1993
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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, 1993
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
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CHEVRON CORPORATION
(Exact name of registrant as specified in its charter)
225 Bush Street,
Delaware 94-0890210 San Francisco, California 94104
- ---------------- --------------------- ------------------------- -----------
(State or other (I.R.S. Employer (Address of principal (Zip Code)
jurisdiction of Identification Number) executive offices)
incorporation or
organization)
Registrant's telephone number, including area code (415) 894-7700
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 $3.00 per share New York Stock Exchange, Inc.
Preferred stock purchase rights Midwest Stock Exchange
Pacific Stock Exchange
Sinking fund debentures: 9-3/8%, due 2016 New York Stock Exchange, Inc.
Securities guaranteed by Chevron Corporation:
Chevron Capital U.S.A. Inc.
Sinking fund debentures: 9-3/4%, due 2017 New York Stock Exchange, Inc.
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes X No
----- -----
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
Aggregate market value of the voting stock held by nonaffiliates
of the Registrant
As of February 28, 1994 - $28,168 million
Number of Shares of Common Stock outstanding as of
February 28, 1994 - 325,825,185
DOCUMENTS INCORPORATED BY REFERENCE
(To The Extent Indicated Herein)
Notice of Annual Meeting and Proxy Statement
Dated March 25, 1994 (in Part III)
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TABLE OF CONTENTS
PAGE
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ITEM YEAR 1993 MARCH 25, 1994
- ---- FORM 10-K PROXY STMT.
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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 9 -
Production Levels . . . . . . . . . . . 9 -
Development Activities . . . . . . . . . 10 -
Petroleum - Natural Gas Liquids . . . . . 15 -
Petroleum - Reserves and
Contract Obligations . . . . . . . . . . . 16 -
Petroleum - Refining . . . . . . . . . . . 16 -
Petroleum - Refined Products Marketing . . 18 -
Petroleum - Transportation . . . . . . . . 19 -
Chemicals . . . . . . . . . . . . . . . . 21 -
Coal and Other Minerals . . . . . . . . . 22 -
Real Estate . . . . . . . . . . . . . . . 22 -
Research and Environmental Protection . . 23 -
2. Properties . . . . . . . . . . . . . . . . . . . 25 -
3. Legal Proceedings . . . . . . . . . . . . . . . 25 -
4. Submission of Matters to a Vote of
Security Holders . . . . . . . . . . . . . . . . 28 -
Executive Officers of the Registrant . . . . . . 28 -
PART II
5. Market for the Registrant's Common Equity
and Related Stockholder Matters . . . . . . . . 30 -
6. Selected Financial Data . . . . . . . . . . . . 30 -
7. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . 30 -
8. Financial Statements . . . . . . . . . . . . . . 30 -
8. Supplementary Data - Quarterly Results . . . . . 30 -
Supplementary Data - Oil and
Gas Producing Activities . 30 -
9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure . . . . . 30 -
PART III
10. Directors and Executive Officers
of the Registrant . . . . . . . . . . . . . . . 30 4-6
11. Executive Compensation . . . . . . . . . . . . . 30 15-17
12. Security Ownership of Certain Beneficial Owners
and Management . . . . . . . . . . . . . . . . . 30 2-3
13. Certain Relationships and Related Transactions . 30 -
PART IV
14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K . . . . . . . . . . . . 31 -
PART I
ITEM 1. BUSINESS
(a) GENERAL DEVELOPMENT OF BUSINESS
SUMMARY DESCRIPTION OF CHEVRON
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Chevron Corporation (1), a Delaware corporation, is a major international oil
company. It provides administrative, financial and management support for,
and manages its investments in, domestic and foreign subsidiaries and
affiliates, which engage in fully integrated petroleum operations, chemical
operations, real estate development and other mineral and energy related
activities in the United States and approximately 100 other countries.
Petroleum operations consist of exploring for, developing and producing crude
oil and natural gas; transporting crude oil, natural gas and petroleum
products by pipelines, marine vessels and motor equipment; refining crude oil
into finished petroleum products; and marketing crude oil, natural gas and the
many products derived from petroleum. Chemical operations include the
manufacture and marketing of a wide range of chemicals for industrial uses.
Incorporated in Delaware in 1926 as Standard Oil Company of California, the
company adopted the name Chevron Corporation in 1984. Domestic integrated
petroleum operations are conducted primarily through three divisions of the
company's wholly owned Chevron U.S.A. Inc. subsidiary. Exploration and
production operations in the United States are carried out through Chevron
U.S.A. Production Company. U.S. refining and marketing activities are
performed by Chevron U.S.A. Products Company. Warren Petroleum Company
engages in all phases of the domestic natural gas liquids business. A list
of the company's major subsidiaries is presented on page 40 of this Annual
Report on Form 10-K. As of December 31, 1993, Chevron had 47,576 employees,
78 percent of whom were employed in U.S. operations.
OVERVIEW OF PETROLEUM INDUSTRY
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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 determined by supply and demand for these commodities.
OPEC member countries are the world's swing producers of crude oil and their
production levels are the primary driver in determining worldwide supply.
Demand for crude oil and its products is largely driven by the health 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. Its largest use is for electrical generation, where it competes with
other energy fuels.
CURRENT OPERATING ENVIRONMENT
- -----------------------------
Crude oil prices rose slightly in the first quarter of 1993 and remained
steady through the second quarter before trending downward for the remainder
of the year. The decline was particularly prominent during the last two
months of 1993, with prices reaching their lowest level in five years by year
end. The weak global economy has dampened the demand for petroleum and
petroleum related products. Increased production from non-OPEC countries,
particularly from the North Sea, and OPEC's failure to adjust their
production levels accordingly has further exacerbated the decline in crude
oil prices. Partially mitigating the effects of
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(1) 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 the context clearly indicates
otherwise, should not be read to include "affiliates" of Chevron
(those companies owned approximately 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 -
lower crude oil prices were higher natural gas prices. Unseasonable weather
patterns, low gas storage levels, the loss of three nuclear power plants in
the Southeast for a portion of the year, and the environmentally preferred
attributes of natural gas all contributed to the stronger natural gas prices.
In the United States, the Henry Hub, Louisiana spot price for natural gas, a
common benchmark for natural gas prices, averaged $2.21 per thousand cubic
feet (MCF) in 1993, an increase of $.41 per MCF over 1992. Strong refined
product prices, which did not decline as rapidly as crude oil prices, also
helped to dampen the effects of lower crude oil prices. However, product
prices in the United States fell late in the year and have remained low into
1994. If both crude oil and refined product prices continue at their low
levels, the company's earnings and cash flow from ongoing operations may be
negatively affected. Widely fluctuating prices have become characteristic of
the petroleum industry for the past several years.
Chevron's average realization from U.S. crude oil production declined from
$16.50 per barrel in 1992 to $14.58 per barrel in 1993 while average liquids
realizations from international liftings, including equity affiliates,
declined by $1.84 per barrel to $16.09 per barrel. Average U.S. natural gas
realizations from production increased to $1.99 per MCF in 1993 from $1.70
per MCF in 1992.
The following table compares the high, low and average company posted prices
for West Texas Intermediate (WTI), an industry benchmark light crude oil, for
each of the quarters during 1993 and for the full years of 1993, 1992, and
1991:
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WEST TEXAS INTERMEDIATE CRUDE OIL
CHEVRON POSTED PRICES
(Dollars per Barrel)
1993
-------------------------------------
1st Q 2nd Q 3rd Q 4th Q Year 1992 1991
----- ----- ----- ----- ----- ----- -----
High 20.25 19.75 18.00 18.00 20.25 21.75 29.50
Low 17.50 18.00 16.00 13.00 13.00 16.50 16.75
Average 19.09 19.10 17.01 15.58 17.68 19.71 20.20
- ----------------------------------------------------------------------
For the first two months of 1994, average natural gas realizations for the
company's U.S. operations were $2.14 per MCF. During this period, the
company's posted price for WTI ranged from $13.00 per barrel to $15.00 with
an average of $13.86. On March 21, 1994, the company's posted price for WTI
was $14.25 per barrel.
CHEVRON STRATEGIC DIRECTION
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To improve financial performance and to compete more effectively, Chevron
developed and began implementing seven "strategic intents" in 1992. These are
to:
- - SHIFT EXPLORATION AND PRODUCTION EMPHASIS TO INTERNATIONAL OPPORTUNITIES.
The company believes opportunities to discover and develop major new
reserves in the United States are limited due to regulatory barriers and
drilling prohibitions on many of the most promising areas of development.
In 1993, 68 percent of the exploration and production capital spending,
including affiliates, was allocated to international operations. In 1994,
that number is expected to increase to 75 percent. As recently as 1990,
U.S. exploration and production capital spending was approximately 50
percent of the total. As an important example of this new emphasis, in
April 1993, the company entered into a joint venture agreement with the
Republic of Kazakhstan to develop the massive Tengiz oil field in that
country.
- 2 -
- - GENERATE $1 BILLION IN CASH ANNUALLY FROM U.S. EXPLORATION AND PRODUCTION
OPERATIONS. Chevron is emphasizing a steady cash flow from a core group of
approximately 400 oil and gas fields concentrated in California, Texas,
the Rocky Mountains and the Gulf of Mexico. In 1993, net cash flow after
capital and exploratory expenditures for U.S. exploration and production
operations was more than $1.2 billion. Lower operating expenses and an
improved natural gas market helped to mitigate the effects of lower crude
oil prices. If crude oil prices do not rebound, this goal may be difficult
to achieve in 1994.
- - RESHAPE THE U.S. REFINING AND MARKETING COMPANY INTO A TOP COMPETITOR.
Chevron is currently the leading U.S. marketer of refined products and has
the largest refining capacity in the nation. The company is seeking to
strengthen its competitive position by investing in core refineries,
reducing the size of its refining system and concentrating on specific
marketing regions. Major projects are continuing at the company's Richmond
and El Segundo, California refineries in order to produce reformulated
fuels to meet the January 1995 emission requirements of the Clean Air Act
Amendments of 1990 and the 1996 requirements of the California Air
Resources Board. The company expects to complete the sale of its
Philadelphia, Pennsylvania and Port Arthur, Texas refineries in 1994,
thereby reducing its refining capacity about 25 percent.
