......................... (566) 767 859 774 1,398 1,249 1,396 1,459
INCOME TAX (CREDIT) EXPENSE ....................... (360) 306 282 267 523 522 573 628
- - ------------------------------------------------------------------------------------------------------------------------------------
NET (LOSS) INCOME (2) ............................. $ (206) $ 461 $ 577 $ 507 $ 875 $ 727 $ 823 $ 831
====================================================================================================================================
NET (LOSS) INCOME PER SHARE - BASIC ............... $ (0.31) $ 0.70 $ 0.88 $ 0.78 $ 1.33 $ 1.11 $ 1.26 $ 1.27
- DILUTED ............. $ (0.31) $ 0.70 $ 0.88 $ 0.77 $ 1.33 $ 1.10 $ 1.25 $ 1.27
====================================================================================================================================
DIVIDENDS PAID PER SHARE .......................... $ 0.61 $ 0.61 $ 0.61 $ 0.61 $ 0.58 $ 0.58 $ 0.58 $ 0.54
====================================================================================================================================
COMMON STOCK PRICE RANGE - HIGH.................... $89 7\16 $89 $86 13\16 $90 3\16 $88 7\8 $89 3\16 $77 1/4 $72 5\8
- LOW .................... $78 3\8 $73 $77 3\8 $67 3\4 $71 1\2 $73 1\2 $61 3/4 $63 1\2
====================================================================================================================================
(1) Includes consumer excise taxes of $ 943 $ 973 $ 988 $ 852 $ 1,339 $ 1,487 $ 1,447 $ 1,314
(2) Special (charges) credits included in Net Income $ (709) $ 75 $ (43) $ 71 $ 68 $ (5) $ 14 $ 27
(3) Restated for the cumulative effect of accounting changes, the net effect of which was immaterial.
The company's common stock is listed in the New York Stock Exchange (trading symbol CHV), as well as the Chicago, Pacific, London
and Swiss stock exchanges. It is also traded on the Boston, Cincinnati, Detroit and Philadelphia stock exchanges.
As of March 4, 1999, stockholders of record numbered approximately 124,000
There are no restrictions on the company's ability to pay dividends. Chevron has made dividend payments to stockholders
for 87 consecutive years.
REPORT OF MANAGEMENT
--------------------
TO THE STOCKHOLDERS OF CHEVRON CORPORATION
Management of Chevron is responsible for preparing the accompanying financial
statements and for assuring their integrity and objectivity. The statements were
prepared in accordance with generally accepted accounting principles 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/ K.T. Derr /s/ M.R. Klitten /s/ S.J. Crowe
Kenneth T. Derr Martin R. Klitten Stephen J. Crowe
Chairman of the Board Vice President Comptroller
and Chief Executive Officer and Chief Financial Officer
March 4, 1999
FS-13
CONSOLIDATED STATEMENT OF INCOME
--------------------------------
Year ended December 31
-------------------------------------------
Millions of dollars, except per-share amounts 1998 1997 1996
- - --------------------------------------------------------------------------------------------------------------
REVENUES
Sales and other operating revenues* ....................... $ 29,943 $ 40,596 $ 42,782
Income from equity affiliates ............................. 228 688 767
Other income .............................................. 386 679 344
- - --------------------------------------------------------------------------------------------------------------
TOTAL REVENUES ............................................. 30,557 41,963 43,893
- - --------------------------------------------------------------------------------------------------------------
COSTS AND OTHER DEDUCTIONS
Purchased crude oil and products .......................... 14,036 20,223 22,826
Operating expenses ........................................ 4,834 5,280 6,007
Selling, general and administrative expenses .............. 2,239 1,533 1,377
Exploration expenses ...................................... 478 493 455
Depreciation, depletion and amortization .................. 2,320 2,300 2,216
Taxes other than on income* ............................... 4,411 6,320 5,908
Interest and debt expense ................................. 405 312 364
- - --------------------------------------------------------------------------------------------------------------
TOTAL COSTS AND OTHER DEDUCTIONS ........................... 28,723 36,461 39,153
INCOME BEFORE INCOME TAX EXPENSE ........................... 1,834 5,502 4,740
Income Tax Expense ........................................ 495 2,246 2,133
==============================================================================================================
NET INCOME ................................................. $ 1,339 $ 3,256 $ 2,607
==============================================================================================================
NET INCOME PER SHARE OF COMMON STOCK - BASIC ............... $ 2.05 $ 4.97 $ 3.99
- DILUTED ............. $ 2.04 $ 4.95 $ 3.98
WEIGHTED-AVERAGE NUMBER OF SHARES OUTSTANDING .............. 653,666,859 654,990,921 652,769,250
==============================================================================================================
* Includes consumer excise taxes. $ 3,756 $ 5,587 $ 5,202
1997 amounts have been reclassified to conform to
1998 presentation
See accompanying notes to consolidated financial statements
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
----------------------------------------------
Year ended December 31
-------------------------------------------
Millions of dollars 1998 1997 1996
- - --------------------------------------------------------------------------------------------------------------
NET INCOME ................................................. $ 1,339 $ 3,256 $ 2,607
Currency translation adjustment ........................... (1) (173) (54)
Unrealized holding gain (loss) on securities .............. 3 (4) (20)
Minimum pension liability adjustment ...................... (15) 4 (4)
- - --------------------------------------------------------------------------------------------------------------
OTHER COMPREHENSIVE INCOME, NET OF TAX ..................... (13) (173) (78)
- - --------------------------------------------------------------------------------------------------------------
COMPREHENSIVE INCOME ....................................... $ 1,326 $ 3,083 $ 2,529
==============================================================================================================
See accompanying notes to consolidated financial statements
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, 1998 and 1997, and
the results of their operations and their cash flows for each of the three years
in the period ended December 31, 1998, in conformity with generally accepted
accounting principles. 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 generally accepted auditing standards 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
March 4, 1999
FS-14
CONSOLIDATED BALANCE SHEET
--------------------------
At December 31
---------------------
Millions of dollars ........................................................ 1998 1997
- - ---------------------------------------------------------------------------------------------------
ASSETS
Cash and cash equivalents .................................................. $ 569 $ 1,015
Marketable securities ...................................................... 844 655
Accounts and notes receivable (less allowance: 1998 - $27; 1997 - $32) ..... 2,813 3,374
Inventories:
Crude oil and petroleum products ........................................... 600 539
Chemicals .................................................................. 559 547
Materials, supplies and other .............................................. 296 292
--------------------
1,455 1,378
Prepaid expenses and other current assets .................................. 616 584
--------------------
TOTAL CURRENT ASSETS ....................................................... 6,297 7,006
Long-term receivables ...................................................... 872 471
Investments and advances ................................................... 4,604 4,496
Properties, plant and equipment, at cost ................................... 51,337 49,233
Less: accumulated depreciation, depletion and amortization ................. 27,608 26,562
--------------------
23,729 22,671
Deferred charges and other assets .......................................... 1,038 829
--------------------
TOTAL ASSETS ............................................................... $ 36,540 $ 35,473
===================================================================================================
LIABILITIES AND STOCKHOLDERS' EQUITY
Short-term debt ............................................................ $ 3,165 $ 1,637
Accounts payable ........................................................... 2,170 2,735
Accrued liabilities ........................................................ 1,202 1,450
Federal and other taxes on income .......................................... 226 732
Other taxes payable ........................................................ 403 392
--------------------
TOTAL CURRENT LIABILITIES .................................................. 7,166 6,946
Long-term debt ............................................................. 4,128 4,139
Capital lease obligations .................................................. 265 292
Deferred credits and other noncurrent obligations .......................... 2,560 1,745
Noncurrent deferred income taxes ........................................... 3,645 3,215
Reserves for employee benefit plans ........................................ 1,742 1,664
--------------------
TOTAL LIABILITIES .......................................................... 19,506 18,001
- - ---------------------------------------------------------------------------------------------------
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 ............................................. 2,097 2,022
Deferred compensation ...................................................... (691) (750)
Accumulated other comprehensive income ..................................... (90) (77)
Retained earnings .......................................................... 16,942 17,185
Treasury stock, at cost (1998 - 59,460,666 shares; 1997 - 56,555,871 shares) (2,293) (1,977)
TOTAL STOCKHOLDERS' EQUITY ................................................. 17,034 17,472
- - ---------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ................................. $ 36,540 $ 35,473
===================================================================================================
See accompanying notes to consolidated financial statements.
FS-15
CONSOLIDATED STATEMENT OF CASH FLOWS
------------------------------------
Year ended December 31
-------------------------------
Millions of dollars ...................................................... 1998 1997* 1996*
- - ------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Net income ............................................................. $ 1,339 $ 3,256 $ 2,607
Adjustments
Depreciation, depletion and amortization ........................... 2,320 2,300 2,216
Dry hole expense related to prior years' expenditures .............. 40 31 55
Distributions greater than (less than) income from equity affiliates 25 (353) 83
Net before-tax (gains) losses on asset retirements and sales ....... (45) (344) 207
Net foreign exchange gains ......................................... (20) (69) (10)
Deferred income tax provision ...................................... 266 622 359
Net (increase) decrease in operating working capital (1)............ (809) (253) 649
Other, net ......................................................... 615 (310) (219)
-------------------------------
NET CASH PROVIDED BY OPERATING ACTIVITIES (2) .......................... 3,731 4,880 5,947
-------------------------------
INVESTING ACTIVITIES
Capital expenditures ................................................... (3,880) (3,899) (3,424)
Proceeds from asset sales .............................................. 434 1,235 778
Net (purchases) sales of marketable securities (3) ..................... (183) 101 44
Other, net ............................................................. (230) (297) (177)
-------------------------------
NET CASH USED FOR INVESTING ACTIVITIES ................................. (3,859) (2,860) (2,779)
-------------------------------
FINANCING ACTIVITIES
Net borrowings (repayments) of short-term obligations .................. 1,713 (163) (1,179)
Proceeds from issuances of long-term debt .............................. 224 26 95
Repayments of long-term debt and other financing obligations ........... (388) (421) (476)
Cash dividends paid .................................................... (1,596) (1,493) (1,358)
Net (purchases) sales of treasury shares ............................... (261) 173 23
-------------------------------
NET CASH USED FOR FINANCING ACTIVITIES ................................. (308) (1,878) (2,895)
-------------------------------
EFFECT OF FOREIGN CURRENCY EXCHANGE RATE CHANGES
ON CASH AND CASH EQUIVALENTS ........................................... (10) (19) (2)
-------------------------------
NET CHANGE IN CASH AND CASH EQUIVALENTS .................................. (446) 123 271
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR ........................... 1,015 892 621
-------------------------------
CASH AND CASH EQUIVALENTS AT YEAR-END .................................... $ 569 $ 1,015 $ 892
===============================
============================================================================================================
*Certain amounts were reclassified to conform to the 1998 presentation.
See accompanying notes to consolidated financial statements.
(1)"Net (increase) decrease in operating working capital" is composed of
the following:
Decrease in accounts and notes receivable .............................. $ 552 $ 474 $ 38
(Increase) decrease in inventories ..................................... (116) (11) 60
(Increase) decrease in prepaid expenses and other current assets ....... (23) 59 15
(Decrease) increase in accounts payable and accrued liabilities ........ (807) (685) 369
(Decrease) increase in income and other taxes payable .................. (415) (90) 167
-------------------------------
Net (increase) decrease in operating working capital ............... $ (809) $ (253) $ 649
============================================================================================================
(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) .................... $ 407 $ 318 $ 361
Income taxes paid ...................................................... $ 654 $ 1,706 $ 1,595
============================================================================================================
(3)"Net (purchases) sales of marketable securities" consists of the
following gross amounts:
Marketable securities purchased ........................................ $(2,679) $(2,724) $(3,443)
Marketable securities sold ............................................. 2,496 2,825 3,487
-------------------------------
Net (purchases) sales of marketable securities ..................... $ (183) $ 101 $ 44
============================================================================================================
FS-16
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
1998 1997 1996
----------------------- ------------------------ -----------------------
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 ..... 56,555,871 $ (1,977) 59,401,015 $ (2,024) 60,160,057 $ (2,047)
Purchases ................ 5,246,100 (398) 1,255,022 (95) 69,278 (4)
Reissuances .............. (2,341,305) 82 (4,100,166) 142 (822,320) 27
----------------------------------------------------------------------------
Balance at December 31 ... 59,460,666 $ (2,293) 56,555,871 $ (1,977) 59,401,015 $ (2,024)
-------------------------------------------------------------------------------------------------------------------------
CAPITAL IN EXCESS OF PAR
Balance at January 1 ..... $ 2,022 $ 1,874 $ 1,863
Treasury stock transactions relating
to employee compensation plans 75 148 11
-------- -------- --------
Balance at December 31 ... $ 2,097 $ 2,022 $ 1,874
-------------------------------------------------------------------------------------------------------------------------
DEFERRED COMPENSATION
Balance at January 1 ..... $ (750) $ (800) $ (850)
Reduction of ESOP debt and other 59 50 50
-------- -------- --------
Balance at December 31 ... $ (691) $ (750) $ (800)
-------------------------------------------------------------------------------------------------------------------------
ACCUMULATED OTHER
COMPREHENSIVE INCOME (1)
Balance at January 1 ..... $ (77) $ 96 $ 174
Change during year ....... (13) (173) (78)
-------- -------- --------
Balance at December 31 ... $ (90) $ (77) $ 96
-------------------------------------------------------------------------------------------------------------------------
RETAINED EARNINGS
Balance at January 1 ..... $ 17,185 $ 15,408 $ 14,146
Net Income ............... 1,339 3,256 2,607
Cash dividends (per-share amounts
1998: $2.44; 1997: $2.28; 1996: $2.08) (1,596) (1,493) (1,358)
Tax benefit from dividends paid on
unallocated ESOP shares 14 14 13
-------- -------- --------
Balance at December 31 ... $ 16,942 $ 17,185 $ 15,408
-------------------------------------------------------------------------------------------------------------------------
TOTAL STOCKHOLDERS' EQUITY
AT DECEMBER 31 ......... $ 17,034 $ 17,472 $ 15,623
=========================================================================================================================
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, 1996 .... $ 172 $ 34 $ (32) $ 174
Change during the year ........ (54) (20) (4) (78)
----------------------------------------------------------------------------------------------------------------
Balance at December 31, 1996 .. $ 118 $ 14 $ (36) $ 96
Change during the year ........ (173) (4) 4 (173)
----------------------------------------------------------------------------------------------------------------
Balance at December 31, 1997 .. $ (55) $ 10 $ (32) $ (77)
Change during the year ........ (1) 3 (15) (13)
----------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 .. $ (56) $ 13 $ (47) $ (90)
================================================================================================================
FS-17
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 approximately 90 other
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 generally accepted accounting
principles 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 of accounting 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 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."
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 fair
values. For proved oil and gas properties in the United States, the company
would typically perform 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 when the event occurred.
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.
Environmental Expenditures
- - --------------------------
Environmental expenditures that relate to current ongoing operations or to
conditions caused by past operations are expensed. Expenditures that
FS-18
Note 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Continued
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.
Stock Compensation
- - ------------------
The company applies Accounting Principles Board Opinion No. 25, "Accounting for
Stock Issued to Employees,"(APB Opinion 25) 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"(SFAS 123), 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
------------------------------
1998 1997 1996
- - -------------------------------------------------------------------------------
Asset write-offs and revaluations
Asset impairments
- - - Oil and gas properties ...................... $ (50) $ (68) $ (68)
U.S. refining, marketing and
transportation assets ......................... (22) -- --
U.K. refining and marketing assets ............ -- -- (200)
Chemicals assets .............................. (19) (10) (12)
Real estate assets ............................ (9) -- (29)
Computer and telecommunications
equipment ..................................... (59) (8) (12)
Other assets .................................. -- -- (16)
-----------------------------
(159) (86) (337)
- - -------------------------------------------------------------------------------
Asset dispositions, net
Oil and gas properties ........................ (9) 240 80
U.K. refining and marketing exit .............. -- (72) --
Sale of domestic shipping assets .............. -- (18) --
Sale of chemicals affiliate ................... -- 33 --
Sale of two Caltex affiliate refineries ....... -- -- 279
Dynegy merger ................................. -- -- 32
-----------------------------
(9) 183 391
- - -------------------------------------------------------------------------------
Prior-year tax adjustments .................... 271 152 52
- - --------------------------------------------------------------------------------
Environmental remediation provisions, net ..... (39) (35) (54)
- - --------------------------------------------------------------------------------
Restructurings and reorganizations
Caltex affiliate .............................. (43) (6) (14)
Dynegy affiliate .............................. -- (54) --
-----------------------------
(43) (60) (14)
- - -------------------------------------------------------------------------------
LIFO inventory (losses) gains ................. (25) 5 (4)
- - -------------------------------------------------------------------------------
Other, net
Settlement of insurance claims ................ 105 7 --
Caltex write-off of
start-up costs (SOP 98-5) ..................... (25) -- --
Litigation and regulatory issues* ............. (682) (24) (90)
Performance stock options ..................... -- (66) --
Federal lease cost refund ..................... -- -- 12
-----------------------------
(602) (83) (78)
- - -------------------------------------------------------------------------------
Total special items, after tax ................ $(606) $ 76 $ (44)
===============================================================================
*1998 includes provision related to Cities Service litigation.
Other financial information is as follows:
Year ended December 31
-----------------------------
1998 1997 1996
- - -------------------------------------------------------------------------------
Total financing interest and debt costs ........ $ 444 $ 411 $ 472
Less: capitalized interest ..................... 39 99 108
-----------------------------
Interest and debt expense ...................... 405 312 364
Research and development expenses .............. 187 179 182
Foreign currency (losses) gains* ............... $ (47) $ 246 $ (26)
===============================================================================
*Includes $(68), $177 and $(28) in 1998, 1997 and 1996, 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
$584, $1,089 and $1,122 at December 31, 1998, 1997 and 1996, 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),
FS-19
Note 3. CUMULATIVE EFFECT ON NET INCOME FROM ACCOUNTING CHANGES - Continued
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, and it had no impact on the company's
accounting practices. However, Caltex capitalized these types of costs for
certain projects. Chevron, accordingly, restated its 1998 quarterly financial
statements for its $25 share of the charge associated with Caltex's fourth
quarter 1998 implementation of SOP 98-5, effective January 1, 1998.
In the fourth quarter 1998, Chevron changed its method of calculating certain
Canadian deferred income taxes, effective January 1, 1998. The benefit from this
change was $32 and resulted in the restatement of first quarter 1998 net income.
The net benefit to Chevron's restated first quarter 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.
Chevron also adopted other new accounting statements and positions during 1998,
but these were not material to the company's results of operations or its
consolidated balance sheet.
Note 4. INFORMATION RELATING TO THE CONSOLIDATED STATEMENT OF CASH FLOWS
- - -------------------------------------------------------------------------
The Consolidated Statement of Cash Flows excludes the following noncash
transactions:
During 1997, the company's Venice, Louisiana, natural gas facilities were
contributed to a partnership with Dynegy Inc. (Dynegy). An increase in
"Investments and advances" from this merger is considered a noncash transaction
and resulted primarily from the contribution of properties, plant and equipment.
During 1996, the company merged substantially all of its natural gas liquids and
natural gas marketing businesses with Dynegy. The company received cash, a note
and shares of Dynegy common stock and participating preferred stock in exchange
for its contribution of net assets to Dynegy. Only the cash received is included
in the Consolidated Statement of Cash Flows as "Proceeds from asset sales."
The major components of "Capital expenditures" and the reconciliation of this
amount to the capital and exploratory expenditures, excluding equity in
affiliates, presented in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" are presented below:
Year ended December 31
-------------------------------
1998 1997 1996
- - -------------------------------------------------------------------------------
Additions to properties,
plant and equipment ........................ $ 3,678 $ 3,840 $ 3,250
Additions to investments ................... 306 153 195
Payments for other liabilities
and assets, net ............................ (104) (94) (21)
- - -------------------------------------------------------------------------------
Capital expenditures ....................... 3,880 3,899 3,424
Expensed exploration expenditures .......... 438 462 400
Payments of long-term debt
and other financing obligations ............ 2 6 33
- - -------------------------------------------------------------------------------
Capital and exploratory expenditures,
excluding equity affiliates ................ $ 4,320 $ 4,367 $ 3,857
===============================================================================
There have been other noncash transactions that have occurred during the years
presented. These include the contribution of working capital balances in
exchange for an equity interest in a newly formed entity; the acquisition of
long-term debt in exchange for the termination of a capital lease obligation;
the reissuance of treasury shares for management and employee compensation
plans; and changes in assets, liabilities and stockholders' equity resulting
from the accounting for the company's Employee Stock Ownership Plan (ESOP),
minimum pension liability and market value adjustments on investments. The
amounts for these transactions are not material in the aggregate in relation to
the company's financial position.
"Other, net" operating activities in 1998 include a non-current provision for
the Cities Service litigation.
Note 5. STOCKHOLDERS' EQUITY
- - ------------------------------
Retained earnings at December 31, 1998 and 1997, include $2,121 and $2,272,
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 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 1998 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 natural gas swap contracts
entered into principally with major financial institutions. The futures
contracts hedge anticipated crude oil purchases and sales and product sales,
generally forecast to occur within a 60- to 90-day period. Natural gas swaps are
used primarily
FS-20
Note 6. FINANCIAL AND DERIVATIVE INSTRUMENTS - Continued
to hedge firmly committed sales, and the terms of the swap contracts held at
year-end 1998 have an average remaining maturity of 55 months. Gains and losses
on these derivative instruments offset and are recognized concurrently with
gains and losses from the underlying commodities.
In addition, the company in 1998 and 1997 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 are reflected
currently in income and were not material in 1998 or 1997.
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 forecast 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 either semiannually or annually, and are recorded monthly as "Interest
and debt expense." At December 31, 1998, there were three outstanding contracts,
with remaining terms of between eight months and seven years.
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 various foreign governments
and 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 are the
principal security obtained to support lines of credit or negotiated contracts
when the financial strength of a customer is not considered sufficient.
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, 1998 and 1997, the fair values of the
financial and derivative instruments were as follows:
Long-term debt of $1,403 and $1,414 had estimated fair values of $1,485 and
$1,481.
The notional principal amounts of the interest rate swaps totaled $700 and
$1,050, with approximate fair values totaling $(21) and $(16). 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 $1,206 and $1,483. Of these
balances, $362 and $828 classified as cash equivalents had average maturities
under 90 days, while the remainder, classified as marketable securities, had
average maturities of two years and three years.
For other derivatives the contract or notional values were as follows: Crude oil
and products futures had net contract values of $33 and $4, approximating their
fair values. Forward exchange contracts had contract values of $180 and $47,
approximating their fair values. Gas swap contracts, based on notional gas
volumes of approximately 67 and 75 billion cubic feet, had fair values
approximating their face values. Deferred gains and losses that have been
accrued on the Consolidated Balance Sheet are not material.
Note 7. SUMMARIZED FINANCIAL DATA - CHEVRON U.S.A. INC.
- - --------------------------------------------------------
At December 31, 1998, Chevron U.S.A. Inc. was Chevron Corporation's principal
operating company, consisting primarily of the company's U.S. integrated
petroleum operations (excluding most of the domestic pipeline operations) and,
effective February 1, 1998, the majority of the company's worldwide
petrochemicals operations. In 1998, these operations were conducted primarily by
three divisions: Chevron U.S.A. Production Company, Chevron Products Company and
Chevron Chemical Company, LLC. Prior to September 1, 1996, Chevron U.S.A. Inc.'s
natural gas liquids operations were conducted by its Warren Petroleum Company
division, and its natural gas marketing operations were conducted by Chevron
U.S.A. Production Company. Beginning September 1, 1996, these operations are
carried out through its 28 percent equity ownership in Dynegy. Summarized
financial information for Chevron U.S.A. Inc. and its consolidated subsidiaries
is presented below:
Year ended December 31
---------------------------------
1998 1997 1996
- - --------------------------------------------------------------------------------
Sales and other operating revenues ...... $24,440 $28,130 $29,726
Total costs and other deductions ........ 24,338 26,354 28,331
Net income .............................. 346 1,484 1,042
================================================================================
At December 31
--------------------------
1998 1997
- - --------------------------------------------------------------------------------
Current assets ............................. $ 3,227 $ 2,854
Other assets ............................... 18,306 13,867
Current liabilities ........................ 3,809 3,282
Other liabilities .......................... 6,517 4,966
Net equity ................................. 11,207 8,473
================================================================================
Note 8. SUMMARIZED FINANCIAL DATA - CHEVRON TRANSPORT CORPORATION
- - -----------------------------------------------------------------
Chevron Transport Corporation (CTC), a Liberian corporation, 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
FS-21
Note 8. SUMMARIZED FINANCIAL DATA - CHEVRON TRANSPORT CORPORATION - Continued
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.
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, 1998.
Year ended December 31
-------------------------------
1998 1997* 1996
- - --------------------------------------------------------------------------------
Sales and other operating revenues ........... $573 $544 $512
Total costs and other deductions ............. 580 557 564
Net income ................................... 17 28 11
================================================================================
*Certain amounts were reclassified to conform to the 1998 and 1996 presentations.
At December 31
----------------------------
1998 1997
- - --------------------------------------------------------------------------------
Current assets ............................... $270 $243
Other assets ................................. 982 897
Current liabilities .......................... 898 666
Other liabilities ............................ 284 311
Net equity ................................... 70 163
================================================================================
The 1998 decrease in "Net equity" was due primarily to the return of $110
million of paid-in capital to CTC's parent in partial settlement of a receivable
balance.
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.
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, which are held
for sale; insurance operations, and real estate activities.
Reportable operating segment sales and other operating revenues, including
internal transfers, for the years 1998, 1997 and 1996 are presented in the
following table. Sales from the transfer of products between segments are at
estimated market prices. Segment revenues are presented on the following table.
Year ended December 31
-------------------------------
1998 1997 1996
- - ------------------------------------------------------------------------
EXPLORATION AND PRODUCTION
United States
Crude oil ........................... $ - $ (3) $ (36)
Natural gas ......................... 1,599 1,978 2,742
Natural gas liquids ................. 128 185 944
Other ............................... 12 20 59
Intersegment ........................ 1,453 4,362 2,970
-------------------------------
Total United States ................. 3,192 6,542 6,679
- - ------------------------------------------------------------------------
International
Refined products .................... 1 2 (2)
Crude oil ........................... 1,761 2,790 2,852
Natural gas ......................... 505 590 558
Natural gas liquids ................. 89 170 142
Other ............................... 130 116 133
Intersegment ........................ 1,984 2,810 2,881
-------------------------------
Total International ................. 4,470 6,478 6,564
- - ------------------------------------------------------------------------
TOTAL EXPLORATION
AND PRODUCTION ...................... 7,662 13,020 13,243
- - ------------------------------------------------------------------------
REFINING, MARKETING
AND TRANSPORTATION
United States
Refined products .................... 10,148 12,586 12,295
Crude oil ........................... 2,971 4,531 4,872
Natural gas liquids ................. 100 158 48
Other ............................... 622 592 624
Excise taxes ........................ 3,503 3,386 3,230
Intersegment ........................ (1,172) (1,916) (2,068)
--------------------------------
Total United States ................. 16,172 19,337 19,001
- - ------------------------------------------------------------------------
International
Refined products .................... 1,312 2,998 3,493
Crude oil ........................... 3,049 3,978 4,709
Natural gas liquids ................. 5 40 33
Other ............................... 299 390 367
Excise taxes ........................ 213 2,188 1,959
Intersegment ........................ 20 15 18
--------------------------------
Total International ................. 4,898 9,609 10,579
- - ------------------------------------------------------------------------
TOTAL REFINING, MARKETING
AND TRANSPORTATION .................. 21,070 28,946 29,580
- - ------------------------------------------------------------------------
CHEMICALS
United States
Products ............................ 2,468 2,933 2,831
Excise taxes ........................ 2 - -
Intersegment ........................ 121 112 105
--------------------------------
Total United States ................. 2,591 3,045 2,936
- - ------------------------------------------------------------------------
International
Products ............................ 568 559 556
Other ............................... 18 28 35
Excise taxes ........................ 38 13 12
Intersegment ........................ 1 2 2
--------------------------------
Total International ................. 625 602 605
- - ------------------------------------------------------------------------
TOTAL CHEMICALS ..................... 3,216 3,647 3,541
- - ------------------------------------------------------------------------
ALL OTHER
United States - Coal ................ 399 359 329
United States - Other ............... (1) 8 (14)
International ....................... 4 1 11
Intersegment - United States ........ 52 47 -
Intersegment - International ........ 2 - -
- - ------------------------------------------------------------------------
TOTAL ALL OTHER ..................... 456 415 326
- - ------------------------------------------------------------------------
Sales and Other Operating Revenues
- - - United States ..................... 22,405 29,338 28,931
Sales and Other Operating Revenues
- - - International ..................... 9,999 16,690 17,759
- - ------------------------------------------------------------------------
Total Segment Sales and
Other Operating Revenues ............ 32,404 46,028 46,690
- - ------------------------------------------------------------------------
Elimination of Intersegment Sales ... (2,461) (5,432) (3,908)
- - ------------------------------------------------------------------------
Total Sales and
Other Operating Revenues ............ $ 29,943 $ 40,596 $ 42,782
========================================================================
FS-22
Note 9. OPERATING SEGMENTS AND GEOGRAPHIC DATA - Continued
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 for direct
corporate services. Nonbillable costs remain as corporate center expenses. Other
than depreciation expense and deferred income taxes, there were no significant
noncash items included in segment results. After-tax segment operating earnings
for the years 1998, 1997 and 1996 are presented in the following table.