- - GROW CALTEX IN ATTRACTIVE MARKETS. Management believes that the demand for
petroleum products will continue to grow in the Asia Pacific region and
Chevron's 50 percent owned Caltex affiliate, a leading competitor in these
areas, has made significant capital investments to expand and upgrade its
refining capacity. Refinery upgrade projects are currently underway in
Singapore and Korea, as well as the construction of a new refinery in
Thailand.
- - EXPLOIT COMPETITIVE STRENGTHS IN CHEMICALS. The petrochemical industry is
highly cyclical. In order to improve its competitive position, the company
is concentrating on areas of the petrochemical business in which it holds
a competitive advantage, such as in its proprietary Aromax (R) process used
to produce high value benzene from low value by-products of the oil
refining process. The first Aromax (R) plant in the U.S., located at the
company's Pascagoula, Mississippi, refinery, was completed in 1993. The
company also announced, in January 1994, a cost reduction plan intended to
reduce annual operating expense by approximately $100 million by 1996. An
integral part of the plan is to divest or close non-core assets and
sharpen the company's focus on the remaining core businesses.
- - BE SELECTIVE IN NON-CORE BUSINESSES. In 1993, Chevron continued to dispose
of marginally performing or non-strategic assets, including various oil
and gas properties located in the United States and Indonesia. The company
also divested its ORTHO lawn and garden products business, retail
marketing operations in Guatemala, Nicaragua and El Salvador, certain
undeveloped coal properties in the U.S., and its Vinwood Cellars Winery in
California. Properties currently for sale include the company's 52.5
percent interest in some zinc-lead prospects in Ireland, refineries
located in Philadelphia, Pennsylvania and Port Arthur, Texas, and the
company's headquarters building located in San Francisco, California.
- - FOCUS ON REDUCING COSTS ACROSS ALL ACTIVITIES. Chevron undertook an
extensive cost-cutting and work force reduction program in early 1992.
These efforts, in combination with the company's continuing program to
dispose of non-core or underperforming assets, reduced 1993 operating
costs, adjusted for special items, by approximately 5 percent or 40 cents
a barrel from 1992 levels. When compared to the base year of 1991, ongoing
operating, selling and administrative expenses have dropped by 11 percent,
or 94 cents a barrel. To remain competitive, the company's management has
set a number of new goals, including a new cost-reduction target of an
additional 25 cents a barrel by the end of 1994.
In 1993, the company established a new "strategic intent:"
- - BUILD A COMMITTED TEAM TO ACCOMPLISH THE CORPORATE MISSION. The company
believes the success of the other seven strategic intents is dependent on
the commitment and dedication that Chevron employees bring to their jobs.
In a 1992 employee survey and a 1993 update, Chevron measured employee
- 3 -
commitment using a model that assesses employee's willingness to expend
discretionary effort on the job, combined with how strongly they feel the
company deserves that effort. The surveys highlighted employee concerns
on issues that the company is addressing. Due, in part, to the results
of the survey, the company has initiated a number of work and family
programs to help employees improve their productivity and commitment,
such as flexible schedules, part-time work, job sharing and various leave
programs. The company also presented commemorative wristwatches to its
employees and a one time cash bonus equal to 5 percent of their annual
salaries in appreciation for their efforts in meeting the company's five
year goal, established in 1989, to be number one in stockholders' return
among five peer U.S. oil companies. In February 1994, the company took
delivery of a new vessel, the Chevron Employee Pride, named in honor of
its worldwide workforce.
(b) INDUSTRY SEGMENT AND GEOGRAPHIC AREA INFORMATION
The company's primary business is its integrated petroleum operations.
Secondary operations include chemicals and minerals. The petroleum
activities of the company are widely distributed geographically, with major
operations in the United States, Australia, United Kingdom, Canada, Nigeria,
Angola, Papua New Guinea, China, Indonesia and Zaire. The company's Caltex
affiliate, through its subsidiaries and affiliates, conducts exploration and
production operations in Indonesia and refining and marketing activities in
the Eastern Hemisphere, with major operations in Japan, Korea, Australia, the
Philippines, Thailand and South Africa. Tengizchevroil (TCO), a 50/50 joint
venture with a subsidiary of the national oil company of the Republic of
Kazakhstan conducts production activities in Kazakhstan, a former Soviet
republic.
The company's and its affiliates' chemicals operations are concentrated in
the United States, but include operating facilities in France, Japan and
Brazil. The company's and its affiliates' principal minerals activities
include both coal and platinum and palladium operations in the United States.
Tabulations setting forth three years' identifiable assets, operating income,
sales and other operating revenues for the company's three industry segments,
by United States and International geographic areas, may be found in Note 9
to the Consolidated Financial Statements beginning on page FS-22 of this
Annual Report on Form 10-K.
(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.
The company's operations can be affected significantly by changing economic,
regulatory and political environments in the various countries, including the
United States, in which it operates. The company evaluates the economic and
political risk of initiating, maintaining or expanding operations in any
geographical area.
In the United States, environmental regulations and federal, state and local
actions and policies concerning economic development, energy and taxation
may have a significant effect on the company's operations.
Internationally, the company is monitoring closely the civil unrest in Angola
and the political uncertainty in Nigeria and Zaire and the possible threat
these may pose to the company's oil and gas exploration and production
operations and the safety of the company's employees located in those
countries.
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.
- 4 -
CAPITAL AND EXPLORATORY EXPENDITURES
Chevron's capital and exploratory expenditures during 1993 and 1992 are
summarized in the following table:
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CAPITAL AND EXPLORATORY EXPENDITURES
(Millions of Dollars)
1993 1992
------ ------
Exploration and Production $2,217 $2,097
Refining, Marketing and Transportation 1,166 1,263
Chemicals 224 251
Coal and Other Minerals 42 79
All Others 90 112
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Total Consolidated Companies 3,739 3,802
Equity in Affiliates 701 621
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Total Including Affiliates $4,440 $4,423
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Total consolidated expenditures in 1993 were essentially flat when compared
to 1992, declining less than 2 percent between periods. An increase in
exploration and production (E&P) expenditures of $120 million was more than
offset by lower expenditures in the company's other operations.
Exploration and production expenditures amounted to 59 percent of the
company's consolidated expenditures, a 4 percent increase over 1992 levels.
The increase was due solely to increased expenditures in international E&P as
U.S. E&P expenditures continued to decline, down 4 percentage points to 34
percent of consolidated E&P expenditures in 1993. This decrease reflects
the continued shift in the company's emphasis from U.S. exploration and
production activities to international opportunities. Major international
E&P expenditures in 1993 included development of the Alba Field in the U.K.
North Sea, the North West Shelf Project in Australia, the Hibernia Project
offshore Newfoundland, the Duri steamflood project in Indonesia, Areas B and
C in Angola and the Tengiz project in Kazakhstan. Refining, marketing and
transportation outlays in 1993 included expenditures for upgrading U.S.
refineries to produce fuels, such as low aromatics and ultra low sulfur
diesel fuel and reformulated gasoline, to comply with current and future
federal, state and local air quality regulations.
In 1994, the company expects to spend approximately $4.9 billion, including
its share of equity affiliates' expenditures, an increase of approximately 11
percent over 1993 levels. Equity affiliate spending, primarily Caltex
expenditures in the high growth Pacific Rim areas, account for this increase
as consolidated expenditures in 1994 are expected to remain flat at $3.7
billion. E&P expenditures are expected to total $2.4 billion, of which
approximately 75 percent will be for international projects such as the
continued development of the Hibernia Field, expansion of the North West
Shelf Project, enhanced recovery projects in Indonesia, the Tengiz project
in Kazakhstan, and other development projects in West Africa. Refining,
marketing and transportation expenditures are estimated at $2.1 billion,
with U.S. expenditures of about $1 billion, including continued upgrades to
U.S. refineries to produce reformulated gasoline in order to comply with the
Clean Air Act Amendments of 1990 and California Air Resources Board
regulations.
The actual expenditures for 1994 will depend on various conditions affecting
the company's operations and may differ significantly from the company's
forecast. If low oil prices persist, expenditures, particularly for
exploration and production, may be lower than forecast. Significant
expenditures are expected over the next few years at the company's
manufacturing facilities to comply with federal, state and local
environmental regulations and to enable these facilities to produce cleaner
fuels for industrial and consumer use.
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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, 1993. "Exploratory
wells" 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.
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EXPLORATORY WELL ACTIVITY
NET WELLS COMPLETED (1)
WELLS DRILLING ---------------------------------------
AT 12/31/93 1993 1992 1991
------------------- ----------- ---------- -----------
GROSS (2) NET (2) PROD. DRY PROD. DRY PROD. DRY
--------- ------- ---- ---- ---- ---- ---- ----
United States 37 33 32 14 42 16 39 25
--------- ------- ---- ---- ---- ---- ---- ----
Canada 13 11 27 26 10 - 24 21
Africa 13 5 3 4 3 3 2 5
Other
International 35 10 - 9 5 4 1 5
--------- ------- ---- ---- ---- ---- ---- ----
Total
International 61 26 30 39 18 7 27 31
--------- ------- ---- ---- ---- ---- ---- ----
Total
Consolidated
Companies 98 59 62 53 60 23 66 56
Equity in
Affiliate - - 1 1 1 - 1 1
--------- ------- ---- ---- ---- ---- ---- ----
Total Including
Affiliates 98 59 63 54 61 23 67 57
========= ======= ==== ==== ==== ==== ==== ====
(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.
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At December 31, 1993, the company owned or had under lease or similar agree-
ments undeveloped and developed oil and gas properties located throughout
the world. Undeveloped acreage includes undeveloped proved acreage. The geo-
graphical distribution of the company's acreage is shown in the next table.