Year ended December 31
-----------------------------------
1998 1997 1996
- - -------------------------------------------------------------------------------
EXPLORATION AND PRODUCTION
United States ........................ $ 365 $ 1,001 $ 1,087
International ........................ 707 1,252 1,211
- - -------------------------------------------------------------------------------
TOTAL EXPLORATION
AND PRODUCTION ....................... 1,072 2,253 2,298
- - -------------------------------------------------------------------------------
REFINING, MARKETING
AND TRANSPORTATION
United States ........................ 572 601 193
International ........................ 28 298 226
- - -------------------------------------------------------------------------------
TOTAL REFINING, MARKETING
AND TRANSPORTATION ................... 600 899 419
- - -------------------------------------------------------------------------------
CHEMICALS
United States ........................ 79 138 147
International ........................ 43 90 53
- - -------------------------------------------------------------------------------
TOTAL CHEMICALS ...................... 122 228 200
- - -------------------------------------------------------------------------------
TOTAL SEGMENT INCOME ................. 1,794 3,380 2,917
- - -------------------------------------------------------------------------------
Interest Expense ..................... (270) (189) (242)
Interest Income ...................... 63 75 51
Other ................................ (248) (10) (119)
- - -------------------------------------------------------------------------------
NET INCOME ........................... $ 1,339 $ 3,256 $ 2,607
===============================================================================
NET INCOME - UNITED STATES ........... $ 642 $ 1,622 $ 1,144
NET INCOME - INTERNATIONAL ........... $ 697 $ 1,634 $ 1,463
- - -------------------------------------------------------------------------------
TOTAL NET INCOME ..................... $ 1,339 $ 3,256 $ 2,607
===============================================================================
Segment Income Taxes
- - ---------------------
Segment income tax expense for the years 1998, 1997 and
1996 is as follows:
Year ended December 31
-----------------------------------
1998 1997 1996
- - -------------------------------------------------------------------------------
EXPLORATION AND PRODUCTION
United States ........................ $ 164 $ 559 $ 521
International ........................ 595 1,488 1,633
- - -------------------------------------------------------------------------------
TOTAL EXPLORATION
AND PRODUCTION ....................... 759 2,047 2,154
- - -------------------------------------------------------------------------------
REFINING, MARKETING
AND TRANSPORTATION
United States ........................ 309 346 122
International ........................ 54 6 30
- - -------------------------------------------------------------------------------
TOTAL REFINING, MARKETING
AND TRANSPORTATION ................... 363 352 152
- - -------------------------------------------------------------------------------
CHEMICALS
United States ........................ 25 77 72
International ........................ 14 57 27
- - -------------------------------------------------------------------------------
TOTAL CHEMICALS ...................... 39 134 99
- - -------------------------------------------------------------------------------
All Other ............................ (666) (287) (272)
- - -------------------------------------------------------------------------------
Total Income Tax expense ............. $ 495 $ 2,246 $ 2,133
===============================================================================
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 1998, 1997 and 1996 are as follows:
At December 31
------------------------
1998 1997
- - ------------------------------------------------------------------------
EXPLORATION AND PRODUCTION
United States .......................... $ 6,026 $ 5,848
International .......................... 10,794 9,830
- - ------------------------------------------------------------------------
TOTAL EXPLORATION
AND PRODUCTION ......................... 16,820 15,678
- - ------------------------------------------------------------------------
REFINING, MARKETING
AND TRANSPORTATION
United States .......................... 8,084 8,109
International .......................... 3,559 3,786
- - ------------------------------------------------------------------------
TOTAL REFINING, MARKETING
AND TRANSPORTATION ..................... 11,643 11,895
- - ------------------------------------------------------------------------
CHEMICALS
United States .......................... 3,045 2,828
International .......................... 828 690
- - ------------------------------------------------------------------------
TOTAL CHEMICALS ........................ 3,873 3,518
- - ------------------------------------------------------------------------
TOTAL SEGMENT ASSETS ................... 32,336 31,091
- - ------------------------------------------------------------------------
ALL OTHER
United States .......................... 2,467 2,730
International .......................... 1,737 1,652
- - ------------------------------------------------------------------------
TOTAL All OTHER ........................ 4,204 4,382
- - ------------------------------------------------------------------------
TOTAL ASSETS - UNITED STATES ........... 19,622 19,515
TOTAL ASSETS - INTERNATIONAL ........... 16,918 15,958
- - ------------------------------------------------------------------------
TOTAL ASSETS ........................... $36,540 $35,473
========================================================================
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.
Note 10. LITIGATION
- - -------------------
The company is a defendant in numerous lawsuits, including, along with other oil
companies, actions challenging oil and gas royalty and severance tax payments
based on posted prices and others related to the use of the chemical MTBE in
certain oxygenated gasolines. Plaintiffs may seek to recover large and sometimes
unspecified amounts, and some matters may remain unresolved for several years.
It is not practical to estimate a range of possible loss for the company's
litigation matters, and losses could be material with respect to earnings in any
given period. However, management is of the opinion that resolution of the
lawsuits will not result in any significant liability to the company in relation
to its consolidated financial position or liquidity.
The company is a defendant in a lawsuit that OXY U.S.A. brought in its capacity
as successor in interest to Cities Service Company. The lawsuit claims damages
resulting from the allegedly improper termination of a tender offer made by
FS-23
Gulf Oil Corporation, acquired by Chevron in 1984, to purchase Cities Service in
1982. A 1996 trial resulted in a judgment against the company of $742 million,
including interest that continues to accrue at 9.55 percent per year while this
matter is pending. The Oklahoma Supreme Court affirmed the lower court's
decision in March 1999, and accordingly, the company recorded in 1998 results a
litigation reserve of $637 million, substantially all of which pertained to this
lawsuit. The ultimate outcome of this matter cannot be determined presently with
certainty, and the company will seek further review of this case in the
appropriate courts.
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
-------------------
1998 1997
- - ----------------------------------------------------------
Exploration and Production ........... $ 5 $ 5
Refining, Marketing and Transportation 757 756
- - ----------------------------------------------------------
Total ................................ 762 761
Less: accumulated amortization ....... 398 371
- - ----------------------------------------------------------
Net capitalized leased assets ........ $364 $390
==========================================================
At December 31, 1998, the future minimum lease payments under operating and
capital leases are as follows:
At December 31
----------------------------
Operating Capital
Year .................................. Leases Leases
- - --------------------------------------------------------------------
1999 ................................. $ 133 $ 68
2000 ................................. 116 61
2001 ................................. 109 57
2002 ................................. 103 53
2003 ................................. 98 52
Thereafter .......................... 284 709
- - --------------------------------------------------------------------
Total .................................. $ 843 1,000
- - --------------------------------------------------
Less: amounts representing interest
and executory costs .................. 429
- - --------------------------------------------------------------------
Net present values ................... 571
Less: capital lease obligations
included in short-term debt .......... 306
- - --------------------------------------------------------------------
Long-term capital lease obligations .. $ 265
====================================================================
Future sublease rental income ........ $ 17 $ -
====================================================================
Rental expenses incurred for operating leases during 1998, 1997 and 1996 were as
follows:
Year ended December 31
---------------------------
1998 1997 1996
- - -----------------------------------------------------------------
Minimum rentals ...................... $503 $443 $438
Contingent rentals ................... 5 5 6
- - -----------------------------------------------------------------
Total ................................ 508 448 444
Less: sublease rental income ......... 3 5 15
- - -----------------------------------------------------------------
Net rental expense ................... $505 $443 $429
=================================================================
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. In April 1997,
Chevron sold 10 percent of its interest in TCO to an affiliate of LUKoil, a
Russian oil company, and ARCO. The sale reduced Chevron's ownership to 45
percent. 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 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, including
natural gas, natural gas liquids, crude oil and electricity. The market value of
Chevron's shares of Dynegy common stock at December 31, 1998, was $424 based on
quoted closing market prices.
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
-------------------------------------------------------------
1998 1997(1) 1998 1997(1) 1996(1)
- - -------------------------------------------------------------------------------------
Exploration and
Production
Tengizchevroil .......... $1,455 $1,255 $ 60 $ 169 $ 110
Caltex Group ............ 452 438 107 171 188
Dynegy .................. 265 385 49 (17) 25
Other ................... 134 77 4 13 (1)
- - -------------------------------------------------------------------------------------
Total Exploration
and Production ....... 2,306 2,155 220 336 322
- - -------------------------------------------------------------------------------------
Refining, Marketing
and Transportation
Caltex Group ............ 1,751 1,863 (36) 252 408
Other ................... 124 84 24 57 8
- - -------------------------------------------------------------------------------------
Total Refining,
Marketing and
Transportation ...... 1,875 1,947 (12) 309 416
- - -------------------------------------------------------------------------------------
Chemicals ................ 135 132 -- 25 32
All Other ................ 74 54 20 18 (3)
- - -------------------------------------------------------------------------------------
Total Equity Method $4,390 $4,288 $ 228 $ 688 $ 767
- - -------------------------------------------------------------------------------------
Other at or below cost 214 208
Total Investments and
Advances $4,604 $4,496
=====================================================================================
(1) Reclassified to conform to 1998 presentation
FS-24
Effective October 1, 1997, Caltex's management changed the functional currency
for its Korean and Japanese equity affiliates from their local currencies to the
U.S. dollar, based on significantly changed economic facts and circumstances,
primarily the changing regulatory environments in those countries.
The company received dividends and distributions of $254, $335 and $828 in 1998,
1997 and 1996, respectively, including $167, $207 and $735 from the Caltex
Group. Also during 1998, Dynegy repaid a $155 loan to 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
following table. These are primarily for the purchase of Indonesian crude oil
from CPI, the sale of crude oil and products to Caltex Corp.'s refining and
marketing companies, the sale of natural gas to Dynegy, and the purchase of
natural gas and natural gas liquids from Dynegy.
Year ended December 31
1998 1997 1996
----------------------------------
Sales to Caltex Group ...................... $ 772 $1,335 $1,708
Sales to Dynegy Inc. ....................... 1,307 1,822 676
Sales to other affiliates .................. 26 8 18
- - --------------------------------------------------------------------------------
Total sales to affiliates .................. $2,105 $3,165 $2,402
================================================================================
Purchases from Caltex Group ................ $ 681 $ 932 $1,022
Purchases from Dynegy Inc. ................. 642 854 269
Purchases from other affiliates ............ 2 16 41
- - --------------------------------------------------------------------------------
Total purchases from affiliates ............ $1,325 $1,802 $1,332
================================================================================
"Accounts and notes receivable" in the Consolidated Balance Sheet include $156
and $145 at December 31, 1998 and 1997, respectively, of amounts due from
affiliated companies. "Accounts payable" include $41 and $57 at December 31,
1998 and 1997, respectively, of amounts due to affiliated companies.
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 ........... 1998 1997 1996 1998 1997 1996 1998 1997 1996
- - ----------------------------------------------------------------------------------------------------------------------------
Sales and other operating revenues $16,969 $17,920 $16,895 $16,842 $16,574 $ 6,356 $14,029 $13,827 $10,218
Total costs and other deductions 16,655 17,147 15,991 16,430 15,770 5,829 13,371 13,118 9,573
Net income ....................... 143 846 1,193 295 556 404 228 688 767
============================================================================================================================
Caltex Group Other Affiliates Chevron's Share
---------------------------------------------------------------------------------------
At December 31 ...... 1998 1997 1996 1998 1997 1996 1998 1997 1996
- - ----------------------------------------------------------------------------------------------------------------------------
Current assets ....... $1,974 $2,521 $2,681 $3,326 $3,232 $3,286 $2,015 $2,289 $2,284
Other assets ......... 7,683 7,193 6,714 8,868 6,713 6,088 6,663 5,971 5,524
Current liabilities .. 2,840 2,991 2,999 2,723 2,565 2,064 2,162 2,232 2,076
Other liabilities .... 2,420 2,131 2,140 7,147 5,448 5,034 2,126 1,740 1,448
Net equity ........... 4,397 4,592 4,256 2,324 1,932 2,276 4,390 4,288 4,284
============================================================================================================================
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
------------------------ ----------------------- ----------------------- -----------------------
1998 1997 1996 1998 1997 1996 1998 1997 1996 1998 1997 1996
- - ------------------------------------------------------------------------------------------------------------------------------
Exploration and Production
United States ............. $18,372 $18,104 $17,742 $ 5,237 $ 5,052 $ 4,849 $ 1,000 $ 1,166 $ 974 $ 818 $ 887 $ 785
International ............. 12,755 11,752 10,516 7,148 6,691 6,026 1,221 1,310 1,231 730 634 581
- - ------------------------------------------------------------------------------------------------------------------------------
Total Exploration
and Production ............ 31,127 29,856 28,258 12,385 11,743 10,875 2,221 2,476 2,205 1,548 1,521 1,366
- - ------------------------------------------------------------------------------------------------------------------------------
Refining, Marketing
and Transportation
United States ............ 11,793 11,378 11,186 6,268 6,186 6,295 665 538 415 483 464 472
International ............ 2,005 2,063 2,259 1,139 1,210 1,387 50 57 70 81 111 115
- - ------------------------------------------------------------------------------------------------------------------------------
Total Refining, Marketing
and Transportation ...... 13,798 13,441 13,445 7,407 7,396 7,682 715 595 485 564 575 587
- - ------------------------------------------------------------------------------------------------------------------------------
Chemicals
United States ........... 3,436 3,039 2,587 2,211 1,931 1,552 385 470 376 109 92 138
International ........... 662 549 393 414 309 163 116 157 37 10 12 24
- - ------------------------------------------------------------------------------------------------------------------------------
Total Chemicals ........... 4,098 3,588 2,980 2,625 2,240 1,715 501 627 413 119 104 162
- - ------------------------------------------------------------------------------------------------------------------------------
All Other(2) .............. 2,314 2,348 2,253 1,312 1,292 1,224 202 110 93 89 100 101
- - ------------------------------------------------------------------------------------------------------------------------------
Total United States ....... 35,915 34,867 33,764 15,028 14,461 13,920 2,252 2,284 1,858 1,499 1,543 1,496
Total International ....... 15,422 14,366 13,172 8,701 8,210 7,576 1,387 1,524 1,338 821 757 720
- - ------------------------------------------------------------------------------------------------------------------------------
Total ..................... $51,337 $49,233 $46,936 $23,729 $22,671 $21,496 $ 3,639 $ 3,808 $ 3,196 $ 2,320 $ 2,300 $ 2,216
==============================================================================================================================
(1) Net of dry hole expense related to prior years' expenditures of $40, $31 and
$55 in 1998, 1997 and 1996, respectively.
(2) Primarily coal assets, real estate assets and management information
systems.
Expenses for maintenance and repairs were $833, $738 and $626 in 1998, 1997 and
1996, respectively.
FS-25
Note 14. TAXES
- - --------------
Year ended December 31
--------------------------
1998 1997 1996
- - -----------------------------------------------------------
Taxes other than on income
United States
Excise taxes on products
and merchandise .............. $3,505 $3,386 $3,231
Property and other
miscellaneous taxes .......... 262 274 274
Payroll taxes ................. 129 123 123
Taxes on production ........... 92 118 121
- - -----------------------------------------------------------
Total United States ........ 3,988 3,901 3,749
- - -----------------------------------------------------------
International
Excise taxes on products
and merchandise .............. 251 2,201 1,971
Property and other
miscellaneous taxes .......... 137 185 157
Payroll taxes ................. 26 23 26
Taxes on production ........... 9 10 5
- - -----------------------------------------------------------
Total International ........ 423 2,419 2,159
- - -----------------------------------------------------------
Total taxes other than on income $4,411 $6,320 $5,908
===========================================================
U.S. federal income tax expense was reduced by $84, $93 and $77 in 1998, 1997
and 1996, respectively, for low-income housing and other business tax credits.
In 1998, before-tax income, including related corporate and other charges, for
U.S. operations was $728, compared with $2,054 in 1997 and $1,631 in 1996. For
international operations, before-tax income was $1,106, $3,448 and $3,109 in
1998, 1997 and 1996, respectively.
The deferred income tax provisions included costs of $470, $304 and $204 related
to properties, plant and equipment in 1998, 1997 and 1996, respectively.
Year ended December 31
-------------------------
1998 1997 1996
- - -----------------------------------------------------------
Taxes on income
U.S. federal
Current ...................... $ (176) $ 369 $ 360
Deferred ..................... 71 357 165
State and local .............. 20 81 59
- - -----------------------------------------------------------
Total United States ...... (85) 807 584
- - -----------------------------------------------------------
International
Current ...................... 385 1,174 1,356
Deferred ..................... 195 265 193
- - -----------------------------------------------------------
Total International ...... 580 1,439 1,549
- - -----------------------------------------------------------
Total taxes on income .......... $ 495 $2,246 $2,133
===========================================================
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
-----------------------------
1998 1997 1996
- - --------------------------------------------------------------------------
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 ................... 7.6 9.6 16.8
State and local taxes on income, net
of U.S. federal income tax benefit .... 0.2 1.3 0.9
Prior-year tax adjustments .............. (4.5) (0.3) (0.2)
Tax credits ............................. (4.6) (1.7) (1.6)
Other ................................... (6.4) (1.7) (3.6)
- - --------------------------------------------------------------------------
Consolidated companies ................ 27.3 42.2 47.3
Effect of recording equity in income
of certain affiliated companies
on an after-tax basis ................. (0.3) (1.4) (2.3)
- - --------------------------------------------------------------------------
Effective tax rate .................... 27.0% 40.8% 45.0%
==========================================================================
The reduction in the 1998 effective rate from prior-year tax adjustments
primarily reflects a benefit from the finalization of the company's 1997 tax
return. The additional reduction in the effective tax rate in 1998 from tax
credits reflects a larger proportion of before-tax income in 1998 than 1997 and
1996 from similar amounts of tax credits. The other effects on the 1998
effective tax rate consist primarily of the utilization of additional capital
loss benefits, the settlement of outstanding issues and permanent differences.