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ACREAGE* AT DECEMBER 31, 1993
(Thousands of Acres)
DEVELOPED
UNDEVELOPED DEVELOPED AND UNDEVELOPED
---------------- -------------- ----------------
GROSS NET GROSS NET GROSS NET
------- ------ ----- ----- ------- ------
United States 3,994 3,123 4,626 2,841 8,620 5,964
------- ------ ----- ----- ------- ------
Canada 18,213 10,374 528 383 18,741 10,757
Africa 17,147 12,726 135 53 17,282 12,779
Asia 54,297 23,944 61 21 54,358 23,965
Europe 3,231 1,195 58 11 3,289 1,206
Other International 9,656 3,257 57 16 9,713 3,273
------- ------ ----- ----- ------- ------
Total International 102,544 51,496 839 484 103,383 51,980
------- ------ ----- ----- ------- ------
Total Consolidated
Companies 106,538 54,619 5,465 3,325 112,003 57,944
Equity in Affiliates 3,202 1,601 233 116 3,435 1,717
------- ------ ----- ----- ------- ------
Total Including
Affiliates 109,740 56,220 5,698 3,441 115,438 59,661
======= ====== ===== ===== ======= ======
* 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.
- -----------------------------------------------------------------------------
- 6 -
The company had $222 million of suspended exploratory wells included in
properties, plant and equipment at year-end 1993. The wells are suspended
pending drilling of additional wells to determine if commercially
producible quantities of oil or gas reserves are present. The ultimate
disposition of these well costs is dependent on the results of this future
activity.
During 1993, the company explored for oil and gas in the United States and
about 21 other countries. The company's 1993 exploratory expenditures,
including affiliated companies' expenditures but excluding unproved
property acquisitions, were $533 million compared with $547 million in
1992, a 3 percent decrease. Domestic expenditures represented approximately
34 percent of the consolidated companies' worldwide exploration
expenditures, essentially unchanged from the prior year. Significant
activities in Chevron's exploration program during 1993 include the
following (number of wells are on a "gross" basis):
UNITED STATES: Domestic exploratory expenditures, excluding unproved
property acquisitions, were $183 million in 1993, compared to $189 million
spent in 1992. In addition, the company incurred costs of $11 million for
unproved property acquisitions in 1993. The company continued to focus its
1993 exploratory efforts in the Gulf of Mexico and in other areas where it
has existing production. Fifteen exploratory wells were initiated in 1993.
Seven of these exploratory wells were completed in 1993, resulting in two
discoveries located in the Houston Salt Basin and in the Gulf of Mexico.
Plans to spud a well in the Norphlet Trend prospect in Destin Dome 97,
located in the Gulf of Mexico, were deferred until March 1994 due to delays
in the permit process.
Exploration efforts in high-potential areas, including Alaska's Arctic
National Wildlife Refuge (ANWR) and parts of offshore Florida, California
and North Carolina have been blocked by legal restrictions and drilling
moratoria.
Chevron and other oil companies have sued the Department of Interior to
recover bonus payments, lease rentals and certain geophysical costs for
federal offshore leases that remain undrilled due to state, federal, and
private objections to drilling. The company is seeking to recover
approximately $126 million, plus interest, spent on leases off Florida,
North Carolina and Alaska.
AFRICA: In Africa, the company spent $104 million during 1993 on
exploratory efforts, excluding the acquisition of unproved properties,
compared with $108 million in 1992. The company also acquired $9 million of
unproved properties in 1993. In Nigeria, the company drilled six
exploratory and appraisal wells in 1993, with all six either having proved
reserves assigned or assignment deferred pending further exploration or
evaluation work. The company also acquired 3-D seismic data covering
Nigerian acreage of 1,410 square kilometers in 1993 and separately entered
into a farm-in arrangement for the exploration of three offshore
concessions. In Angola, the company is the operator of a 7,000 square
kilometer concession off the coast of Angola's Cabinda exclave. The
concession is divided into Areas A, B, and C, with Area A generating all
current production. One successful exploration well was drilled in Area A
during 1993 resulting in the discovery of the Numbi South East field which
was brought on stream in 1993 by linking it to the existing Numbi Field
facilities. Two exploratory wells were drilled in Areas B and C and a third
was drilled at the end of the year. These resulted in the discovery of the
M'Bili Field in Area C and a non-commercial accumulation in Area B. The
third well was tested in Area B as a discovery well, N'Sangui, in January
1994. Options for the development of M'Bili are currently being evaluated.
The current Exploration Period for Areas B and C was to expire at the end
of February 1994 with a provision to fulfill all obligations by the end of
August 1994. The company has requested an extension of the Exploration
Period. Under the existing agreement, two exploratory wells will be drilled
in Areas B and C in 1994. An additional well may be drilled if the
extension is granted. Chevron (operator) and its partners are currently
negotiating a Production Sharing Agreement for the recently awarded
Deepwater Block 14, located due west of Areas B and C. The agreement is
expected to be completed and signed in 1994. In the Congo, a regional 3-D
survey was acquired in 1993 covering the southern part of the Marine VII
Block which includes both the Kitina and Kitina South discoveries, as well
as several additional exploration prospects. In Namibia, the company has
been conducting a detailed seismic evaluation of the offshore Namibia Block
2815, where Chevron is the operator. In 1993, Chevron farmed-out a portion
of its interest in the concession, reducing its share from 60 percent to 40
percent.
- 7 -
OTHER INTERNATIONAL INCLUDING AFFILIATED COMPANIES: Exploration
expenditures, excluding unproved property acquisitions, were $246 million
in 1993, a decrease of $4 million from the 1992 amount of $250 million. In
addition, unproved properties of $430 million, primarily related to the
company's investment in Tengizchevroil (TCO), were acquired in 1993.
In the North Sea, Chevron participated in four wildcat wells in the U.K.
sector in 1993. A discovery was made in the Paleocene Parliament prospect,
to the northeast of Alba and Britannia, thereby establishing area
potential. During the U.K.'s 14th licensing round, the company was awarded
operatorship of four blocks in the coastal waters to the west of Britain.
In Canada, exploration efforts in 1993 continued to be concentrated in the
western part of the country. A total of 23 wildcat wells were drilled in
1993 which reflected an increase in drilling activity as a share of total
exploratory expenditures.
In Indonesia, Chevron and its partners drilled nine exploratory wells in
1993, three of which resulted in oil discoveries.
In Australia, Chevron and its partners in West Australia Petroleum Pty.,
Ltd. (WAPET) participated in the drilling of the North West Shelf
exploration well West Dixon-1, which proved unsuccessful. A preliminary
interpretation of the Gorgon 3-D seismic survey was completed in 1993 and
WAPET has approved the exploratory drilling for gas of North Gorgon-2 in
1994. WAPET also acquired a 519,000 acre block north of Gorgon in 1993. The
new permit, WA-253-P, will be issued to WAPET in early 1994.
In Papua New Guinea, the government has agreed to grant Chevron and its
partners an extension of its exploratory license. The extension
significantly extends the time remaining for exploration of a large area of
the Papuan Fold and Thrust Belt. Exploration efforts continue to be
concentrated near the Kutubu project facilities and export system. The Gobe
4X well was drilled before year-end at a location approximately 15
kilometers northwest of the SE Gobe field, resulting in an additional oil
and gas discovery on this 40 kilometer-long anticline.
In China, Chevron was awarded sole interest in Block 33/08 in the East
China Sea in December. Seismic studies are planned for the second quarter
1994 to determine the optimum location for exploratory drilling. All
exploration and drilling activities will be coordinated from Chevron's
newly-opened Shanghai office. The HZ/32-4-1 exploratory well in the Pearl
River Mouth Basin of the South China Sea was abandoned as a dry hole in
1993.
Other areas where exploration activities occurred in 1993 include Bolivia
where the first exploratory well (Cuevo West) was completed in March 1994
as a dry hole, Trinidad and Tobago where the first of four exploratory
wells (Rocky Palace #1) was spudded in late 1993, Colombia where evaluation
of the Rio Blanco Block in the Llanos foothills continued in 1993 with the
acquisition of a seismic program, Yemen where the exploratory well Al Harsh
#1 was unsuccessful, and Azerbaijan where Chevron and the State Oil Company
of the Azerbaijan Republic (SOCAR) signed an agreement to jointly study oil
and gas reserve potential in the southern third of the Caspian Sea.
- 8 -
PETROLEUM - OIL AND NATURAL GAS PRODUCTION
The following table summarizes the company's and its affiliate's 1993 net
production of crude oil, natural gas liquids and natural gas.
- -----------------------------------------------------------------------------
1993 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 130,330 139,110
-Gulf of Mexico 127,500 1,134,910
-Texas 73,420 403,620
-Louisiana 5,790 30,060
-Wyoming 10,610 155,120
-Colorado 16,560 -
-New Mexico 8,630 94,720
-Other States 21,380 98,460
------- ---------
Total United States 394,220 2,056,000
------- ---------
Africa 217,600 -
Canada 49,510 217,650
United Kingdom (North Sea) 49,430 27,670
Indonesia 31,730 1,050
Australia 17,780 163,580
Papua New Guinea 31,040 -
China 8,200 -
Other International 7,750 6,110
------- ---------
Total International 413,040 416,060
------- ---------
Total Consolidated
Companies 807,260 2,472,060
------- ---------
Equity in Affiliates 142,890 53,370
------- ---------
Total Including
Affiliates 950,150 2,525,430
======= =========
* Net production excludes royalties owned by others.
- -----------------------------------------------------------------------------
PRODUCTION LEVELS:
In 1993, net crude oil and natural gas liquids production, including
affiliates, increased by about one percent to 950,150 barrels per day from
943,940 barrels per day in 1992. Production increases were noted in Papua
New Guinea due to full year production and additional wells being brought
on stream in 1993 from the Kutubu project, in Kazakhstan due to the startup
of a new joint venture partnership in April 1993, and in Indonesia due to
production increases as the result of application of enhanced recovery
methods in certain fields. These production increases were partially offset
by production declines in the United States due to divestments of producing
properties in 1992 and normal field declines.
Net production of natural gas, including affiliates, declined 250,920
thousand cubic feet per day, or 9 percent, in 1993 from 1992. The decrease
was primarily due to normal field declines and 1992 divestitures of
producing properties in the United States and the Netherlands. The decline
was partially offset by production from the startup of the company's new
joint venture in Kazakhstan.