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, 1998 and 1997, deferred taxes were classified in the
Consolidated Balance Sheet as follows:
At December 31
------------------------
1998 1997
- - -------------------------------------------------------------------------------
Prepaid expenses and other current assets .......... $ (30) $ (13)
Deferred charges and other assets .................. (264) (181)
Federal and other taxes on income .................. -- 79
Noncurrent deferred income taxes ................... 3,645 3,215
- - -------------------------------------------------------------------------------
Total deferred income taxes, net ................... $ 3,351 $ 3,100
===============================================================================
The reported deferred tax balances are composed of the following deferred tax
liabilities (assets):
At December 31
--------------------------
1998 1997
- - -------------------------------------------------------------------------------
Properties, plant and equipment .................. $ 5,150 $ 4,724
Inventory ........................................ 144 151
Miscellaneous .................................... 184 200
- - -------------------------------------------------------------------------------
Total deferred tax liabilities ................. 5,478 5,075
- - -------------------------------------------------------------------------------
Abandonment/environmental reserves ............... (774) (872)
Employee benefits ................................ (592) (596)
AMT/other tax credits ............................ (354) (362)
Other accrued liabilities ........................ (408) (202)
Miscellaneous .................................... (294) (382)
- - -------------------------------------------------------------------------------
Total deferred tax assets ...................... (2,422) (2,414)
- - -------------------------------------------------------------------------------
Deferred tax assets valuation allowance .......... 295 439
- - -------------------------------------------------------------------------------
Total deferred taxes, net ........................ $ 3,351 $ 3,100
===============================================================================
FS-26
Note 14. TAXES - Continued
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 $4,558 at December 31, 1998. 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 $186 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, 1998 and 1997, the company had swapped notional amounts of
$700 and $1,050 of floating rate debt to fixed rates. The effect of these swaps
on the company's interest expense was not material.
At December 31
---------------------
1998 1997
- - -------------------------------------------------------------------------------
Commercial paper (1) ................................. $ 4,875 $ 3,352
Current maturities of long-term debt ................. 123 303
Current maturities of long-term capital leases ....... 33 35
Redeemable long-term obligations
Long-term debt ....................................... 301 304
Capital leases ....................................... 273 273
Notes payable ........................................ 285 95
- - -------------------------------------------------------------------------------
Subtotal (2) ........................................ 5,890 4,362
Reclassified to long-term debt ....................... (2,725) (2,725)
- - -------------------------------------------------------------------------------
Total short-term debt ................................ $ 3,165 $ 1,637
===============================================================================
(1) Weighted-average interest rates at December 31, 1998 and 1997, were 5.6%
and 6.1%, respectively, including the effect of interest rate swaps.
(2) Weighted-average interest rates at December 31, 1998 and 1997, were 5.8%
and 6.0%, respectively, including the effect of interest rate swaps.
Note 16.LONG-TERM DEBT
- - ----------------------
Chevron and one of its wholly owned subsidiaries each have "shelf" registrations
on file with the Securities and Exchange Commission that together would permit
the issuance of $1,300 of debt securities pursuant to Rule 415 of the Securities
Act of 1933.
At year-end 1998, the company had $4,050 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 any
borrowings under the agreements is based on either the London Interbank Offered
Rate or the Reserve Adjusted Domestic Certificate of Deposit Rate. No amounts
were outstanding under these credit agreements during the year or at year-end.
At December 31, 1998 and 1997, 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 1999, 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, 1998, is as follows: 1999-$123, 2000-$229, 2001-$141, 2002-$152 and
2003-$164.
At December 31
----------------------
1998 1997
- - -------------------------------------------------------------------------------
8.11% amortizing notes due 2004 (1) .................. $ 690 $ 750
7.45% notes due 2004 ................................. 349 349
7.61% amortizing bank loans due 2003 ................. 172 200
5.6%notes due 1998 ................................... -- 190
6.92% bank loans due 2005 ............................ 51 51
9.75% sinking-fund debentures due 2017 (2) ........... -- 38
LIBOR-based bank loan due 2000 ....................... 100 --
Other foreign currency obligations (4.5%) (3) ........ 94 85
Other long-term debt (5.3%) (3) ...................... 70 54
- - -------------------------------------------------------------------------------
Total including debt due within one year ............. 1,526 1,717
Debt due within one year ............................. (123) (303)
Reclassified from short-term debt .................... 2,725 2,725
- - -------------------------------------------------------------------------------
Total long-term debt ................................. $ 4,128 $ 4,139
===============================================================================
(1) Guarantee of ESOP debt.
(2) Retired in 1998 through use of sinking fund provisions specified in
the Bond Prospectus Supplement.
(3) Less than $50 individually; weighted-average interest rates at December
31, 1998.
Note 17. OTHER COMPREHENSIVE INCOME
- - -----------------------------------
The components of changes in other comprehensive income and the related tax
effects, including the company's share of equity affiliates, are shown below.
Year ended December 31
---------------------------
1998 1997 1996
- - -------------------------------------------------------------------------------
Currency translation adjustment
Before-tax change ................................ $ (1) $(173) $ (54)
Tax benefit (expense) ............................ -- -- --
---------------------------
Change, net of tax ............................... (1) (173) (54)
Unrealized holding gain (loss) on securities
Before-tax change ................................ 3 (11) (38)
Tax benefit (expense) ............................ -- 7 18
---------------------------
Change, net of tax ............................... 3 (4) (20)
Minimum pension liability adjustment
Before-tax change ................................ (24) 6 (6)
Tax benefit (expense) ............................ 9 (2) 2
---------------------------
Change, net of tax ............................... (15) 4 (4)
TOTAL OTHER COMPREHENSIVE INCOME
Before-tax change ................................ $ (22) $(178) $ (98)
Tax benefit (expense) ............................ 9 5 20
---------------------------
Change, net of tax ............................... $ (13) $(173) $ (78)
===============================================================================
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
FS-27
Note 18. EMPLOYEE BENEFIT PLANS - Continued
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.
Non-funded 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 1998 and 1997 is as follows:
Pension Benefits Other Benefits
-------------------------------------------
1998 1997 1998 1997
- - ------------------------------------------------------------------------------
Change in benefit obligation:
Benefit obligation at January 1 $ 4,069 $ 3,773 $ 1,362 $ 1,236
Service cost ................... 113 106 19 17
Interest cost .................. 275 274 93 90
Plan participants' contributions 1 2 -- --
Plan amendments ................ -- -- -- --
Actuarial loss ................. 248 336 72 94
Foreign currency exchange
rate changes ................... (10) (29) -- --
Benefits paid .................. (418) (405) (78) (75)
Special termination
benefits ....................... -- 12 -- --
-------------------------------------------
Benefit obligation
at December 31 ................. 4,278 4,069 1,468 1,362
- - ------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets
at January 1 ................... 4,454 4,149 -- --
Actual return on plan assets ... 675 699 -- --
Foreign currency exchange
rate changes ................... (6) (24) -- --
Employer contribution .......... 11 10 -- --
Plan participants' contribution 1 2 -- --
Benefits paid .................. (394) (382) -- --
-------------------------------------------
Fair value of plan assets
at December 31 ................. 4,741 4,454 -- --
- - ------------------------------------------------------------------------------
Funded status .................. 463 385 (1,468) (1,362)
Unrecognized net actuarial gain (155) (115) (46) (124)
Unrecognized prior service cost 88 102 -- --
Unrecognized net transitional
assets ......................... (85) (127) -- --
- - ------------------------------------------------------------------------------
Total recognized at December 31 $ 311 $ 245 $(1,514) $(1,486)
==============================================================================
Amounts recognized in the
Consolidated Balance Sheet
at December 31:
Prepaid benefit cost ........... $ 524 $ 437 $ -- $ --
Accrued benefit liability ...... (298) (259) (1,514) (1,486)
Intangible asset ............... 12 18 -- --
Accumulated other
comprehensive income (1) ....... 73 49 -- --
-------------------------------------------
Net amount recognized .......... $ 311 $ 245 $(1,514) $(1,486)
==============================================================================
Weighted-average assumptions
as of December 31
Discount rate .................. 6.7% 7.3% 6.8% 7.0%
Expected return on plan assets . 9.1% 9.1% -- --
Rate of compensation increase .. 4.6% 5.2% 4.5% 5.0%
==============================================================================
(1) Accumulated other comprehensive income includes deferred income taxes of
$26 and $17 in 1998 and 1997, respectively.
For measurement purposes, separate health care cost-trend rates were utilized
for pre-age 65 and post-age 65 retirees. The 1999 annual rates of change were
assumed to be 4.6 percent and 10.8 percent, respectively, before gradually
converging to the average ultimate rate of 5.1 percent in 2013 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- 0ne-Percentage-
Point Increase Point Decrease
- - ----------------------------------------------------------------------------
Effect on total service and interest
cost components $ 19 $ (15)
Effect on postretirement benefit
obligation $ 149 $ (121)
- - ----------------------------------------------------------------------------
The components of net periodic benefit cost for 1998, 1997 and 1996 were:
Pension Benefits Other Benefits
--------------------------------------------------
1998 1997 1996 1998 1997 1996
- - -------------------------------------------------------------------------------
Service cost ............. $ 113 $ 106 $ 104 $ 19 $ 17 $ 19
Interest cost ............ 275 274 271 93 90 91
Expected return on
plan assets .............. (397) (371) (351) -- -- --
Amortization of
transitional assets ...... (38) (40) (42) -- -- --
Amortization of prior-
service costs ............ 14 14 13 -- -- --
Recognized actuarial
(gains) losses ........... 4 4 6 (5) (11) (8)
--------------------------------------------------
Net periodic benefit cost $ (29) $ (13) $ 1 $ 107 $ 96 $ 102
===============================================================================
Settlement gains in 1998, 1997 and 1996, related to lump-sum payments, totaled
$11, $29 and $28, respectively. Curtailment gains were immaterial.
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 $408, $364 and $87, respectively, at December 31, 1998, and
$301, $258 and $6, respectively at December 31, 1997.
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 $60, $79 and $92 in 1998, 1997 and 1996, 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. The ESOP
provides a partial pre-funding of the company's future commitments to the profit
sharing part of the plan, which will result in annual income tax savings for the
company. The ESOP is expected to satisfy most of the company's obligations to
the profit sharing part of the plan during the next six years.
As permitted by AICPA Statement of Position 93-6, "Employers' Accounting for
Employee Stock Ownership Plans," the company has elected to continue its
practices,
FS-28
Note 18. EMPLOYEE BENEFIT PLANS - Continued
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 $58, $53 and $61 in 1998, 1997 and
1996, respectively, including $56, $61 and $65 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 $57, $57 and $53 in 1998, 1997
and 1996, respectively.
The company made contributions to the ESOP of $60, $55 and $62 in 1998, 1997
and 1996, 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 profit sharing
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 $2, $(8) and $(4) in 1998, 1997
and 1996, respectively. The ESOP shares as of December 31, 1998 and 1997, were
as follows:
Thousands 1998 1997
- - --------------------------------------------------------------------------------
Allocated shares ......................... 10,819 9,287
Unallocated shares ....................... 14,087 15,929
- - --------------------------------------------------------------------------------
Total ESOP shares ........................ 24,906 25,216
================================================================================
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 management incentive
plans, excluding expense related to LTIP stock options, which is discussed in
Note 19, "Stock Options," were $28, $55 and $36 in 1998, 1997 and 1996,
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. The total
maximum payout under the program is 8 percent of the employee's annual salary.
Charges for the program were $51, $116 and $72 in 1998, 1997 and 1996,
respectively.
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
1998, 1997 and 1996 would have been the pro forma amounts indicated below:
1998 1997 1996
- - ---------------------------------------------------------------------------
Net Income As reported ........... $ 1,339 $ 3,256 $ 2,607
Pro forma ............. $ 1,294 $ 3,302 $ 2,610
Earnings per share As reported - basic.... $ 2.05 $ 4.97 $ 3.99
- diluted . $ 2.04 $ 4.95 $ 3.98
Pro forma - basic.... $ 1.98 $ 5.04 $ 3.99
- diluted . $ 1.97 $ 5.02 $ 3.98
===========================================================================
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 below. 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 1998, 1997 and 1996 is presented below:
Weighted-
Average
Options Exercise
(000s) Price
- - ------------------------------------------------------------
Outstanding at December 31, 1995 7,087 $ 41.46
============================================================
Granted ........................ 952 66.00
Exercised ...................... (698) 38.91
Forfeited ...................... (64) 49.45
- - ------------------------------------------------------------
Outstanding at December 31, 1996 7,277 $ 44.84
============================================================
Granted ........................ 1,802 80.78
Exercised ...................... (710) 38.66
Forfeited ...................... (107) 72.18
- - ------------------------------------------------------------
Outstanding at December 31, 1997 8,262 $ 52.86
============================================================
Granted ........................ 1,872 79.13
Exercised ...................... (796) 40.47
Forfeited ...................... (104) 80.69
- - ------------------------------------------------------------
Outstanding at December 31, 1998 9,234 $ 58.94
============================================================
Exercisable at December 31
1996 6,330 $ 41.68
1997 6,504 $ 45.31
1998 7,379 $ 53.86
============================================================
FS-29
Note 19. STOCK OPTIONS - Continued
The weighted-average fair market value of options granted in 1998, 1997 and
1996 was $21.10, $17.64 and $14.18 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 1998, 1997 and 1996,
respectively: risk-free interest rate of 4.5, 6.1 and 6.4 percent; dividend
yield of 3.1, 2.8 and 3.3 percent; volatility of 28.6, 15.2 and 16.1 percent and
expected life of seven years in all years.
As of December 31, 1998, 9,234,463 shares were under option at exercise prices
ranging from $31.9375 to $84.8750 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, 1998:
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 1,102 2.90 $ 34.66 1,102 $ 34.66
41 to 51 3,791 5.64 45.00 3,791 45.00
51 to 61 19 7.33 56.75 19 56.75
61 to 71 810 7.83 66.25 810 66.25
71 to 81 3,489 9.34 79.91 1,657 80.82
81 to 91 23 9.40 82.77 -- --
- - -----------------------------------------------------------------------------------
$31 to $91 9,234 6.92 $ 58.94 7,379 $ 53.86
===================================================================================
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 December
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 302,500 shares reduced the outstanding
option shares to 6,902,300 at December 31, 1996. In 1997, exercises of 4,171,300
and forfeitures of 517,550 had reduced the outstanding option shares to
2,213,450 at year-end 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.
Unexercised options expire on March 31, 1999. Under APB Opinion No. 25, the
company recorded expenses of $125 and $29 for these options in 1997 and 1996,
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 will vest in February 2000. Options for 4,820,800 shares were
awarded at an exercise price of $76.3125 per share. Forfeitures of options for
270,650 shares reduced the outstanding option shares to 4,550,150 at December
31, 1998, at which date none was exercisable. The options expire on February 11,
2008. Under APB Opinion No. 25, the company recorded expense of $2 for these
options in 1998.
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 award and salary deferrals 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:
1998 1997 1996
------------------------------------------------------------------------------------
Net Shares Per-Share Net Shares Per-Share Net Shares Per-Share
Income (millions) Amount Income (millions) Amount Income (millions) Amount
- - -----------------------------------------------------------------------------------------------------------------------------------
Net income ................................... $1,339 $3,256 $2,607
Weighted-average common shares outstanding ... 653.7 655.0 652.8
Dividend equivalents
paid on Chevron stock units................ 3 2 3
Deferred awards held as Chevron stock units .. 1.2 1.3 1.4
- - -----------------------------------------------------------------------------------------------------------------------------------
BASIC EPS COMPUTATION ........................ $1,342 654.9 $ 2.05 $3,258 656.3 $ 4.97 $2,610 654.2 $ 3.99
Dilutive effects of stock options ............ 2.2 2.1 1.2
- - -----------------------------------------------------------------------------------------------------------------------------------
DILUTED EPS COMPUTATION ...................... $1,342 657.1 $ 2.04 $3,258 658.4 $ 4.95 $2,610 655.4 $ 3.98
===================================================================================================================================
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 1987 and 1991, respectively.
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. Caltex believes the underlying excise tax claim is
wrong, and therefore the claim for penalties and interest is wrong. The IRS
claim relates to crude oil sales to Japanese customers beginning in 1980. Caltex
is challenging the claim and fully expects to prevail. In early 1998, Caltex
provided an initial letter of credit for $2.33 billion to the IRS to pursue the
claim. The letter of credit was renewed in February 1999 for $2.52 billion.
Caltex's owners, Chevron and Texaco, guaranteed the letter of credit.
Settlement of open tax years 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, 1998, the company and its subsidiaries, as direct or indirect
guarantors, had contingent liabilities of $79 for notes of affiliated companies
and $106 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: 1999-$314; 2000-$280; 2001-$248; 2002-$231; 2003-$185;
2004 and after-$546. Total payments under the agreements were $201 in 1998, $243
in 1997 and $177 in 1996.
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 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 results of operations and financial position of certain equity affiliates
may be affected by its 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 and Venezuela. The
company's Caltex affiliates have significant operations in Indonesia, Korea,
Japan, Australia, Thailand, the Philippines, Singapore and South Africa. The
company's Tengizchevroil affiliate operates in Kazakhstan.
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, the United Kingdom
North Sea, Canada, Papua New Guinea, Venezuela, China 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, 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 (3) ............ 12 -- -- 12 -- -- 12
Unproved .............. 58 -- 14 72 -- -- 72
- - ------------------------------------------------------------------------------------------------------
Total property acquisition 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 (3) ............ 3 6 75 84 -- -- 84
Unproved .............. 101 -- 23 124 -- -- 124
- - ------------------------------------------------------------------------------------------------------
Total property acquisition 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
======================================================================================================
Year Ended December 31, 1996
Exploration
Wells ................. $ 357 $ 75 $ 126 $ 558 $ 1 $ -- $ 559
Geological and geophysical 16 37 70 123 8 -- 131
Rentals and other ..... 52 10 54 116 -- -- 116
- - ------------------------------------------------------------------------------------------------------
Total exploration ..... 425 122 250 797 9 -- 806
- - ------------------------------------------------------------------------------------------------------
Property acquisitions (2)
Proved (3) ............ 5 1 9 15 -- -- 15
Unproved .............. 62 2 43 107 -- -- 107
- - ------------------------------------------------------------------------------------------------------
Total property acquisition 67 3 52 122 -- -- 122
- - ------------------------------------------------------------------------------------------------------
Development ............. 603 465 594 1,662 123 50 1,835
- - ------------------------------------------------------------------------------------------------------
Total Costs Incurred .... $1,095 $ 590 $ 896 $2,581 $ 132 $ 50 $ 2,763
======================================================================================================
(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; unproved represents amounts for equipment and facilities
not associated with the production of proved reserves.
(3) 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, 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
========================================================================================================================
AT DECEMBER 31, 1996
Unproved properties .......................... $ 301 $ 59 $ 208 $ 568 $ -- $ 420 $ 988
Proved properties and related producing assets 16,284 2,753 4,267 23,304 1,018 524 24,846
Support equipment ............................ 525 158 254 937 548 200 1,685
Deferred exploratory wells ................... 157 43 94 294 -- -- 294
Other uncompleted projects ................... 446 678 1,520 2,644 293 97 3,034
- - ------------------------------------------------------------------------------------------------------------------------
GROSS CAPITALIZED COSTS .................... 17,713 3,691 6,343 27,747 1,859 1,241 30,847
- - ------------------------------------------------------------------------------------------------------------------------
Unproved properties valuation ................ 150 37 86 273 -- -- 273
Proved producing properties -
Depreciation and depletion ................... 11,422 1,240 2,259 14,921 557 34 15,512
Future abandonment and restoration ........... 996 272 160 1,428 37 4 1,469
Support equipment depreciation ............... 310 75 137 522 309 46 877
- - ------------------------------------------------------------------------------------------------------------------------
Accumulated provisions ..................... 12,878 1,624 2,642 17,144 903 84 18,131
- - ------------------------------------------------------------------------------------------------------------------------
NET CAPITALIZED COSTS ........................ $ 4,835 $ 2,067 $ 3,701 $10,603 $ 956 $ 1,157 $12,716
========================================================================================================================
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 1998, 1997 and 1996 are shown in the following table.
Net income from exploration and production activities as reported on page FS-9
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 - 9.
FS-33
TABLE III - RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES(1) - Cont
inued
Consolidated Companies Affiliated Companies
---------------------------------------- --------------------
Millions of dollars ....................... U.S. Africa Other Total CPI TCO Worldwide
- - -----------------------------------------------------------------------------------------------------------------------
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)(3) (79) (2,123)
Proved producing properties: depreciation,
depletion and abandonment provision .... (737) (256) (311) (1,304) (130)(3) (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
=======================================================================================================================
YEAR ENDED DECEMBER 31, 1996
Revenues from net production
Sales .................................. $ 1,695 $ 975 $ 984 $ 3,654 $ 45 $ 256 $ 3,955
Transfers .............................. 2,073 1,181 756 4,010 648 -- 4,658
- - -----------------------------------------------------------------------------------------------------------------------
Total .................................. 3,768 2,156 1,740 7,664 693 256 8,613
Production expenses ...................... (1,252) (242) (342) (1,836) (183)(3) (97) (2,116)
Proved producing properties: depreciation,
depletion and abandonment provision .... (678) (194) (296) (1,168) (110)(3) (34) (1,312)
Exploration expenses ..................... (172) (85) (198) (455) (8) -- (463)
Unproved properties valuation ............ (12) (6) (8) (26) -- -- (26)
Other income (expense)(2) ................ 46 (74) 112 84 8 (13) 79
- - -----------------------------------------------------------------------------------------------------------------------
Results before income taxes ............ 1,700 1,555 1,008 4,263 400 112 4,775
Income tax expense ....................... (600) (1,059) (471) (2,130) (212) (34) (2,376)
- - -----------------------------------------------------------------------------------------------------------------------
Results of producing operations .......... $ 1,100 $ 496 $ 537 $ 2,133 $ 188 $ 78 $ 2,399
=======================================================================================================================
(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, 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-9.
(3) Certain amounts were reclassified to conform to the 1998 presentation.
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, 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 .07 2.26 2.04 -- .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 -- .51 2.35
Average production costs, per barrel .......... 5.47 2.61 2.89 4.17 4.48(3) 2.78 4.22
============================================================================================================================
YEAR ENDED DECEMBER 31, 1996
Average sales prices
Liquids, per barrel ....................... $ 18.41 $ 20.41 $ 18.50 $ 19.12 $ 16.26 $ 12.27 $ 18.42
Natural gas, per thousand cubic feet ...... 2.29 -- 2.08 2.25 -- .57 2.21
Average production costs, per barrel .......... 5.40 2.29 3.31 4.16 4.30(3) 4.15 4.23
============================================================================================================================
Average sales price for liquids ($/Bbl)
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
December 1996 ............................... 21.07 23.54 19.45 21.54 19.06 13.64 20.68
============================================================================================================================
Average sales price for natural gas ($/MCF)
DECEMBER 1998 ............................... $ 2.23 $ -- $ 2.47 $ 2.29 $ -- $ .57 $ 2.26
December 1997 ............................... 2.25 -- 2.76 2.31 -- .63 2.26
December 1996 ............................... 3.73 -- 2.24 3.42 -- .81 3.36
============================================================================================================================
(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.
(3) Certain amounts were reclassified to conform to the 1998 presentation.
TABLE IV - RESERVE QUANTITIES INFORMATION
- - -----------------------------------------
The company's estimated net proved underground oil and gas reserves and
changes thereto for the years 1998, 1997 and 1996 are shown in the following
table. Proved reserves are estimated by the company's 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 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 contract, unless renewal is reasonably certain, or that may
result from extensions of currently proved areas, or from application of
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 April 1997, Chevron sold 10 percent of its interest in Tengizchevroil,
reducing its ownership to 45 percent.
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,
1998, had recorded 55 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 QUANTITIES INFORMATION - Continued
NET PROVED RESERVES OF CRUDE OIL, CONDENSATE NET PROVED RESERVES OF NATURAL GAS
AND NATURAL GAS LIQUIDS - Millions of barrels Billions of cubic feet
---------------------------------------------------- --------------------------------------------------
Consolidated Companies Affiliates Consolidated Companies Affiliates
--------------------------- ------------ World- ---------------------------- ---------- World-
U.S. Africa Other Total CPI TCO wide U.S. Africa Other Total CPI TCO wide
- - ------------------------------------------------------------------------------- --------------------------------------------------
RESERVES AT
JANUARY 1, 1996 ...... 1,187 969 538 2,694 562 1,087 4,343 5,532 84 2,794 8,410 155 1,505 10,070
Changes attributable to:
Revisions ............ (9) 73 24 88 (4) 69 153 (225) 209 489 473 (1) (18) 454
Improved recovery .... 38 22 22 82 60 - 142 20 - 16 36 1 - 37
Extensions
and discoveries ...... 63 74 6 143 2 - 145 676 - 7 683 15 - 698
Purchases(1) ......... 2 - - 2 - - 2 5 - 11 16 - - 16
Sales(2) ............. (7) - (32) (39) - - (39) (47) - (11) (58) - - (58)
Production ........... (125) (106) (76) (307) (54) (21) (382) (686) - (171) (857) (18) (25) (900)
- - ------------------------------------------------------------------------------- --------------------------------------------------
RESERVES AT
DECEMBER 31, 1996 .... 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
===================================================================================================================================
Developed reserves
- - -----------------------------------------------------------------------------------------------------------------------------------
At January 1, 1996 ... 1,061 596 371 2,028 457 406 2,891 4,929 84 1,726 6,739 140 562 7,441
At December 31, 1996 . 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
===================================================================================================================================
(1)Includes reserves acquired through property exchanges.
(2)Includes reserves disposed of through property exchanges.
(3)Mainly includes crude reserve 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
pre-tax net cash flows, less the tax basis of related assets. Discounted
future net cash flows are calculated using 10 percent midperiod discount
factors. This discounting requires a year-by-year estimate of when the future
expenditures will be incurred and when the 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, 1998
Future cash inflows from production . $ 19,810 $ 12,560 $ 13,010 $ 45,380 $ 6,020 $ 8,360 (1) $ 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
==================================================================================================================================
AT DECEMBER 31, 1996
Future cash inflows from production . $ 45,620 $ 24,220 $ 19,560 $ 89,400 $ 12,220 $ 16,040 $ 117,660
Future production and development costs (14,430) (3,840) (4,590) (22,860) (7,560) (5,330) (35,750)
Future income taxes ................. (11,170) (12,560) (5,290) (29,020) (2,210) (4,220) (35,450)
- - ----------------------------------------------------------------------------------------------------------------------------------
Undiscounted future net cash flows .. 20,020 7,820 9,680 37,520 2,450 6,490 46,460
10 percent midyear annual discount for
timing of estimated cash flows ...... (8,250) (2,700) (4,300) (15,250) (1,020) (5,070) (21,340)
- - ----------------------------------------------------------------------------------------------------------------------------------
Standardized Measure of Discounted
Future Net Cash Flows ............... $ 11,770 $ 5,120 $ 5,380 $ 22,270 $ 1,430 $ 1,420 $ 25,120
==================================================================================================================================
(1) Includes lower transportation expense and higher crude oil realizations
beginning in 2002 associated with the anticipated completion of the CPC
pipeline.
TABLE VI - CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS FROM PROVED RESERVES
Consolidated Companies Affiliated Companies Worldwide
---------------------------- ---------------------------- ----------------------------
Millions of dollars 1998 1997 1996 1998 1997 1996 1998 1997 1996
- - ---------------------------------------------------------------------------------------------------------------------------------
Present Value at January 1 ............. $ 13,110 $ 22,270 $ 13,830 $ 1,890 $ 2,850 $ 2,520 $ 15,000 $ 25,120 $ 16,350
- - ---------------------------------------------------------------------------------------------------------------------------------
Sales and transfers of oil and gas
produced, net of production costs ...... (3,294) (5,493) (5,828) (429) (684) (669) (3,723) (6,128) (6,467)
Development costs incurred ............. 1,652 1,908 1,662 276 311 173 1,928 2,219 1,835
Purchases of reserves .................. 208 173 28 -- -- -- 208 173 28
Sales of reserves ...................... (347) (238) (353) -- (140) -- (347) (378) (353)
Extensions, discoveries and improved
recovery, less related costs ........... 813 2,161 3,745 49 104 316 862 2,265 4,061
Revisions of previous quantity estimates 262 535 969 280 980 59 542 1,515 1,028
Net changes in prices, development
and production costs ................... (11,321) (20,440) 13,495 (2,159) (3,521) 751 (13,480) (24,010) 14,216
Accretion of discount .................. 2,096 3,673 2,236 289 516 418 2,385 4,189 2,654
Net change in income tax ............... 5,281 8,561 (7,514) 614 1,474 (718) 5,895 10,035 (8,232)
- - ---------------------------------------------------------------------------------------------------------------------------------
Net change for the year ................ (4,650) (9,160) 8,440 (1,080) (960) 330 (5,730) (10,120) 8,770
- - ---------------------------------------------------------------------------------------------------------------------------------
Present Value at December 31 ........... $ 8,460 $ 13,110 $ 22,270 $ 810 $ 1,890 $ 2,850 $ 9,270 $ 15,000 $ 25,120
=================================================================================================================================
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 1998 1997 1996 1995 1994
- - ----------------------------------------------------------------------------------------------------------------------------
CONSOLIDATED STATEMENT OF INCOME DATA
REVENUES
Sales and other operating revenues
Refined products ............................................. $ 11,461 $ 15,586 $ 15,785 $ 13,471 $ 14,328
Crude oil .................................................... 7,781 11,296 12,397 9,376 8,249
Natural gas .................................................. 2,104 2,568 3,299 2,019 2,138
Natural gas liquids .......................................... 322 553 1,167 1,285 1,180
Other petroleum .............................................. 1,063 1,118 1,184 1,144 944
Chemicals .................................................... 3,054 3,520 3,422 3,758 3,065
Coal and other minerals ...................................... 399 359 340 358 416
Excise taxes ................................................. 3,756 5,587 5,202 4,988 4,790
Corporate and other .......................................... 3 9 (14) (89) 20
- - ----------------------------------------------------------------------------------------------------------------------------
Total sales and other operating revenues ...................... 29,943 40,596 42,782 36,310 35,130
Income from equity affiliates ................................. 228 688 767 553 440
Other income .................................................. 386 679 344 219 284
- - ----------------------------------------------------------------------------------------------------------------------------
TOTAL REVENUES ................................................ 30,557 41,963 43,893 37,082 35,854
COSTS, OTHER DEDUCTIONS AND INCOME TAXES ...................... 29,218 38,707 41,286 36,152 34,161
INCOME BEFORE CUMULATIVE EFFECT
OF CHANGES IN ACCOUNTING PRINCIPLES .......................... $ 1,339 $ 3,256 $ 2,607 $ 930 $ 1,693
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES ......... - - - - -
- - ----------------------------------------------------------------------------------------------------------------------------
NET INCOME .................................................... $ 1,339 $ 3,256 $ 2,607 $ 930 $ 1,693
============================================================================================================================
PER SHARE OF COMMON STOCK:
INCOME BEFORE CUMULATIVE EFFECT
OF CHANGES IN ACCOUNTING PRINCIPLES - BASIC .................. $ 2.05 $ 4.97 $ 3.99 $ 1.43 $ 2.60
- DILUTED ................ $ 2.04 $ 4.95 $ 3.98 $ 1.43 $ 2.59
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES ......... - - - - -
- - ----------------------------------------------------------------------------------------------------------------------------
NET INCOME PER SHARE OF COMMON STOCK - BASIC .................. $ 2.05 $ 4.97 $ 3.99 $ 1.43 $ 2.60
- DILUTED ................ $ 2.04 $ 4.95 $ 3.98 $ 1.43 $ 2.59
============================================================================================================================
CASH DIVIDENDS PER SHARE ...................................... $ 2.44 $ 2.28 $ 2.08 $ 1.925 $ 1.85
============================================================================================================================
CONSOLIDATED BALANCE SHEET DATA (AT DECEMBER 31)
Current assets ................................................ $ 6,297 $ 7,006 $ 7,942 $ 7,867 7,591
Properties, plant and equipment (net) ......................... 23,729 22,671 21,496 21,696 22,173
Total assets .................................................. 36,540 35,473 34,854 34,330 34,407
Short-term debt ............................................... 3,165 1,637 2,706 3,806 4,014
Other current liabilities ..................................... 4,001 5,309 6,201 5,639 5,378
Long-term debt and capital lease obligations .................. 4,393 4,431 3,988 4,521 4,128
Stockholders equity ........................................... 17,034 17,472 15,623 14,355 14,596
Per share ................................................... $ 26.08 $ 26.64 $ 23.92 $ 22.01 $ 22.40
============================================================================================================================
SELECTED DATA
Return on average stockholders equity ......................... 7.8% 19.7% 17.4% 6.4% 11.8%
Return on average capital employed ............................ 6.7% 15.0% 12.7% 5.3% 8.7%
Total debt/total debt plus equity ............................. 30.7% 25.8% 30.0% 36.7% 35.8%
Capital and exploratory expenditures (2) ...................... $ 5,314 $ 5,541 $ 4,840 $ 4,800 $ 4,819
Common stock price - High ................................ $90 3/16 $89 3/16 $68 3/8 $53 5/8 $49 3/16
- Low ................................. $67 3/4 $61 3/4 $51 $43 3/8 $39 7/8
- Year-End ............................ $82 15/16 $77 $65 $52 3/8 $44 5/8
Common shares outstanding at year-end (in thousands) .......... 653,026 655,931 653,086 652,327 651,751
Weighted-average shares outstanding for the year (in thousands) 653,667 654,991 652,769 652,084 651,672
Number of employees at year-end (3) 39,191 39,362 40,820 43,019 45,758
============================================================================================================================
(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. $ 994 $ 1,174 $ 983 $ 912 $ 846
(3) Includes service station personnel.