In the United States, natural gas producers have traditionally sold their
production to pipeline companies, who in turn distribute the product to
their customers. As a result of FERC Order 636, producers now can sell
directly to customers and provide many of the services previously provided
by the pipeline companies. Chevron has concentrated its natural gas
marketing efforts on the longer term contract market. These customers,
which include local distribution companies and industrials, require premium
bearing services and marketing arrangements that Chevron can fulfill. The
company's sales to these customers have risen significantly, while sales to
pipeline companies have correspondingly declined.
- 9 -
Data on the company's average sales price per unit of oil and gas
produced, as well as the average production cost per unit for 1993, 1992
and 1991 are reported in Table III on pages FS-32 to FS-33 of this Annual
Report on Form 10-K. The following table summarizes the company's and its
affiliates' gross and net productive wells at year-end 1993.
- -----------------------------------------------------------------------------
PRODUCTIVE OIL AND GAS WELLS AT DECEMBER 31, 1993
PRODUCTIVE (1) PRODUCTIVE (1)
OIL WELLS GAS WELLS
------------------ -------------------
GROSS (2) NET(2) GROSS (2) NET (2)
--------- ------ --------- -------
United States 27,155 12,460 3,164 1,569
--------- ------ --------- -------
Canada 2,042 1,017 330 146
Africa 830 320 4 2
United Kingdom (North Sea) 180 24 - -
Other International 968 350 54 15
--------- ------ --------- -------
Total International 4,020 1,711 388 163
--------- ------ --------- -------
Total Consolidated Companies 31,175 14,171 3,552 1,732
Equity in Affiliates 4,311 2,156 28 14
Total Including Affiliates 35,486 16,327 3,580 1,746
========= ====== ========= =======
Multiple completion wells
included above: 388 183 20 14
(1) Includes wells producing or capable of producing. 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 affiliated companies but
excluding proved property acquisitions, were $1,451 million in 1993 and
$1,525 million in 1992.
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 developmental wells drilling at December 31, 1993.
(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.)
- -----------------------------------------------------------------------------
DEVELOPMENT WELL ACTIVITY
NET WELLS COMPLETED (1)
WELLS DRILLING --------------------------------------
AT 12/31/93 1993 1992 1991
------------------- ----------- ---------- -----------
GROSS (2) NET (2) PROD. DRY PROD. DRY PROD. DRY
--------- ------- ---- ---- ---- ---- ---- ----
United States 97 80 293 11 217 5 445 6
--------- ------- ---- ---- ---- ---- ---- ----
Canada 14 12 41 12 45 4 66 5
Africa 6 2 10 - 10 1 13 1
Other
International 51 16 16 - 10 - 17 1
--------- ------- ---- ---- ---- ---- ---- ----
Total
International 71 30 67 12 65 5 96 7
--------- ------- ---- ---- ---- ---- ---- ----
Total
Consolidated
Companies 168 110 360 23 282 10 541 13
Equity in
Affiliates 45 22 93 - 159 5 171 10
--------- ------- ---- ---- ---- ---- ---- ----
Total Including
Affiliates 213 132 453 23 441 15 712 23
========= ======= ==== ==== ==== ==== ==== ====
(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.
- -----------------------------------------------------------------------------
- 10 -
Significant 1993 development activities include the following:
UNITED STATES: Chevron's U.S. development expenditures were $475 million
in 1993, a decrease of $8 million from the 1992 figure of $483 million.
Additions to proved reserves during 1993 from extensions, discoveries and
improved recovery, before revisions, were 98 million barrels of crude oil
and natural gas liquids and 356 billion cubic feet of natural gas.
The development of the San Joaquin Valley diatomite reserves in California
continued in 1993. Forty one new wells were drilled and 45 older wells were
reworked using reservoir fracturing techniques. A four year water injection
project, initiated in 1992, to sustain reservoir pressure and further boost
production continued into its second year with the drilling of 42 injection
wells and the conversion of 18 producing wells to injection. The
combination of reservoir fracturing and water injection is expected to
increase both the production rate and the amount of oil ultimately
recoverable from this resource.
Production in the Point Arguello project, offshore California, averaged
74,000 barrels of oil per day in 1993. Chevron owns approximately 25
percent of the project and operates two offshore platforms (Hermosa and
Hidalgo), the onshore Gaviota oil and gas plant and the interconnecting
pipelines. A workover and drilling program, designed to add proved reserves
and abate the decline in production rate, commenced in August 1993 on the
two offshore platforms. Five workovers and two new wells, improving
Chevron's lease production by 4,300 barrels of oil per day, were completed
in 1993. Three additional wells are planned to be drilled in 1994. Chevron
and its partners began double-hulled tankering to Los Angeles of some
250,000 barrels of oil three to four times per month from the field's
processing plant at Gaviota in August 1993 under an agreement with the
California Coastal Commission. Previously, production was limited to
approximately 60,000 barrels per day or 70 percent of full capacity of
85,000 barrels per day due to limited onshore pipeline capacity. Fourth
quarter production averaged 80,700 barrels per day. The terms of the permit
granted by the California Coastal Commission allowed tankering to continue
until January 1, 1996 but required suspension of tankering from February 1,
1994 until such time that Chevron and its partners sign an agreement with a
pipeline developer that the developer could use to finance construction of
a new line. In late January 1994, Chevron approached the California Coastal
Commission to permit short-term tankering beyond February 1 due to damage
to a key crude oil pipeline system to Los Angeles caused by the Northridge
earthquake. The request was not acted upon by January 31 and short-term
tankering was subsequently suspended on February 1. Although production was
initially maintained by routing to alternate markets, the shortage of
adequate transportation facilities has subsequently resulted in reduced
production. In March 1994, the company announced that an agreement had been
reached on building a new 130 mile pipeline in Southern California that
would carry Point Arguello oil production to Los Angeles. The company
anticipates construction on the Pacific Pipeline will commence in early 1995
and be operational in early 1996. Pending the construction of this new
pipeline, the company is seeking to resume limited tanker shipments through
1995.
Natural gas production from Garden Banks Block 191 in the Gulf of Mexico
started in late 1993. Daily production should reach 150 million cubic feet
per day during the first quarter of 1994. During 1994, six additional wells
will be drilled under simultaneous drilling and production operations.
Chevron is the operator and holds a 50 percent interest in this block.
In the Gulf of Mexico's Norphlet Trend, which stretches some 80 miles from
the Destin Dome area (offshore Florida) to the Mobile Block 861 area
(offshore Mississippi), two wells, Mobile Block 861 #8 (Chevron 50 percent
interest) and Mobile Block 917 #2 (Chevron 91.3 percent interest), were
completed and tested in 1993. Production from 861 #8, which tested at 57
million cubic feet per day (total), commenced in February 1994 while
production from 917 #2, which tested at 46 million cubic feet per day
(total), will commence in 1995. The company and its partners are currently
drilling or planning to drill additional exploratory wells in Mobile Blocks
863, 864, and 916 and Destin Dome 97 in 1994.
A new platform was installed in Chevron's wholly owned Main Pass 299 Field
in July 1993. Ten development wells are planned with three wells having
been completed and placed in production in December 1993. Production is
expected to peak at 3,000 barrels per day late in 1994.
- 11 -
Chevron continued to aggressively develop "tight gas" (gas which is
produced from a tight, low-permeability formation) in the Laredo, Texas
area. In 1993, twenty-five wells were drilled with twenty-three successes,
adding net proved reserves of 70 billion cubic feet of gas. Production
averaged 135 million cubic feet of gas per day in 1993. The S. Uribe No. 11
well was completed in 1993 with a sustained flow rate of 23 million cubic
feet of gas per day.
AFRICA: Developmental expenditures in Africa were $239 million in 1993,
compared to $189 million in 1992. Additions to proved reserves were 105
million barrels of crude oil and natural gas liquids. In Angola, where
Chevron's equity interest is 39 percent, ten development wells were added
in Area A fields in 1993. In order to sustain production, six existing
wells in Area A were reworked and three offshore processing platforms in
the Malongo and Takula Fields were revamped and modernized in 1993.
Production from the N'Sano Field, discovered in 1992, was tied back to
existing Takula facilities. A new production platform to fully develop
N'Sano reserves is under construction for installation later this year.
Areas B and C continued to be the major focus of development programs in
1993. The first phase of development in these areas involves the
installation of two integrated drilling and production platforms in the
Kokongo Field. The East Kokongo platform will also be the hub for future
phases of development for Areas B and C. A thirty-eight mile pipeline
linking the platforms to onshore terminal facilities was completed in the
fourth quarter of 1993. Platform construction will be completed in Brazil
and delivered to Angola with oil production scheduled to begin in late
1994. The second phase of development is scheduled for the Sanha and N'Dola
fields and will consist of two production platforms and related pipelines
and facilities for which contracts were awarded in 1993. Commencement of
work has been delayed by partner financing issues. Preliminary development
plans for the third phase involving development of the Nemba and Lomba
fields have been submitted for governmental approval.
In Nigeria, Chevron is operator and has a 40 percent interest in
concessions totalling 2.3 million acres in onshore and offshore regions in
the Niger Delta. Producing facilities for three new fields, Opuekeba, Idama
and Inda, were completed and the fields came on stream during the second
half of 1993. Combined production from these new fields, along with
production from the Belma and Belma North unitized field development which
began in October 1993, is expected to add 60,000 barrels per day to the
total production capacity in 1994. Upgrade construction work on two
production platforms, Tapa and Delta South, were completed in 1993. This is
the beginning of a multi-year program which will include all existing
platforms in order to extend the useful life of these facilities and also
enhance safety and environmental performance. Work on the Escravos Gas
Project, Phase I, continued in 1993. This first phase will utilize gas that
is currently being flared in the Okan and Mefa fields. The project will
include offshore gas compression facilities, an onshore Liquified Petroleum
Gas (LPG) extraction plant, and a floating LPG storage unit anchored
offshore. The project will sell gas under a long term contract to the
Nigerian Gas Company in addition to producing approximately fifteen
thousand barrels per day of hydrocarbon liquids for export. The project is
scheduled for start-up in 1997. At year-end, discussions were underway on
the assignment of Chevron as the developer of a West African Gas Pipeline
which would deliver gas to Ghana via Benin and Togo. The company has an
additional subsidiary in Nigeria that holds a 20 percent interest in five
offshore oil fields operated by another partner.