FS-38
CALTEX GROUP OF COMPANIES
COMBINED FINANCIAL STATEMENTS
December 31, 1998
C-1
CALTEX GROUP OF COMPANIES
COMBINED FINANCIAL STATEMENTS
DECEMBER 31, 1998
INDEX
Page
General Information C-3 to C-8
Independent Auditors' Report C-9
Combined Balance Sheet C-11
Combined Statement of Income C-12
Combined Statement of Comprehensive Income C-12
Combined Statement of Stockholders' Equity C-13
Combined Statement of Cash Flows C-14
Notes to Combined Financial Statements C-15 to C-27
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:
* Caltex Corporation (formerly Caltex Petroleum Corporation), a company
incorporated in Delaware that, through its many subsidiaries and
affiliates, conducts refining, transporting, trading, and marketing
activities in the Eastern Hemisphere;
* P. T. Caltex Pacific Indonesia, an exploration and production company
incorporated and operating in Indonesia; and,
* American Overseas Petroleum Limited, a company incorporated in the
Bahamas, that, through its subsidiary, provides services for and manages
certain exploration and production operations in Indonesia in which
Chevron and Texaco have interests, but not necessarily jointly.
A brief description of each company's operations and other items follows:
Caltex Corporation (Caltex)
- - --------------------------
Through its subsidiaries and affiliates, Caltex operates in approximately 60
countries, principally in Africa, Asia, the Middle East, New Zealand and
Australia. Caltex is involved in all aspects of the downstream business:
refining, distribution, shipping, storage, marketing, supply and trading
operations. At year-end 1998, Caltex had over 7,900 employees, of which
approximately 2% were located in the United States.
The majority of refining and certain marketing operations are conducted through
joint ventures. Caltex has equity interests in 13 refineries with equity
refining capacity of approximately 978,000 barrels per day. It continues to
improve its refineries with investments designed to provide higher yields and
meet environmental regulations. Additionally, it has interests in two lubricant
refineries, six asphalt plants, 17 lubricant blending plants and more than 500
ocean terminals and depots. Caltex also has an interest in a fleet of vessels
and owns or has equity interests in numerous pipelines. Its sales of crude oil
and petroleum products were in excess of 1.5 million barrels per day in 1998.
Caltex conducts international crude oil and petroleum product logistics and
trading operations from a subsidiary in Singapore, and is also active in the
petrochemical business, particularly in Japan and Korea.
Marketing
Caltex and its affiliates maintain a strong marketing presence through a network
of 8,000 retail outlets, of which 4,700 are branded as Caltex. It also operates
425 Star Mart convenience stores, many of which anchor high-volume station
locations. Many stations include new ancillary revenue centers such as
quick-service restaurants, auto lube bays and brushless car washes. A
significant portion of the $1.8 billion that Caltex plans to invest over the
next three years is targeted to stimulate retail growth and continue the
roll-out of its new corporate and retail image introduced in 1996, focussing on
preferred marketing areas where the expenditures will provide the greatest
benefit to the business. Under-performing stations with poor prospects for
improvement are being eliminated.
During 1998, in response to major changes in the petroleum business, increased
competition, and partly due to the challenges created by the currency and
economic crisis in the Asia Pacific region, Caltex announced a change in
organizational structure from geographic to one modeled along functional
business lines, namely: marketing, refining, lubricants, trading, aviation, new
business development and business support. At the same time that it is
emphasizing managing its costs and improving its capital investment returns,
Caltex will use this functional focus to build or rebuild brand strength,
increase emphasis on convenience retailing, and maximize emerging business
opportunities. The new structure will position Caltex to seize opportunities
that will provide higher returns and strong long-term growth, focus on its
mission and respond to market developments more quickly, as well as place it in
a better position to serve customers, partners and suppliers more effectively.
The functional management structure is effective January 1, 1999.
C-3
CALTEX GROUP OF COMPANIES
GENERAL INFORMATION
Refining
Refining margins in 1998 were at their lowest level in more than ten years due
to worldwide oversupply of capacity, partly as a result of the economic
disruption in many of the Asian economies. By focusing on full utilization of
assets, cost reductions, cost-effective investment and initiatives to improve
efficiency and maintain the integrity of the refining assets, the operating
performance of the Group's refineries has continued to improve, mitigating to
some extent the effect of low margins.
During 1997, Caltex's 64% owned Thailand affiliate, Star Petroleum Refining
Company, Ltd. (SPRC), and Rayong Refining Company (RRC), an affiliate of the
Royal Dutch Petroleum Company, entered into a Memorandum of Understanding to
combine the operations of the two nearby refineries in order to achieve
significant economic benefits through increased efficiency and cost reduction.
During 1998, SPRC and RRC evaluated various proposed structures and synergies,
and conducted discussions with lenders to ensure proper approvals were obtained.
Tentative agreement has been reached to form a new entity, Alliance Refining
Company (ARC), which will be owned 32% each by Caltex and Shell and 36% by the
Petroleum Authority of Thailand (PTT) - a government entity. ARC will operate
the refineries and be responsible for ongoing maintenance and new construction.
Significant economic benefits are expected from this arrangement. Pending lender
and Thai cabinet approvals, binding agreements are expected to be signed and
operations commenced by ARC in the first half of 1999.
Over the period 1992-1996, SPRC capitalized certain start-up costs, primarily
organizational and training, related to refinery construction. These costs were
considered part of the effort required to prepare the refinery for operations.
With the issuance in 1998 of the American Institute of Certified Public
Accountants Statement of Position 98-5 - "Reporting on the Costs of Start-up
Activities", these costs would be accounted for as period expenses. The Group
has 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 these costs.
Corporate
Effective January 1, 1999, Caltex eliminated "Petroleum" from its name to become
Caltex Corporation. The change reflects the broader scope of activities it is
pursuing, particularly the rapidly growing Star Mart convenience stores and
other related services provided to its customers.
Concurrently, Caltex announced the relocation of its corporate senior leadership
team from Dallas, Texas, to Singapore. The leadership team will reside within
the primary operational area and be closer to its customers to achieve a more
timely and effective process of corporate governance. The relocation will be
completed during the first half of 1999.
Caltex recorded a charge to income of $86 million in 1998 for restructuring and
other related reorganization costs including special voluntary and involuntary
severance benefits (see Note 13 of Notes to Combined Financial Statements).
P. T. Caltex Pacific Indonesia (CPI)
- - -----------------------------------
CPI holds a Production Sharing Contract 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. 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 1998 was over 760,000 barrels per
day. CPI entitlements are sold to its stockholders, who use them in their
systems or sell them to third parties. At year-end 1998, CPI had approximately
5,900 employees, all located in Indonesia.
C-4
CALTEX GROUP OF COMPANIES
GENERAL INFORMATION
American Overseas Petroleum Limited (AOPL)
- - -----------------------------------------
In addition to providing services to CPI, AOPL, through its subsidiary Amoseas
Indonesia Inc., manages geothermal and power generation projects for Texaco's
and Chevron's interests in Indonesia. At year-end, AOPL had approximately 279
employees, of which 6% were located in the United States.
Economic Overview and Outlook
- - -----------------------------
During the second half of 1997, many of the countries in the Pacific Rim
experienced major devaluations in their currencies compared to the U.S. dollar,
resulting in economic slowdowns throughout the area during 1998. The weak
economic conditions have negatively affected oil consumption. Although most of
the region is still experiencing economic contraction, the currencies themselves
have strengthened during 1998. There are some signs emerging of a general
stabilization in the economies of the region and there are indications of
economic recovery in some countries. The Group has significant operations
(either subsidiary or affiliate) in many of the affected countries (Korea,
Philippines, Singapore, Thailand, Malaysia, and Indonesia) which are material to
the Group's net income, cash flows and capital.
Environmental Activities
- - ------------------------
The Group's activities are subject to various environmental, health and safety
regulations in each of the countries in which it operates. Such regulations vary
significantly in scope, standards and enforcement. The Group's policy is to
comply with all applicable environmental, health, and safety laws and
regulations as well as its own internal policies. The Group has an active
program to ensure that its environmental standards are maintained, which
includes closely monitoring applicable statutory and regulatory requirements, as
well as enforcement policies in each of the countries in which it operates, and
conducting periodic environmental compliance audits.
The environmental guidelines and definitions promulgated by the American
Petroleum Institute provide the basis for reporting the Group's expenditures.
For the year ended December 31, 1998, the Group, including its equity share of
affiliates, incurred total costs of approximately $138 million, consisting of
capital costs of $70 million and nonremediation related operating expenses of
$68 million. The major component of the Group's expenditures is for the
prevention of air and water pollution. As of December 31, 1998, the Group,
including its equity share of affiliates, had accrued $135 million for various
known remediation activities, including $114 million relating to the future cost
of restoring and abandoning existing oil and gas properties.
While the Group 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. However, the
Group believes that future environmental expenditures will not materially affect
its financial position or liquidity.
Year 2000 Compliance
- - --------------------
The Problem
The year 2000 problem (Y2K) relates to the inability of some computer systems
and other equipment ("systems") with embedded microchip technology to correctly
interpret and process date-sensitive data at certain key dates before, during or
after the year 2000. This could result in systems failures or miscalculations,
which could cause business disruptions. Due to the widespread nature of this
problem, the Group could be affected not only by failures of its own systems,
but also by failures of the systems of its customers, suppliers, utilities and
government entities that provide it with essential services.
C-5
CALTEX GROUP OF COMPANIES
GENERAL INFORMATION
Our state of readiness
Individual operating location (including major affiliates) Y2K teams and a
corporate level team were established in 1997 and early 1998. The corporate team
monitors and supports the individual locations and also evaluates progress
against the milestones outlined below. Y2K progress reports are presented
regularly to the Group management and the Stockholders.
A common rigorous process has been employed to identify, test, and remediate
systems affected by the Y2K problem and to achieve Y2K readiness. The process
consists of the following (in many cases overlapping) steps:
(1) Inventory - a list all systems and embedded microchip technology that may
have date-sensitive components - computer hardware and software, as well as
other embedded microchip systems.
(2) Business risk assessment - an assessment to determine the importance of
each system to the business - including financial, operational,
environmental and safety impact.
(3) Y2K risk assessment - a determination of whether or not systems or system
components are Y2K compliant, firstly by obtaining vendor compliance
statements for all systems, then evaluating more detailed vendor test
results (for medium risk systems), and conducting our own on site
end-to-end tests (for high risk systems).
(4) Remediation and testing - remediation, testing and comprehensive
contingency plan preparation for high-risk systems.
The Group has essentially completed the inventory and business risk assessments
in its major operating areas. Most of the Y2K risk assessments are also
complete. Approximately 25-30% of the remediation and on site end-to-end testing
of high-risk systems has been performed as at February 1999, and it is estimated
that this will be completed between June - September 1999. This includes major
internal business support systems and various equipment (process control etc)
with embedded microchips. It also includes the readiness of critical business
chain partners (third party suppliers, and customers). High-risk systems found
to be Y2K non-compliant are being corrected primarily by software/hardware
upgrades and/or implementation of new systems. The Group expects the remediation
of high risk business systems will be essentially complete by the end of 1999,
however, remediation of lower risk systems may continue into the year 2000 and
beyond.
The determination of Y2K readiness of critical business chain partners has
proven to be the most challenging aspect of the Y2K program. While system
suppliers have been responsive to requests for compliance information, obtaining
responses from business chain partners on their state of readiness has been more
difficult. The Group representatives are meeting with those business chain
partners that have been identified as important to the business to determine
their state of readiness. If any critical business chain partners do not have
effective programs in place, additional contingency plans will be put in place
as necessary before the end of 1999.
Costs
The Group is using both dedicated internal and external resources in its Y2K
initiative. The total cost to address its Y2K issues is estimated at
approximately $57 million, of which approximately $15 million had been spent by
the end of 1998. These figures include work being undertaken to make compliant
some older financial and accounting systems, but do not include costs incurred
on system implementations or modifications where the primary reasons for such
are other than Y2K compliance. The Y2K project costs also include the corporate
project team, external contractors and consultants. Other internal costs such as
salaries, travel expenses, and other out of pocket costs of the operating
company teams are not included in this total.
C-6
CALTEX GROUP OF COMPANIES
GENERAL INFORMATION
Contingency Plans
Due to both the uncertain nature of the Y2K problem, and its inflexible/absolute
deadline, a strong emphasis has been placed on contingency planning and
preparation. Generally, in the normal course of business, the Group has
developed contingency plans to respond to equipment failures, emergencies and
business interruptions. However the Y2K issue increases the complexity of such
planning. Therefore, the Group is enhancing existing plans where possible, and
developing plans where necessary, specifically designed to mitigate the
financial and other impacts of potential high risk system Y2K related failures
and to allow it to carry on business despite possible failures. The Group
expects to complete and test, where appropriate, its contingency plans, with
particular emphasis on any unremediated (or remediated but untested) high risk
systems prior to the year 2000.
Risks
Certain risks related to the Y2K problem that could have a material adverse
effect on the Group's results of operations, liquidity and financial condition
include, but are not limited to, the failure to identify and remediate
significant Y2K problems; the failure to successfully implement contingency
plans in a timely manner; and failures by customers, suppliers, utilities and
government entities that provide essential services to correct their Y2K
problems. The dispersion of the Group's downstream operations in over 60
countries is expected to mitigate the risk of any potential widespread
disruption to its operations. The Group's upstream operations are located in
Indonesia, primarily on the islands of Sumatra and Java. Due to the isolated and
self sufficient nature of these operations, the potential risk of widespread
disruption to its exploration and production operations is also well mitigated.
The Group does not expect any unusual risks to public safety or the environment
resulting from potential Y2K related incidents at its facilities and operations.
The Group believes that the impact of any Y2K related failure in any of its
systems will most likely be localized and limited to specific facilities and
operations. Interruptions caused by such a failure could delay the Group in
being able to explore for, produce or transport hydrocarbons or steam, or
manufacture and deliver refined products to its customers for a short period.
The Group would not expect this to have a significant impact on its ability to
pursue its primary business objectives. While not expected, a worst case
scenario involving failure to address multiple high risk Y2K issues, including
failures to implement contingency plans in a timely manner, could materially
affect the Group's results of operations or liquidity in any one period. The
Group is currently unable to predict the aggregate financial or other
consequence of such potential interruptions.
The foregoing disclosure is based on the Group's current expectation, estimates
and projections, which could ultimately prove to be inaccurate. Because of
uncertainties, the actual effects of Y2K issues on the Group may be different
from its current assessment.
Supplemental Market Risk Disclosures
- - ------------------------------------
The Group uses derivative financial instruments for hedging 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 data relating to derivatives and applicable accounting
policies.
C-7
CALTEX GROUP OF COMPANIES
GENERAL INFORMATION
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 $2.0 billion and $1.9 billion,
before the effects of related net interest rate swaps of $0.5 billion and $0.4
billion, at December 31, 1998 and 1997, respectively). The Group seeks to
balance the benefit of lower cost variable rate debt, having inherent increased
risk, with more expensive, but less risky 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, 1998 and 1997, a hypothetical change in the interest
rates of 2% would change interest expense by approximately $30 million each
year.
Crude oil and petroleum product hedging
The Group hedges a portion of the market risks associated with its crude oil and
petroleum product purchases and sales. The Group uses established petroleum
futures exchanges, as well as "over-the-counter" hedge instruments, including
futures, options, swaps, and other derivative products which reduce the Group's
exposure to price volatility in the physical markets.
As a sensitivity, a hypothetical 10% change in crude oil and petroleum product
prices would not result in a material loss on the outstanding derivatives at the
end of 1998 or 1997, in terms of the Group's financial position, results of
operations or liquidity.
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 $370 million at December 31, 1998
and $417 million at December 31, 1997, 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 1998 or 1997.
Hedging Activities - New Accounting Standards
- - ---------------------------------------------
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 in 1998 and is effective for the Group beginning
January 1, 2000. SFAS No. 133 requires companies to record derivatives on the
balance sheet as assets or liabilities, measured at fair value. Changes in the
fair value of derivatives are to be recorded each period in current earnings or
other comprehensive income, depending on whether a derivative is designated as
part of a hedge transaction and the type of exposure being hedged. The Group
believes the adoption of this standard will not have a material effect on its
results of operations or financial position.
Emerging Issues Task Force (EITF) 98-10, "Accounting for Energy Trading and Risk
Management Activities", is effective for 1999, and covers contracts related to
the purchase and sale of energy commodities prior to the effective date of SFAS
No. 133. This EITF consensus requires that energy contracts related to trading
activities should be marked to market with the gains and losses included
currently in net income. The Group believes adoption of this EITF consensus will
not have a material effect on its results of operations or financial condition.
C-8
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, 1998 and 1997, 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, 1998. 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 generally accepted auditing
standards. 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, 1998 and 1997 and the results of its operations and
its cash flows for each of the years in the three-year period ended December 31,
1998, in conformity with generally accepted accounting principles.
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 LLP
Dallas, Texas
February 8, 1999
C-9
CALTEX GROUP OF COMPANIES
COMBINED BALANCE SHEET
ASSETS
As of December 31,
----------------------
(Millions of dollars)
1998 1997
------- -------
Current assets:
Cash and cash equivalents, including
time deposits of $17 in 1998 and $69 in 1997 $ 178 $ 282
Marketable securities 106 82
Accounts and notes receivable, less allowance
for doubtful accounts of $31 in 1998 and $21 in 1997:
Trade 629 808
Affiliates 256 368
Other 194 360
------- -------
1,079 1,536
Inventories:
Crude oil 167 127
Petroleum products 418 437
Materials and supplies 26 28
------- -------
611 592
Deferred income taxes - 29
------- -------
Total current assets 1,974 2,521
Investments and advances:
Equity in affiliates 2,254 2,035
Miscellaneous investments and long-term receivables,
less allowance of $21 in 1998 and $13 in 1997 109 116
------- -------
Total investments and advances 2,363 2,151
Property, plant, and equipment, at cost:
Producing 4,386 4,058
Refining 1,319 1,272
Marketing 3,125 2,892
Other 15 13
------- -------
8,845 8,235
Accumulated depreciation, depletion
and amortization (3,747) (3,393)
------- -------
Net property, plant and equipment 5,098 4,842
Prepaid and deferred charges 223 200
------- -------
Total assets $ 9,658 $ 9,714
======= =======
See accompanying notes to combined financial statements.
C-10
CALTEX GROUP OF COMPANIES
COMBINED BALANCE SHEET
LIABILITIES AND STOCKHOLDERS' EQUITY
As of December 31,
----------------------
(Millions of dollars)
1998 1997
------ -------
Current liabilities:
Short-term debt $ 1,475 $ 1,554
Accounts payable:
Trade and other 1,005 1,053
Stockholders 28 102
Affiliates 39 60
------- -------
1,072 1,215
Accrued liabilities 181 138
Deferred income taxes 25 -
Estimated income taxes 86 84
------- -------
Total current liabilities 2,839 2,991
Long-term debt 930 770
Employee benefit plans 122 106
Deferred credits and other noncurrent liabilities 1,130 1,050
Deferred income taxes 208 190
Minority interest in subsidiary companies 31 15
------- -------
Total 5,260 5,122
Stockholders' equity:
Common stock 355 355
Capital in excess of par value 2 2
Retained earnings 4,151 4,342
Accumulated other comprehensive loss (110) (107)
------- -------
Total stockholders' equity 4,398 4,592
------- -------
Total liabilities and stockholders' equity $ 9,658 $ 9,714
======= =======
See accompanying notes to combined financial statements.
C-11
CALTEX GROUP OF COMPANIES
COMBINED STATEMENT OF INCOME
Year ended December 31,
---------------------------------
(Millions of dollars)
1998 1997 1996
--------- --------- ---------
Revenues:
Sales and other operating revenues(1) $ 16,969 $ 17,920 $ 16,895
Gain on sale of investment in affiliate - - 1,132
Income in equity affiliates 108 390 51
Dividends, interest and other income 97 47 88
------- ------- -------
Total revenues 17,174 18,357 18,166
Costs and deductions:
Cost of sales and operating expenses(2) 15,210 15,909 14,774
Selling, general and administrative expenses 676 580 532
Depreciation, depletion and amortization 431 421 407
Maintenance and repairs 147 143 134
Foreign exchange - net 16 (55) 6
Interest expense 172 146 140
Minority interest 3 3 (2)
------- ------- -------
Total costs and deductions 16,655 17,147 15,991
------- ------- -------
Income before income taxes 519 1,210 2,175
Provision for income taxes 326 364 982
------- ------- -------
Income before cumulative effect
of accounting change 193 846 1,193
Cumulative effect of accounting
change (no tax benefit) (50) - -
------- ------- -------
Net income $ 143 $ 846 $ 1,193
======= ======= =======
(1) Includes sales to:
Stockholders $ 1,437 $ 1,695 $ 1,711
Affiliates 2,253 3,018 2,841
(2) Includes purchases from:
Stockholders $ 1,337 $ 2,174 $ 2,634
Affiliates 1,485 1,813 1,297
CALTEX GROUP OF COMPANIES
COMBINED STATEMENT OF COMPREHENSIVE INCOME
Year ended December 31,
---------------------------------
(Millions of dollars)
1998 1997 1996
--------- --------- ---------
Net income $ 143 $ 846 $ 1,193
Other comprehensive income:
Currency translation adjustments:
Change during the year (10) (84) (146)
Reclassification to net income for
sale of investment in affiliate - - (240)
Unrealized gains/(losses) on investments:
Change during the year 8 (23) (40)
Reclassification of gains included
in net income - (3) (35)
Related income tax (expense) benefit (1) 14 35
------- ------- -------
Total other comprehensive loss (3) (96) (426)
------- ------- -------
Comprehensive income $ 140 $ 750 $ 767
======= ======= =======
See accompanying notes to combined financial statements.
C-12
CALTEX GROUP OF COMPANIES
COMBINED STATEMENT OF STOCKHOLDERS' EQUITY
Year ended December 31,
-----------------------------
(Millions of dollars)
1998 1997 1996
------- ------- -------
Common stock and capital in excess of par value $ 357 $ 357 $ 357
======= ======= =======
Retained earnings:
- - -----------------
Balance at beginning of year $ 4,342 $ 3,910 $ 4,187
Net income 143 846 1,193
Cash dividends (334) (414) (1,470)
------- ------- -------
Balance at end of year $ 4,151 $ 4,342 $ 3,910
======= ======= =======
Accumulated other comprehensive loss:
- - ------------------------------------
Cumulative translation adjustments:
Balance at beginning of year $ (120) $ (36) $ 350
Change during the year (10) (84) (146)
Reclassification to net income for sale
of investment in affiliate - - (240)
------- ------- -------
Balance at end of year $ (130) $ (120) $ (36)
======= ======= =======
Unrealized holding gain on investments, net of tax:
- - --------------------------------------------------
Balance at beginning of year $ 13 $ 25 $ 65
Change during the year 7 (11) (23)
Reclassification of gains included in net income - (1) (17)
------- ------- -------
Balance at end of year $ 20 $ 13 $ 25
======= ======= =======
Accumulated other comprehensive loss - end of year $ (110) $ (107) $ (11)
- - -------------------------------------------------- ======= ======= =======
Total stockholders' equity - end of year $ 4,398 $ 4,592 $ 4,256
======= ======= =======
See accompanying notes to combined financial statements.
C-13
CALTEX GROUP OF COMPANIES
COMBINED STATEMENT OF CASH FLOWS
Year ended December 31,
------------------------------
(Millions of dollars)
1998 1997 1996
Operating activities:
Net income $ 143 $ 846 $ 1,193
Reconciliation to net cash provided by operating activities:
Depreciation, depletion and amortization 431 421 407
Dividends (less) more than income in equity affiliates (8) (347) 38
Net losses on asset disposals/writedowns 50 16 10
Deferred income taxes 92 (51) 36
Prepaid charges and deferred credits 59 103 38
Changes in operating working capital 316 (150) (7)
Gain on sale of investment in affiliate - - (1,132)
Other 35 (13) (12)
------- ------- -------
Net cash provided by operating activities 1,118 825 571
Investing activities:
Capital expenditures (761) (905) (741)
Investments in and advances to affiliates (211) (10) (30)
Purchase of investment instruments (114) (39) (56)
Sale of investment instruments 90 73 1
Proceeds from sale of investment in affiliate - - 1,984
Proceeds from asset sales 9 156 95
------- ------- -------
Net cash (used for) provided by investing activities (987) (725) 1,253
Financing activities:
Debt with terms in excess of three months :
Borrowings 849 845 1,112
Repayments (701) (628) (1,351)
Net (decrease) increase in other debt (22) 323 (53)
Funding provided by minority interest 17 - -
Dividends paid, including minority interest (334) (414) (1,490)
------- ------- -------
Net cash (used for) provided by financing activities (191) 126 (1,782)
Effect of exchange rate changes on cash and cash equivalents (44) (150) (2)
------- ------- -------
Cash and cash equivalents:
Net change during the year (104) 76 40
Beginning of year balance 282 206 166
------- ------- -------
End of year balance $ 178 $ 282 $ 206
======= ======= =======
See accompanying notes to combined financial statements.
C-14
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.
Translation of foreign currencies
The U.S. dollar is the functional currency for all principal subsidiary and
affiliate operations. 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 inventories are stated at cost, primarily
determined using the last-in, first-out (LIFO) method. Costs 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. Impairment amounts are recorded as incremental
depreciation expense in the period when the event occurred.
C-15
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.
Comprehensive Income
On January 1, 1998, the Group adopted SFAS No. 130, "Reporting Comprehensive
Income." SFAS No. 130 established standards for reporting and presentation of
comprehensive income and its components. Comprehensive income consists of net
income, currency translation adjustments and unrealized gains/(losses) on
investments and is presented in a separate statement. SFAS No. 130 requires only
additional disclosure, and does not affect the Group's financial position or
results of operations.
Derivative financial instruments
The Group uses various derivative financial instruments for hedging purposes.
These instruments principally 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 contracts that do not qualify as hedges are recognized
currently in other income.
Accounting for contingencies
Certain conditions may exist as of the date financial statements are issued
which may result in a loss to the Group, but which will only be resolved when
one or more future events occur or fail to occur. Assessing contingencies
necessarily involves an exercise of judgment. In assessing loss contingencies
related to legal proceedings that are pending against the Group or unasserted
claims that may result in such proceedings, the Group evaluates the perceived
merits of any legal proceedings or unasserted claims as well as the perceived
merits of the amount of relief sought or expected to be sought therein.
If the assessment of a contingency indicates that it is probable that a material
liability had been incurred and the amount of the loss can be estimated, then
the estimated liability is accrued in the Group's financial statements. If the
assessment indicates that a potentially material liability is not probable, but
is reasonably possible, or is probable but cannot be estimated, then the nature
of the contingent liability, together with an estimate of the range of possible
loss, if determinable, is disclosed.
Loss contingencies considered remote are generally not disclosed unless they
involve guarantees, in which case the nature and amount of the guarantee would
be disclosed. However, in some instances in which disclosure is not otherwise
required, the Group may disclose contingent liabilities of an unusual nature
which, in the judgment of management and its legal counsel, may be of interest
to Stockholders or others.
Environmental matters
The Group's environmental policies encompass the existing laws in each country
in which the Group operates, and the Group's own internal standards.
Expenditures that create future benefits or contribute to future revenue
generation are capitalized. Future remediation costs are accrued based on
estimates of known environmental exposure even if uncertainties exist about the
ultimate cost of the remediation. Such accruals are based on the best available
undiscounted estimates using data primarily developed by third party experts.
Costs of environmental compliance for past and ongoing operations, including
maintenance and monitoring, are expensed as incurred. Recoveries from third
parties are recorded as assets when realizable.
C-16
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
Note 1 - Summary of significant accounting policies - continued
- - -----------------------------------------------------------------
Revenue recognition In general, revenue is recognized for crude oil, natural gas
and refined product sales when title passes as specified in the sales contract.
Reclassifications Certain reclassifications have been made to prior year amounts
to conform to the 1998 presentation.
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, 1998 approximated its current
cost. At December 31, 1997, the excess of current cost over the reported value
of inventory maintained on the LIFO basis was approximately $28 million. Certain
inventories were recorded at market, which was lower than the LIFO carrying
value. Adjustments to market reduced earnings $18 million in 1998 and $36
million in 1997. Earnings increased $29 million in 1996 due to recovery of
market values over previous years' write-downs.
During the periods presented, inventory quantities valued on the LIFO basis were
reduced at certain locations. Inventory reductions 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), and increased net
income $4 million in 1996.
Trading inventories are recorded on a mark-to-market basis due to their highly
transitory nature. At December 31, 1998 the value of these inventories was
approximately $3 million, which approximated cost.
Note 4 - Equity in affiliates
- - -------------------------------
Investments in affiliates at equity include the following:
As of December 31,
------------------------
(Millions of Dollars)
Equity % 1998 1997
-------- -------- -------
Caltex Australia Limited 50% $ 324 $ 300
Koa Oil Company, Limited 50% 298 353
LG-Caltex Oil Corporation 50% 1,170 999
Star Petroleum Refining Company, Ltd. 64% 304 228
All other Various 158 155
-------- -------
$ 2,254 $ 2,035
======== =======
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.