In Zaire, where the company has a 50 percent interest in a 390 square mile
concession off the coast, development and exploration activities resumed in
1993 as political unrest subsided. Two developmental wells and four well
workovers in the Mibale, Motoba and Libwa fields were completed in 1993.
In the Congo, where Chevron has a 29.3 percent interest, the 1991 Kitina
discovery in the offshore Marine VII Block was successfully delineated with
a second appraisal well. Engineering studies are currently underway to
determine the optimal development and reservoir management plan for this
field.
OTHER INTERNATIONAL INCLUDING AFFILIATED COMPANIES: Development
expenditures in 1993 were $737 million compared to $853 million in 1992.
Additions to proved reserves from extensions, discoveries and improved
- 12 -
recoveries were 66 million barrels of crude oil and natural gas liquids
and 46 billion cubic feet of natural gas. Additions to proved reserves from
acquisitions were approximately 1.1 billion barrels of crude oil and
natural gas liquids and 1.5 trillion cubic feet of natural gas.
In the United Kingdom, the company has interests in over 50 blocks on the
U.K. Continental Shelf which totals approximately 1.7 million gross acres.
Chevron held interests, varying from 4.9 to 33.3 percent, in five producing
fields in the North Sea during 1993. A sixth field, Alba, started
production in January 1994. At the Ninian Field in the U.K. North Sea,
Chevron increased its interest by 6.5 percent to 23.6 percent in December
1993. Chevron and its partners began processing third party oil and gas in
1992 using available processing capacity at the Ninian facilities. The
Ninian partners receive tariffs for processing and exporting the production
from three subsea produced satellite fields - Staffa, Lyell and Strathspey.
Staffa production was brought on stream in 1992, followed by production
from Lyell (Chevron owns a 33.3 percent interest) in March 1993 and
Strathspey in December 1993. Lyell production peaked at 31,000 barrels per
day and has stabilized at a daily average of 19,000 barrels per day.
Strathspey production is currently averaging 17,000 barrels per day, with
an expected peak of 41,000 barrels per day. In 1993, Chevron and its
partners announced a commercial framework for bringing on future satellite
fields through Ninian. Direct drilling from Ninian Northern platform into
the first of four potential satellite prospects began in December. At the
Alba Field in the North Sea, development of the first phase of that project
was successfully completed with the installation and hook-up of the Alba
Northern platform and the Alba floating storage unit (FSU) in November.
Initial production, expected to peak at 70,000 barrels per day later this
year, began in January 1994 after the FSU was fully commissioned. Work also
began in 1993 on plans for the second phase of Alba which will develop the
southern area of the reservoir. The Alba Field, in which Chevron has a 33
percent interest, is estimated to contain up to 400 million barrels of
recoverable reserves. At the Britannia Field in the North Sea, a 3-D
seismic survey was completed in 1992 and analyzed in 1993 as a guide for
field mapping and development drilling. Delineation drilling results and
technical studies indicate that approximately two and one-half trillion
cubic feet of gas, 175 million barrels of condensate and up to 30 million
barrels of crude oil will be recoverable, with Chevron's share equating to
approximately 30 percent. Preliminary facility engineering studies are
nearing completion and a firm decision on development options and
commercial arrangements is expected in 1994.
In Canada, the company continues to concentrate its development efforts in
six core producing areas in Alberta and one in Manitoba where operating
efficiencies and lower operating costs can be realized using existing
infrastructure.
Chevron increased its ownership in the Hibernia Field, located
approximately 200 miles offshore Newfoundland, by 5 percent to about 27
percent in January 1993 after one of the four original project partners
withdrew. In 1993, construction on the project continued with the awarding
of the supermodule fabrication contracts, the pouring of the base slab for
the Gravity Base Structure, and the completion of supermodule and hook-up
engineering. Hibernia investment is projected to be about $200 million in
1994, an increase of $54 million over 1993 levels. Initial production is
scheduled for 1997. The company's capitalized investment in this project
was $375 million at year-end 1993.
In Indonesia, Chevron's interests in 14 contract areas are managed by its
50 percent owned P.T. Caltex Pacific Indonesia and Amoseas Indonesia
affiliates. The Duri Steamflood project, begun in 1985 to assist the
difficult production process for the relatively heavy, waxy Duri crude, is
being completed in 12 stages (Areas 1-12). Development of Area 7 is
currently underway. More than three billion additional barrels of oil are
expected to be recovered from the Duri Field as a result of steamflooding.
Total production at Duri averaged 247,000 barrels per day in 1993 and is
expected to peak at just over 300,000 barrels per day by the late 1990s. A
waterflood project involving 21 fields in Central Sumatra, including the
Minas field, continued in 1993. Water injection at Minas was initiated in
December 1993 as part of the conversion of the peripheral waterflood to a
pattern waterflood which is designed to improve oil recovery. Chevron sold
its 17.5 percent share in the South Natuna Sea Block B effective January 1,
1994. Chevron's net share of production from this block averaged
approximately 11,300 barrels of oil and natural gas liquids per day in
1993.
- 13 -
In Kazakhstan, the company formed a 50/50 joint venture with
Tengizmunaigaz, a subsidiary of Kazakhstanmunaigaz - the national oil
company of the Republic of Kazakhstan, to develop the Tengiz and Korolev
oil fields on the northeast coast of the Caspian Sea. This joint venture
affiliate, Tengizchevroil (TCO), began operations in April 1993, adding net
proved reserves to Chevron of 1.1 billion barrels of crude oil and natural
gas liquids and 1.5 trillion cubic feet of natural gas. Current production
has averaged about 30,000 barrels per day, which is approximately 46
percent of the rated crude oil production capacity of 65,000 barrels per
day. Production is restricted by limited treatment and transportation
facilities currently available to TCO to bring the oil to world markets.
Tengiz crude oil production is currently exchanged for Russian crude which
is then exported from Russia to world markets. Natural gas, natural gas
liquids and sulfur are being sold into local markets. Over the next three
to five years, plans call for TCO to spend about $1.5 billion on expanding
production capacity and infrastructure. Current capacity is expected to
double to 130,000 barrels per day by 1995 and could reach 260,000 barrels
per day by the late 1990s. The pace of field development from 130,000 to
260,000 barrels per day is predicated on the construction of an export
pipeline system capable of handling the full production from the fields.
Negotiations to agree on terms for a pipeline project, which would be
separate from the TCO joint venture's Tengiz development project, have
proved to be very difficult, and it is currently impossible to predict
the eventual outcome or its impact on the joint venture.
In Australia, the Goodwyn Field, being developed as part of the North West
Shelf Project in which Chevron holds a one-sixth interest, is scheduled to
start production in 1994. Completion of the offshore platform, originally
scheduled for 1993, was delayed due to repair work on the piles. Upon
completion of the repair work, in first quarter 1994, the topside modules
will be installed and commissioned. Production will flow by a 30 inch
diameter pipeline to the nearby North Rankin platform and then by trunkline
to shore. The participants in the North West Shelf Project approved, in
1993, the development of the Wanaea Field, the Cossack Field, and an LPG
extraction and export project. Combined initial production from the two
oilfields is forecast at 115,000 barrels per day starting in late 1995. The
liquids-rich gas from Wanaea will be combined with gas from the North
Rankin and Goodwyn fields and processed at the onshore gas plant at
Karratha, which is being modified to allow the export sale of LPG. Two new
LPG storage tanks and a second product loading jetty are currently under
construction to handle the extra production. Following start-up in early
1996, LPG exports are expected to average 25,000 barrels per day. Drilling
and construction for the Roller/Skate oilfield development progressed
according to schedule in 1993. Production is scheduled to commence in 1994
at a peak rate of 32,000 barrels per day. Associated gas from the
Roller/Skate and Saladin fields will be piped to shore and either sold in
the Perth market or stored in the Dongara field for future sales. The
Roller/Skate development, in which Chevron holds about a 26 percent
interest, is a project of the West Australian Petroleum Pty., Ltd.
In Papua New Guinea, Chevron (19 percent interest) and its partners are
reviewing the feasibility of developing the SE Gobe Field with possible
production commencing in 1994.
In China, projects to develop the HZ/32-2 and HZ/32-3 Fields in the South
China Sea were initiated in 1993 with the awarding of the major contract.
The plan includes two platforms, 12 additional wells and a tie-in to the
existing production facility at the HZ/21-1 Field. Initial production,
expected to peak at 45,000 barrels per day, is scheduled for 1995. Chevron
holds a 16 percent interest in the venture.
Other development projects included the completion of the expanded
development of the Chichimene Field in the Llanos Basin area of Colombia.
The project included development drilling, production facilities and a 35
kilometer pipeline. Expected peak production of 10,000 barrels of oil per
day is expected in 1994. Chevron holds a 50 percent interest in the field.
- 14 -
PETROLEUM - NATURAL GAS LIQUIDS
Chevron's wholly owned Warren Petroleum Company is engaged in all phases
of the domestic natural gas liquids (NGL's) business and is the largest
U.S. wholesale marketer of natural gas liquids, selling to customers in 46
states. Warren also conducts Chevron's international liquefied petroleum
gas (LPG) trading and sales activities. Sales in 1993 totaled 287 thousand
barrels per day (includes sales of 79,000 barrels per day to Chevron
subsidiaries). Warren's business encompasses:
EXTRACTION - Warren operates 18 gas processing plants in Oklahoma, Texas,
Louisiana and New Mexico and holds equity interests in another 25 plants.
Natural gas from Chevron's and other producers' wells is piped to these
plants, where the various liquids are extracted. Gas liquids production
from these plants was 64,000 barrels per day in 1993.
FRACTIONATION - Raw natural gas liquids are collected from Warren's
processing plants, third-party purchases and Warren's gas liquids import
facility on the Houston Ship Channel and transported via pipelines to
Warren's fractionation plant at Mont Belvieu, Texas. The 220,000 barrel per
day capacity facility fractionates raw NGL's into ethane, propane, normal
butane, iso-butane and natural gasoline products. The Mont Belvieu complex
includes a 45 million barrel capacity underground gas liquids storage
facility.