Effective April 1, 1996, the Group sold its 50% investment in Nippon Petroleum
Refining Company, Limited for approximately $2 billion in cash. The Group's net
income in 1996 includes a net after-tax gain of approximately $620 million
related to this sale. The combined statement of income includes Group product
sales to the purchaser of approximately $0.5 billion in the first quarter of
1996.
C-17
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 Thailand governmental entity. 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 by the year 2001; however,
it is likely that this 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 dollars):
100% Equity Share
--------------------- ----------------------
1998 1997 1998 1997
-------- -------- -------- ---------
Current assets $ 3,689 $ 4,768 $ 1,855 $ 2,400
Other assets 7,689 7,345 4,004 3,867
Current liabilities 3,547 4,740 1,795 2,411
Other liabilities 3,505 3,483 1,866 1,879
-------- -------- -------- --------
Net worth $ 4,326 $ 3,890 $ 2,198 $ 1,977
======== ======== ======== ========
100% Equity Share
---------------------------- -----------------------------
1998 1997 1996 1998 1997 1996
-------- -------- --------- --------- --------- ---------
Operating revenues $ 11,811 $ 14,669 $ 15,436 $ 5,968 $ 7,452 $ 7,751
Operating income 1,101 1,078 749 539 532 364
Net income 193 853 133 58 390 51
Cash dividends received from these affiliates were $50 million, $43 million, and
$89 million in 1998, 1997 and 1996, respectively.
The above summarized combined financial information includes the cumulative
effect of the accounting change in 1998 as described in note 12.
Retained earnings as of December 31, 1998 and 1997, 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, 1998 and 1997
were 7.3% and 7.9%, respectively. Unutilized lines of credit available for
short-term financing totaled $1.3 billion as of December 31, 1998.
C-18
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
Note 6 - Long-term debt
- - ---------------------------
Long-term debt, with related interest rates for 1998 and 1997 consist of the
following:
As of December 31,
---------------------
(Millions of dollars)
1998 1997
------ ------
U.S. dollar debt:
Variable interest rate loans with average rates
of 5.5% and 6.2%, due 2002-2010 $ 454 $ 348
Fixed interest rate term loans with average rates of 6.4%
and 6.4%, due 2001-2003 130 100
Australian dollar debt:
Fixed interest rate loan with 11.2% rate due 2001 211 218
New Zealand dollar debt:
Variable interest rate loans with average rates
of 5.0% and 5.7%, due 2001-2004 78 63
Fixed interest rate loan with 8.09% rate due 2000 5 6
Malaysian ringgit debt:
Fixed interest rate loan with average rates of 9.16%
and 8.56%, due 2000-2001 33 21
South African rand debt:
Fixed interest rate loan with 17.8% rate due 2003 8 9
Other - variable interest rate loans with average rates
of 5.8% and 6.5%, due 2000-2003 11 5
------ ------
$ 930 $ 770
====== ======
Aggregate maturities of long-term debt by year are as follows (in millions of
dollars): 1999 - $40 (included in short-term debt); 2000 - $115; 2001- $454;
2002 - $243; 2003 - $82; and thereafter - $36.
Note 7 - Operating leases
- - ---------------------------
The Group has operating leases involving various marketing assets for which net
rental expense was $103 million, $105 million, and $92 million in 1998, 1997 and
1996, respectively.
Future net minimum rental commitments under operating leases having
non-cancelable terms in excess of one year are as follows (in millions of
dollars): 1999 - $64; 2000 - $53; 2001 - $46; 2002 - $31, 2003 - $23, and 2004;
and thereafter - $37.
Note 8 - Employee benefit plans
- - ---------------------------------
Effective January 1, 1998, the Group adopted SFAS No. 132, "Employers'
Disclosures about Pension and Other Post-retirement Benefits". SFAS No. 132
revises employers' disclosures about pension and other post-retirement benefit
plans, but does not change the method of accounting for such 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.
C-19
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
Note 8 - Employee Benefit plans - continued
- - ---------------------------------------------
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 dollars)
Other Post-retirement
Pension Benefits Benefits
------------------ ---------------------
1998 1997 1998 1997
------ ------ -------- ------
Change in benefit obligations:
Benefit obligation at January 1, $ 405 $ 523 $ 64 $ 58
Service cost 19 26 2 2
Interest cost 31 44 6 6
Actuarial loss 32 7 11 3
Benefits paid (72) (37) (4) (4)
Settlements and curtailments (26) - 5 -
Foreign exchange rate changes 11 (158) (5) (1)
------ ------ ------ ------
Benefit obligation at December 31, $400 $ 405 $ 79 $ 64
====== ====== ====== ======
Change in plan assets:
Fair value at January 1, $ 322 $ 399 $ - $ -
Actual return on plan assets 47 41 - -
Group contribution 62 15 4 4
Benefits paid (72) (37) (4) (4)
Settlements (26) - - -
Foreign exchange rate changes - (96) - -
------ ------ ------ ------
Fair value at December 31, $ 333 $ 322 $ - $ -
====== ====== ====== ======
Accrued benefit costs:
Funded status $ (67) $ (83) $ (79) $ (64)
Unrecognized net transition liability 4 3 - -
Unrecognized net actuarial losses 11 32 23 14
Unrecognized prior service costs 9 9 - -
------ ------ ------ ------
Accrued benefit cost $ (43) $ (39) $ (56) $ (50)
====== ====== ====== ======
Amounts recognized in the Combined Balance Sheet:
Prepaid benefit cost $ 27 $ 28 $ - $ -
Equity in affiliates (30) (40) - -
Accrued benefit liability (40) (27) (56) (50)
------ ------ ------ ------
Prepaid (accrued) benefit cost $ (43) $ (39) $ (56) $ (50)
====== ====== ====== ======
Weighted average rate assumptions:
Discount rate 7.6% 8.4% 10.0% 10.3%
Rate of increase in compensation 5.4% 6.4% 4.0% 4.2%
Expected return on plan assets 9.6% 9.4% n/a n/a
C-20
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
Note 8 - Employee Benefit plans - continued
- - ---------------------------------------------
As of December 31,
-----------------------
(Millions of dollars)
1998 1997
------- --------
Pension plans with accumulated benefit obligations
in excess of assets
Projected benefit obligation $ 184 $ 112
Accumulated benefit obligation 157 93
Fair value of assets 87 46
Year ended December 31,
---------------------------------
(Millions of dollars)
1998 1997 1996
Components of Pension Expense
Service cost $ 19 $ 26 $ 26
Interest cost 31 44 46
Expected return on plan assets (28) (36) (37)
Amortization of prior service cost 1 3 3
Recognized net actuarial loss 5 3 4
Curtailment/settlement loss 21 - -
------ ------ ------
Total $ 49 $ 40 $ 42
====== ====== ======
Components of Other Post-retirement Benefits
Service cost $ 2 $ 2 $ 1
Interest cost 6 6 5
Special termination benefit recognition 3 - -
Curtailment recognition 3 - -
------ ------ ------
$ 14 $ 8 $ 6
====== ====== ======
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 9.1% would change the post-retirement benefit obligation by $9
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 U.S. Internal Revenue Service (IRS)
for $292 million in excise tax, along with penalties and interest, bringing the
total to approximately $2 billion. The IRS claim relates to crude oil sales to
Japanese customers beginning in 1980. Prior to this time, Caltex directly
supplied crude oil to its Japanese customers, however, in 1980, a Caltex
subsidiary also became a contractual supplier of crude oil. The IRS position is
that the additional supplier constituted a transfer of property, and was thus
taxable. Caltex is challenging the claim since the addition of another supplying
company was not a taxable event. Additionally, Caltex believes the claim is
based on an overstated value. Finally, Caltex disagrees with the imposition and
calculation of interest and penalties. Caltex believes the underlying excise tax
claim is wrong. Caltex also believes the related claim for penalties is wrong
and the IRS claim for interest is flawed.
To litigate this claim, Caltex has been required to maintain a letter of credit
($2.5 billion at February 8, 1999, including interest for 1998 and 1999). The
Stockholders have guaranteed this letter of credit. For excise taxes, unlike
income taxes, the taxpayer is required to pay a portion of the tax liability to
gain access to the courts. Caltex has made a payment of $12 million in order to
progress this claim.
C-21
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
Note 9 - Commitments and contingencies - continued
- - ----------------------------------------------------
Caltex also is involved in IRS tax audits for years 1987-1993. 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.
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 sought to preclude the plaintiffs
from pursuing the Louisiana litigation on various federal and procedural
grounds. Having pursued these remedies in the federal court system without
success (including a denial of a writ of certiorari by the U.S. Supreme Court),
Caltex management intends to continue to contest all of the foregoing litigation
vigorously on various substantive and procedural 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 $800 million per
year. Purchases (in billions of dollars) under this and other similar contracts
were $0.8, $1.0 and $0.8 in 1998, 1997 and 1996, respectively.
Caltex is contingently liable for sponsor support funding for a maximum of $278
million in connection with an affiliate's project finance obligations. While the
project is operational, the requirements for the plant physical completion test,
which were to have been completed by June 30, 1998, have not been fully
satisfied. Thus, while an event of default exists in terms of the financing
agreement, the secured lenders have agreed not to enforce their rights and
remedies until June 30, 1999, since the affiliate was able to satisfy certain
conditions in the loan documentation. The affiliate is currently addressing the
outstanding issues to remedy the default conditions and expects to meet all
completion conditions by the agreed date.
During 1998, Caltex contributed $218 million as additional equity in the above
affiliate to meet sponsor support requirements. The other sponsor similarly
provided its proportionate share of equity under the sponsor support agreement.
In addition, during 1998, 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, 1998 of $31 million. The possible
requirement for further post-construction support is largely dependent on
refining margins and the affiliate's ability to service its secured debt.
C-22
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 dollars)
1998 1997
------ ------
Interest rate swaps - Pay Fixed, Receive Floating $ 653 $ 591
Interest rate swaps - Pay Floating, Receive Fixed 202 209
Commitments to purchase foreign currencies 395 467
Commitments to sell foreign currencies 25 50
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 eleven years. Net unrealized (losses) and gains on
contracts outstanding at December 31, 1998 and 1997 were ($7 million) and $6
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,
Hong Kong, and Singapore dollars) hedging existing liabilities have maturities
of up to three years. Net unrealized losses applicable to outstanding forward
exchange contracts at December 31, 1998 and 1997 were $23 million and $16
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 which reduce the Group's exposure
to price volatility in the physical markets. The derivative positions are
marked-to-market for valuation purposes. Gains and losses on hedges are deferred
and recognized concurrently with the underlying commodity transactions.
Derivative gains and losses not considered to be a hedge are recognized
currently in income. Unrealized gains on commodity-based derivative hedging
contracts outstanding as of December 31, 1998 and 1997 were $14 million and $3
million, respectively.
The Group's long-term debt of $930 million and $770 million as of December 31,
1998 and 1997, respectively, had fair values of $896 million and $731 million as
of December 31, 1998 and 1997, 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 $105 million and $82 million at December 31, 1998 and 1997,
respectively. The fair value of these securities at December 31, 1998 and 1997
approximates amortized costs. As of December 31, 1998 and 1997, investments in
debt securities available-for-sale had maturities less than ten years. As of
December 31, 1998 and 1997, the Group's carrying amount for investments in
affiliates accounted for at equity included $19 million and $12 million,
respectively, for after tax unrealized net gains on investments held by these
companies.
C-23
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
Note 10 - Financial Instruments - continued
- - -------------------------------------------
The Group is exposed to credit risks in the event of non-performance by
counterparties to financial instruments. For financial instruments with
institutions, the Group does not expect any counterparty 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.
Note 11 - Taxes
- - ---------------
Taxes charged to income consist of the following:
Year ended December 31,
----------------------------------------
(Millions of dollars)
1998 1997 1996
---- ---- ----
Taxes other than income taxes (International):
Duties, import and excise taxes $ 1,218 $ 1,409 $ 1,349
Other 17 19 18
-------- -------- -------
Total taxes other than income taxes $ 1,235 $ 1,428 $ 1,367
======== ======== =======
Income taxes:
U.S. taxes :
Current $ 6 $ 8 $ 455
Deferred 23 (2) 19
-------- -------- -------
Total U.S. 29 6 474
-------- -------- -------
International taxes:
Current $ 228 $ 407 $ 491
Deferred 69 (49) 17
-------- -------- -------
Total International 297 358 508
-------- -------- -------
Total provision for income taxes $ 326 $ 364 $ 982
======== ======== =======
C-24
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
Note 11 - Taxes - continued
- - ---------------------------
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,
----------------------------
1998 1997 1996
---- ---- ----
Computed "expected" tax rate 35.0% 35.0% 35.0%
Effect of recording equity in net income
of affiliates on an after tax basis (7.3) (11.3) (0.7)
Effect of dividends received from
subsidiaries and affiliates (0.3) (0.3) (0.5)
Income subject to foreign taxes at other
than U.S. statutory tax rate 26.0 5.2 8.1
Effect of sale of investment in affiliate - - 3.6
Deferred income tax valuation allowance 8.7 1.4 0.5
Other 0.7 - (0.8)
----- ----- -----
Effective tax rate 62.8% 30.0% 45.2%
===== ===== =====
The increase in the effective tax rate in 1998 is 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:
As of December 31,
-----------------------
(Millions of dollars)
1998 1997
----- -----
Depreciation $ 316 $ 314
Miscellaneous 38 22
----- -----
Deferred tax liabilities 354 336
----- -----
Investment allowances (62) (74)
Tax loss carry-forwards (63) (50)
Foreign exchange (8) (33)
Retirement benefits (48) (30)
Miscellaneous (12) (15)
----- -----
Deferred tax assets (193) (202)
Valuation allowance 72 27
----- -----
Net deferred taxes $ 233 $ 161
===== =====
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.
C-25
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
Note 11 - Taxes - continued
- - ---------------------------
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, 1998 and December 31, 1997, 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
has elected early adoption of this pronouncement effective January 1, 1998 and
accordingly, recorded a cumulative effect charge to income as of January 1, 1998
of $50 million representing the Group's share of the applicable start-up costs.
Excluding the cumulative effect, the change in accounting for start-up costs did
not materially affect net income for 1998.
Note 13 - Restructuring/Reorganization
- - ----------------------------------------
Caltex recorded a charge to income for $86 million in 1998 for various
restructuring and reorganization activities undertaken to realign the company
along functional lines and reduce redundant operating activities. The charge
includes severance and other termination benefits (for a total of 500 employees)
of $52 million for U.S. headquarter and expatriate operating staff ($26 million
severance and other termination benefits, and $26 million for employee benefit
curtailment/settlements) and $8 million for various foreign staff, and $10
million for asset and lease commitment write-offs. Other reorganization costs
were $16 million. Approximately $53 million remained as recorded liabilities as
of December 31, 1998, which will mostly be paid during 1999. These charges were
included in selling, general and administrative expenses in the combined
statement of income.
Note 14 - Combined statement of cash flows
- - --------------------------------------------
Changes in operating working capital consist of the following:
Year ended December 31,
----------------------------------
(Millions of dollars)
1998 1997 1996
----- ----- ------
Accounts and notes receivable $ 404 $ 33 $ (235)
Inventories (28) 85 (16)
Accounts payable (105) (252) 210
Accrued liabilities 41 1 18
Estimated income taxes 4 (17) 16
----- ------- ------
Total $ 316 $ (150) $ (7)
===== ======= =======
Net cash provided by operating activities includes the following cash payments
for interest and income taxes:
Year ended December 31,
-------------------------------
(Millions of dollars)
1998 1997 1996
----- ------ ------
Interest paid (net of capitalized interest) $ 182 $ 138 $ 137
Income taxes paid $ 237 $ 440 $ 865
C-26
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
Note 14 - Combined statement of cash flows - continued
- - --------------------------------------------------------
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:
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
1998 and 1996.
Net cash provided by operating activities in 1996 includes income tax payments
relating to the sale of an investment in an affiliate. Proceeds from this sale
are included in net cash provided by investing activities.
Note 15 - 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-27