DISTRIBUTION - Gas liquids are distributed to refineries, chemical
producers and independent distributors via terminals supplied by pipelines,
barges, tank cars and trucks. NGL imports and exports are handled at
Warren's marine terminal, the Warrengas Terminal, located on the Houston
Ship Channel and linked to the Mont Belvieu complex by dedicated pipelines.
In 1993, Warren continued its activities in international LPG business
development, marketing LPG for other Chevron companies in Canada, West
Africa, the U.K., and Australia. International sales more than doubled from
13,000 barrels per day in 1992 to 28,000 barrels per day in 1993.
Warren completed the construction of an underground natural gas salt dome
storage facility at Hattiesburg, Mississippi, on behalf of Chevron U.S.A.
Production Company. The five billion cubic feet storage terminal began
receiving gas deliveries in December 1993. A major expansion of the Mont
Belvieu fractionator was also completed in 1993. A new butane hydrotreating
and isomerization unit was added, increasing its fractionation capacity by
20,000 barrels per day.
The company'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)
1993 1992 1991
---- ---- ----
United States - Warren 208 191 172
United States - Other 3 3 3
---- ---- ----
Total United States 211 194 175
Canada 30 26 21
Other International 7 7 8
---- ---- ----
Total Consolidated Companies 248 227 204
==== ==== ====
---------------------------------------------------
- 15 -
PETROLEUM - RESERVES AND CONTRACT OBLIGATIONS
Table IV on pages FS-33 to FS-34 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, 1993, 1992, and 1991. During 1993, the company filed
estimates of oil and gas reserves with the Department of Energy, Energy
Information Agency. These estimates were consistent with the reserve data
reported on page FS-34 of this Annual Report on Form 10-K.
The quantities of crude oil that the company is obligated to deliver in
the future under existing contracts in the United States and
internationally, which specify delivery of fixed and determinable
quantities, are not significant in relation to the quantities available
from production of the company's proved developed reserves in those areas.
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 quantities of natural gas the company is
obligated to deliver in the future under existing contracts is not
significant in relation to the quantities available from the production of
the company's proved developed U.S. reserves in these areas. Outside the
United States, the company has contracts, principally with the State Energy
Commission of Western Australia, which have remaining obligations to
deliver 269 billion cubic feet of natural gas through 2005. The company
believes it can satisfy these contracts from quantities available from
production of the company's proved developed Australian natural gas
reserves.
PETROLEUM - REFINING
The daily refinery inputs over the last three years for the company's and
its 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, 1993
------------------ REFINERY INPUTS
OPERABLE --------------------
LOCATIONS NUMBER CAPACITY 1993 1992 1991
- ---------------------------- ------ -------- ---- ---- ----
Pascagoula, Mississippi 1 295 283 294 306
Port Arthur, Texas 1 185 177 189 195
Richmond, California 1 235 228 228 221
El Segundo, California 1 226 233 235 180
Philadelphia, Pennsylvania 1 172 184 164 162
Other* 6 282 202 201 214
-- ----- ----- ----- -----
Total United States 11 1,395 1,307 1,311 1,278
-- ----- ----- ----- -----
Burnaby, B.C., Canada 1 45 43 41 41
Milford Haven,
Wales United Kingdom 1 115 120 103 107
-- ----- ----- ----- -----
Total International 2 160 163 144 148
-- ----- ----- ----- -----
Total Consolidated Companies 13 1,555 1,470 1,455 1,426
Equity in Various
Affiliate Locations 14 492 435 399 369
-- ----- ----- ----- -----
Total Including Affiliate 27 2,047 1,905 1,854 1,795
== ===== ===== ===== =====
* Refineries in El Paso, Texas; Barber's Point, Hawaii; Salt Lake City,
Utah; Perth Amboy, New Jersey; Willbridge, Oregon; and Richmond Beach,
Washington. Inputs for the company's Nikiski, Alaska, refinery, closed in
1991, are included in the above data for 1991.
- -----------------------------------------------------------------------------
- 16 -
Based on refinery statistics published in the December 20, 1993 issue of
The Oil and Gas Journal, Chevron had the largest U.S. refining capacity and
had the fifth largest worldwide refining capacity including its share of
affiliate's refining capacity. The company wholly owns and operates 11
refineries in the United States and one each in Canada and the United
Kingdom. The company's Caltex Petroleum Corporation affiliate owns or has
interests in 14 operating refineries in Japan (4), Korea, the Philippines,
Australia, New Zealand, Bahrain, Singapore, Pakistan, Thailand, Kenya and
South Africa.
The company also owns closed refineries in Nikiski, Alaska; Cincinnati,
Ohio; and Baltimore, Maryland. Excluded from the affiliate's refineries are
3 closed refineries in Japan.
Production records were set at all locations in 1993 as refineries focused
on maximizing unit utilization. In 1993, distillation operating capacity
utilization averaged 94 percent in the United States and 95 percent
worldwide (including affiliate), compared with 90 percent in the United
States and 92 percent worldwide in 1992. Chevron's capacity utilization of
its domestic cracking and coking facilities, which are the primary
facilities used to convert heavier products to gasoline and other light
products, averaged 88 percent in 1993, unchanged from 1992.
During 1993, the company completed the first facility to use Chevron's
patented Aromax (R) technology at the Pascagoula, Mississippi refinery. This
process produces high value benzene from lower valued refining feed stock
and will facilitate the company's ability to comply with the requirement to
reduce the benzene content in motor gasoline mandated by the Clean Air Act
Amendments of 1990. At the El Paso, Texas refinery, the company entered
into an operating agreement with a neighboring refinery which allowed
Chevron, as operator, to combine the most efficient units from each
refinery in order to lower costs and increase yields. The company also
completed a $40 million facility at the Salt Lake City, Utah refinery which
will allow the company to economically manufacture ultra low sulfur diesel
fuel, one of the few such facilities in that area.
In August 1993, the company installed its proprietary Isodewaxing (R)
technology at the Richmond lube oil refining plant. This process, which
uses a new catalyst developed by the company, boosted lube oil production
by 1,500 barrels per day.
The U.S. downstream industry is going through massive recapitalization in
order to meet stringent new environmental regulations. This led to the 1993
announcement of a major restructuring of the company's downstream
operations. An integral part of this plan is to divest refineries in
Philadelphia, Pennsylvania and Port Arthur, Texas since these refineries no
longer fit in Chevron's long term plans to have a more strategically
focused U.S. refining operation and will reduce the capital expenditures
that would have been required under the 1990 amendments to the Clean Air
Act. In 1993, the company established an $837 million pre-tax provision for
the divestment of these two refineries. This charge was composed primarily
of a write-down of the refineries' facilities and related inventories to
their estimated realizable values. Also included in the charges were
provisions for environmental site assessments and employee severance. The
company has taken into account probable environmental cleanup obligations
in estimating the realizable value of the refineries. Responsibility for
these obligations will be negotiated with potential buyers. While
negotiations for the refinery sales are ongoing, it is expected that the
reserve will be sufficient to complete the restructuring. In late February
1994, the company signed a letter of intent with Sun Company, Inc. for the
sale of the Philadelphia refinery. In late March 1994, the company
announced it has entered into exclusive negotiations with Clark Refining &
Marketing, Inc. regarding the sale of its Port Arthur, Texas, refinery.
The company will invest nearly $1 billion in its Richmond and El Segundo,
California refineries over the next three years to produce reformulated
gasoline. In addition, a $300 million investment to upgrade key processing
units to improve yields of high value light products is underway at the
Richmond refinery.
At the company's Milford Haven, Wales refinery, a new isomerization unit
was brought on stream in 1993. This $54 million unit will enable the
refinery to produce a higher octane blend stock in response to increased
demand for lead-free gasoline and anticipated benzene reduction in European
gasoline.
- 17 -
In March 1994, the company announced that it will license technology and
provide engineering design for a major upgrade to the Kirishi Refinery,
operated by Kirishinefteexport, in Russia. The key refining process unit
covered by the agreement is a new hydrocracker, scheduled for startup in
mid-1999, which will use Chevron's Isocracking technology to maximize
production of middistillates such as diesel fuel and jet fuel. The company
will also provide technology to remove ammonia and hydrogen sulfide from
water used in the refining process, yielding clean water for reuse.
Caltex and its partners completed front-end engineering design of a
grassroots, 130,000 barrels per day refinery in Thailand. The engineering,
procurement and construction contract was awarded in October and the
project is on target for completion in 1996. Work continued on the
expansion/upgrade project at the Singapore export refinery. Completion of
the project, scheduled for mid-1995, will increase refining capacity by
60,000 barrels per day, increase yield of light products by 33,000 barrels
per day, and enable the refinery to produce oxygenated unleaded gasoline
and low sulfur diesel fuel. A Japanese affiliate of Caltex placed a new
residuum desulfurizer into service at the Negishi, Japan refinery. This
unit, along with the cracker unit installed last year, will allow the
refinery to increase yields of higher-value products and reduce dependence
on low sulfur crudes.
PETROLEUM - REFINED PRODUCTS MARKETING
PRODUCT SALES: The company and its affiliates, primarily Caltex Petroleum
Corporation, sell petroleum products throughout much of the world. The
principal trademarks for identifying these products are "Chevron", "Gulf"
(principally in the United Kingdom) and "Caltex". Domestic sales volumes of
refined products by the company during 1993 amounted to 1,423 thousand
barrels per day, equivalent to approximately nine percent of total U.S.
consumption. Worldwide sales volumes, including the company's share of
affiliates' sales, averaged 2,346 thousand barrels per day in 1993, an
increase of about one percent over 1992.
The following table shows the company's and its affiliates' refined
product sales volumes, excluding intercompany sales, over the past three
years.
--------------------------------------------------------
REFINED PRODUCTS SALES VOLUMES
(Thousands of Barrels Per Day)
1993 1992 1991
----- ----- -----
UNITED STATES
Gasolines 652 646 632
Gas Oils and Kerosene 325 347 312
Jet Fuel 247 252 249
Residual Fuel Oil 94 110 145
Other Petroleum Products* 105 115 106
----- ----- -----
Total United States 1,423 1,470 1,444
----- ----- -----
INTERNATIONAL
United Kingdom 111 108 110
Canada 50 39 38
Other International 168 147 142
----- ----- -----
Total International 329 294 290
----- ----- -----
Total Consolidated
Companies 1,752 1,764 1,734
Equity in Affiliate 594 565 533
----- ----- -----
Total Including
Affiliate 2,346 2,329 2,267
===== ===== =====
* Principally naphtha, lubes, asphalt and coke.
--------------------------------------------------------
- 18 -
The company's Canadian sales volumes consist of refined product sales in
British Columbia and Alberta by the company's Chevron Canada Ltd.
subsidiary. In the United Kingdom, the sales volumes reported comprise a
full range of product sales by the company's Gulf Oil (Great Britain) Ltd.
subsidiary. The 1993 volumes reported for "Other International" relate
primarily to international sales of aviation, marine fuels, and refined
products in Latin America, the Far East and elsewhere. The equity in
affiliates' sales in 1993 consist primarily of the company's interest in
Caltex Petroleum Corporation, which operates in 63 countries including
Australia, the Philippines, New Zealand, South Africa and, through Caltex
affiliates, in Japan and Korea.
The company introduced several new products in 1993. In September, the
company began delivering JP-8, a kerosene-based jet fuel, to the U.S.
military. Over the next two years, JP-8, a safer and more versatile fuel,
capable of powering tanks, trucks and other military vehicles, will phase
out naphtha-based JP-4. In October, low aromatics diesel fuel in California
and ultra low sulfur diesel fuel in the rest of the country were introduced
to comply with various federal and state air quality regulations.
Reformulated heavy duty motor oils that meet the needs of low sulfur diesel
fuel users were also introduced nationwide in October.
RETAIL OUTLETS: In the United States, the company supplies, directly or
through jobbers, over 9,000 motor vehicle, aircraft and marine retail
outlets, including more than 2,400 company-owned or -leased motor vehicle
service stations. The company's gasoline market area is concentrated in the
Southeastern, South Central and Western states. Chevron is among the top
three marketers in 16 states. During 1993, the company completed the
acquisition and brand conversion of 55 service stations in south Florida
that were acquired from Exxon in exchange for comparable properties in the
Baltimore-Washington D.C.-Eastern Virginia areas. Chevron branded retail
fuel sales in Arkansas, Western Kentucky and Western Tennessee were
discontinued in 1993.
In 1993, Chevron introduced a "Direct Mail Marketing" and a "Premium Card"
program to credit card customers. The company also expanded its "Fast Pay"
system by approximately 400 stations in 1993, to a total of over 1,300
stations nationwide. This automated system allows credit card customers to
pay at the pump with credit approvals processed in about five seconds using
satellite data transmission. During 1993, the company outsourced
purchasing, warehousing and distribution responsibilities for its Tire,
Batteries and Accessories business (TBA).
Internationally, the company's branded products are sold in 214 owned or
leased stations in British Columbia, Canada and in 467 (230 owned or
leased) stations in the United Kingdom. In 1993, the company completed the
sale of its retail marketing operations in Guatemala, El Salvador and
Nicaragua.
PETROLEUM - TRANSPORTATION
TANKERS: Chevron's controlled seagoing fleet at December 31, 1993 is
summarized in the following table. All controlled tankers were utilized in
1993.
- -----------------------------------------------------------------------------
CONTROLLED TANKERS AT DECEMBER 31, 1993
U.S. FLAG FOREIGN FLAG
----------------------------- ------------------------------
CARGO CAPACITY CARGO CAPACITY
NUMBER (millions of barrels) NUMBER (millions of barrels)
------ --------------------- ------ ---------------------
Owned - - 26 27
Bareboat
Charter 7 2 6 11
Time Charter - - 9 5
---- ---- ---- ----
Total 7 2 41 43
==== ==== ==== ====
- -----------------------------------------------------------------------------
- 19 -
Federal law requires that cargo transported between domestic 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 1993, 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 1993, two of the company's controlled international flag
vessels were being used for floating storage. The remaining international
flag vessels were engaged primarily in transporting crude oil from the
Middle East, Indonesia, Mexico, West Africa and the North Sea to ports in
the United States, Europe, the United Kingdom, and Asia. Refined products
also were transported worldwide.
In addition to the tanker fleet summarized in the table on page 19, the
company owns a one-sixth undivided interest in each of five liquefied
natural gas (LNG) ships that are bareboat chartered to the Australian
North West Shelf Project. These ships, along with two time chartered LNG
vessels, transport LNG from Australia to eight Japanese gas and electric
utilities. One additional LNG ship has been ordered with delivery expected
in late 1994.
In 1993, the company took delivery of one 1.1 million and two 1.0 million
barrel capacity, double hull tankers and sold two 1.2 million and two 3.2
million barrel capacity tankers. The company also took delivery of a 1.0
million barrel capacity tanker, the Chevron Employee Pride, in February
1994 and expects to take delivery of an additional 1.0 million barrel
capacity tanker in October 1994. During 1993, the company reduced its time
chartered fleet by a net one tanker and 1.0 million barrels of capacity.
Page 24 of this Annual Report on Form 10-K contains a discussion of the
effects of the Federal Oil Pollution Act on the company's shipping
operations.
PIPELINES: Chevron owns and operates an extensive system of domestic crude
oil, refined products and natural gas pipelines. The company also has
direct or indirect interests in other domestic and international pipelines.
The company's ownership interests in pipelines are summarized in the
following table:
-----------------------------------------------------------
PIPELINE MILEAGE AT DECEMBER 31, 1993
WHOLLY PARTIALLY
OWNED OWNED (1) TOTAL
----- ----- ------
UNITED STATES:
Crude oil (2) 5,696 624 6,320
Natural gas 569 44 613
Petroleum products 3,709 1,610 5,319
----- ----- ------
Total United States 9,974 2,278 12,252
----- ----- ------
INTERNATIONAL:
Crude oil (2) - 747 747
Natural gas - 197 197
Petroleum products 12 130 142
----- ----- ------
Total International 12 1,074 1,086
----- ----- ------
Worldwide 9,986 3,352 13,338
===== ===== ======
(1) Reflects equity interest in lines.
(2) Includes gathering lines related to the transportation
function. Excludes gathering lines related to the
production function.
-----------------------------------------------------------
- 20 -
CHEMICALS
The company's Chevron Chemical Company subsidiary manufactures and markets
chemical products for industrial use. The chemical industry, historically,
has been cyclical and is highly competitive. Since its last peak in the
late 1980s, industry conditions have deteriorated as ample supplies, caused
by production overcapacity, have exerted downward pressure on prices. In
the past four years, weak demand due to U.S. and worldwide recessions has
further weakened prices.
At year-end 1993, Chevron Chemical Company owned and operated 24 U.S.
manufacturing facilities in 12 states, owned manufacturing facilities in
Brazil and France, and owned a majority interest in a manufacturing
facility in Japan. The principal domestic plants are located at Cedar
Bayou, Orange and Port Arthur, Texas; St. James and Belle Chasse,
Louisiana; Philadelphia, Pennsylvania; Marietta, Ohio; Pascagoula,
Mississippi; St. Helens, Oregon; and Richmond, California. The following
table shows, by chemical division, 1993 revenues and the number of owned or
majority owned chemical manufacturing facilities and combined operating
capacities as of December 31, 1993.
- -----------------------------------------------------------------------------
CHEMICAL OPERATIONS
MANUFACTURING
FACILITIES 1993
------------------- ANNUAL REVENUE (1)
DIVISION U.S. INTERNATIONAL CAPACITY ($ MILLIONS)
- --------------------- ---- ------------- ------------------- ------------
Olefins and
Derivatives 12 - 6,990 million lbs. $1,003
Aromatics and
Derivatives 7 - 6,570 million lbs. 718
Oronite Additives 2 3 160 million gal. 746
Fertilizers 2 - (2) 86
Consumer Products 1 - (2) 133
Other
(including excise
taxes) - - (2) 37
-- - ------
Totals 24 3 $2,723
== = ======
(1) Excludes intercompany sales.
(2) No meaningful common measurement.
- -----------------------------------------------------------------------------
The company divested its last major asset in the agricultural-related
chemical business with the sale of its ORTHO consumer products division, a
leading supplier of lawn and garden products in the United States, to
Monsanto Company in 1993. The sale was the result of studies that concluded
that the company's agricultural-related businesses were non-competitive or
were non-core. The company decided to divest those businesses and focus its
attention on areas of strength - petrochemicals, plastics and additives.
Construction was completed during 1993 on the first U.S. benzene
manufacturing plant using the company's proprietary Aromax (R) technology at
the Pascagoula, Mississippi refinery. This technology will enable Chevron
to produce high-value benzene from certain low-value by-products of the oil
refining process. Benzene is a prime building block for a wide range of
consumer products such as sporting goods, nylon, laundry detergent,
children's toys and automobile tires.
In March 1993, the company announced that a letter of intent had been
signed with the Saudi Venture Capital Group, a consortium of Saudi Arabian
business leaders, to develop an aromatics facility in Jubail, Saudi Arabia,
if necessary Saudi government approval can be obtained. The planned
facility would be owned and operated by a newly formed joint venture
company. This joint company, owned on an equal basis by Chevron and the
Saudi group, would market within Saudi Arabia, while Chevron would market
all products outside Saudi Arabia. The facility will utilize Chevron's
patented Aromax (R) reforming technology and have a capacity of 420,000 tons
of benzene per year and 270,000 tons of cyclohexanes per year. The project
is currently delayed while the Saudi government revises its petrochemical
investment policy. The company is also in the early stages of examining
opportunities to employ the Aromax (R) technology in Asia, where chemical
demand is growing rapidly.
- 21 -
In January 1994, the company announced a cost-reduction plan intended to
reduce annual operating expense by approximately $100 million by 1996.
Major elements of the plan include completing the divestiture of the
company's agricultural businesses, including the closing of the consumer
products plant in Maryland Heights, Missouri and the sale of the fertilizer
plant in St. Helens, Oregon; the sale of Chevron's asphalt business in
Brazil; closing of the company's oil-field chemical business; reorganizing
the Oronite Additives Division into global regions; and streamlining and
reducing costs at the company's three largest plants in Cedar Bayou and
Orange, Texas, and Belle Chasse, Louisiana.
An agreement was reached in March 1994 with Institut Francais du
Petrole to jointly develop a new high-purity paraxylene technology called
Eluxyl. If the demonstration unit using this new technology, to be
constructed and operated at Chevron's Pascagoula, Mississippi, refinery,
proves successful, the company plans to integrate the technology at
Pascagoula and expand its paraxylene activities worldwide.
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 and operated four surface
and three underground mines at year-end 1993. Three of the mines are
located in New Mexico and one each in Alabama, Wyoming, Kentucky and
Colorado. All of the mines produce steam coal used primarily for electric
power generation. P&M's strategy is to focus on regional markets in the
United States, capitalizing on major utility growth markets in the West and
Southeast. Approximately 88 percent of P&M's coal sales are made to
electric utilities. Sales of coal from P&M's wholly-owned mines and from
its 50 percent interest in Black Beauty Coal Company were 20.8 million tons
in 1993, an increase of 26 percent over 1992. About 57 percent of these
sales came from two mines, the McKinley Mine in New Mexico and the Kemmerer
Mine in Wyoming. The average selling price for coal from mines owned and
operated by P&M was $24.62 per ton in 1993, contributing $426 million to
Chevron's consolidated sales and other operating revenues. At year-end
1993, P&M controlled approximately 560 million tons of developed and
undeveloped coal reserves.
Demand growth for coal in the U.S. remains largely dependent on the demand
for electric power, which in turn depends on regional and national economic
conditions and on competition from other fuel sources. Although coal-fired
generation of electricity grew during 1993, competition among coal
producers kept downward pressure on regional coal prices during much of the
year. However, in the East, a prolonged strike by United Mine Workers of
America restricted coal production, tightening coal supplies and driving up
spot market prices in the latter half of the year. P&M sells about 88
percent of its coal production under multi-year supply agreements, so it is
not particularly exposed to short-term fluctuations in market prices.
P&M controls a significant inventory of low-sulfur coal reserves, and the
company expects demand for this type of coal to grow as utilities start to
implement programs to comply with the air quality emission standards of the
Clean Air Act Amendments of 1990. In addition, P&M anticipates that the
Energy Policy Act of 1992 will increase competition in the electric power
market and will provide new market opportunities for low-cost coal
producers.
OTHER MINERALS: P&M manages the company's investments in non-coal minerals.
The company expressed its long-term intention to exit the non-coal minerals
business, and most such assets have been sold in recent years. The principal
assets remaining are a 50 percent interest in the Stillwater Mining Company,
a Montana platinum-palladium mining operation, and a 52.5 percent interest in
some zinc-lead prospects in Ireland. The company's share of sales and other
revenues from non-coal operations was approximately $21 million in 1993. The
sale of the company's 52.5 percent holding in the Irish zinc-lead prospects
has been delayed due to legal challenges. The company expects these challenges
to be resolved and the sale completed during 1994.
REAL ESTATE
The company's real estate activities are carried out primarily through its
wholly owned subsidiaries, Chevron Land and Development Company and Huntington
Beach Company (collectively, Chevron Land).
- 22 -
Their activities have concentrated on converting Chevron's surplus fee
production properties in California into residential and commercial real
estate. After making major infrastructure improvements, the properties are
sold to third parties or jointly developed. At the end of 1993, Chevron
Land managed over 26,000 acres of real estate in California.
Chevron Land participates in residential developments through partnerships
with home builders. During 1993, the company sold approximately 160 homes
in California. Although this represents a 78 percent increase from the 90
homes sold in 1992, the California housing market continues to be weak as
California lags the rest of the nation in realizing significant renewed
economic growth. The company anticipates that the California real estate
market will not begin to recover until late 1994 at the earliest and is
currently positioning itself to take advantage of the recovery when it
occurs by developing properties at a pace that meets market demand while
preserving current real estate development entitlements. Ten residential
housing projects were actively being developed at year-end, eight through
joint venture partnerships.
Although Chevron's current development emphasis is on the residential
sector, the Company also participates in commercial real estate investment
and development activities. The Montebello Town Square in Southern
California, a 250,000 square foot community shopping center situated on 20
acres of a former oil field, was sold by the company in 1993. The company
also leases approximately 70,000 acres of irrigated farmland and 160,000
acres of rangeland to local growers and ranchers in California's San
Joaquin Valley. In 1993, Chevron Land restructured its organization by
reducing its workforce 20 percent and closing or consolidating 5 of its
offices. Currently, Chevron Land's activities are predominately handled by
the company's offices in Newport Beach and San Francisco, California.
RESEARCH AND ENVIRONMENTAL PROTECTION
RESEARCH: The company's principal research laboratories are at Richmond
and La Habra, California. The Richmond facility engages in research on new
and improved refinery processes, develops petroleum and chemical products,
and provides technical services for the company and its customers. The La
Habra facility conducts research and provides technical support in geology,
geophysics and other exploration science, 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 1993 numbered approximately 2,400.
In January 1994, the company signed an agreement with China National
Petroleum Corporation to provide enhanced oil recovery technology for
testing in Daqing, China's largest oil field. The technology, called
"microbial profile modification," consists of pumping bacterial spores and
nutrients into a reservoir to plug off highly permeable zones in order to
improve the sweep efficiency of a waterflood. The agreement calls for 15
months of testing in Chevron Petroleum Technology Company's labs in La
Habra, California, followed by a two year pilot program in Daqing.
Chevron's research and development expenses were $206, $229, and $250
million for the years 1993, 1992, and 1991, respectively.
The company owns, controls, or is licensed under numerous patents, but its
business is not dependent upon patents. Licenses under the company's
patents are generally made available to others in the petroleum and
chemical industries.
ENVIRONMENTAL PROTECTION: One of Chevron's ongoing corporate strategies is
to give high priority to environmental, public and governmental concerns.
Chevron's revised corporate policy on Health, Environment and Safety was
approved by the Stockholders in 1991. In 1992, a comprehensive series of
101 management practices was approved by senior management to strengthen
the implementation of the policy. The program is called "Protecting People
and the Environment" and is modeled after the Chemical Manufacturers
Associations' program called "Responsible Care." It is also similar to the
American Petroleum Institute's program called "Strategies for Today's
Environmental Partnership." The program also encompasses previous company
programs to control pollution such as the SMART (Save Money and Reduce
Toxics) program which focuses on routine, process related, hazardous waste.
- 23 -
The company's oil and gas exploration activities, along with many other
petroleum companies, have been hampered by drilling moratoria, imposed
because of environmental concerns, in areas where the company has leasehold
interests, particularly Alaska, offshore Florida and offshore California.
Difficulties and delays in obtaining necessary permits because of
environmental concerns, such as those experienced by Chevron and its
partners in the Point Arguello Field offshore California, can delay or
restrict oil and gas development projects. While events such as these can
impact current and future earnings, either directly or through lost
opportunities, the company does not believe they will have a material
effect on the company's consolidated financial position, its liquidity, or
its competitive position relative to other domestic or international
petroleum concerns. The situation has, however, been a factor, among
others, in the shift of the company's exploration efforts to areas outside
of the United States.
The company will spend an estimated $1.1 billion in capital expenditures
over the next 5 years on its refining facilities in order to comply with
federal and state clean air regulations and to provide consumers with fuels
that reduce air pollution and air toxicity. The Clean Air Act Amendments of
1990 (CAAA) requires the production of reformulated gasoline (RFG).
Beginning in January 1995, only RFG may be sold in the nine worst ozone
areas in the United States. In addition, the California Air Resources Board
(CARB) requires a more stringent reformulated gasoline to be sold statewide
beginning in March 1996. CAAA required a significant decrease in the sulfur
content of diesel fuel sold in U.S. markets beginning October 1993. CARB,
in addition to the federal requirements, also mandated a reduction in the
aromatics content of diesel fuel sold in California. Chevron introduced low
aromatics diesel fuel in California and ultra low sulfur diesel fuel in the
rest of the nation in October 1993.
The Federal Oil Pollution Act of 1990 (OPA) expanded federal authority to
direct responses to oil spills to improve preparedness and response
capabilities and to impose penalties on spillers for restoration costs and
loss of use of the resources during restoration. OPA also requires the
phase out of single hull tankers and the phase in of double hull tankers
for trading to U.S. ports. Many of the coastal states have enacted or are
preparing legislation in these same areas. In 1990, the company began a
fleet modernization program, which included seven double hull tankers for
delivery during the 1992-1994 period. Six of these tankers have been
delivered through the first week of March 1994. The company has been
actively involved in the Marine Preservation Association, a non-profit
organization that funds the Marine Spill Recovery Corporation (MSRC). MSRC
owns the largest stockpile of oil spill response equipment in the nation
and operates five strategically located U.S. coastal regional centers.
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 anticipates that these costs will not have a
material impact on its consolidated financial position, its liquidity, or its
competitive position in the industry.
During 1993, the company's U.S. capitalized environmental expenditures were
$620 million, representing approximately 31 percent of the company's total
consolidated U.S. capital and exploratory expenditures. The company's U.S.
capitalized environmental expenditures were $430 million and $284 million in
1992 and 1991, 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 service stations.
For 1994, the company estimates that capital expenditures for environmental
control facilities will be approximately $637 million. The actual
expenditures for 1994 will depend on various conditions affecting the
company's operations and may differ significantly from the company's forecast.
The company is committed to protecting the environment wherever it operates,
including strict compliance with all governmental regulations. The future
annual capital costs of fulfilling this commitment are uncertain, but for the
next several years are expected to continue at current levels.
- 24 -
Under provisions of the Superfund law, Chevron has been designated as a
potentially responsible party (PRP) for remediation of a portion of 223
hazardous waste sites. Since remediation costs will vary from site to site
as well as 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. At year-end 1993, the
company's environmental remediation reserve related to Superfund sites
amounted to $56 million. The largest of these sites, located in California,
accounts for approximately 20 percent of the reserve.
The company's 1993 environmental expenditures, remediation provisions and
year-end environmental reserves are discussed on pages FS-3 through FS-4 of
this Annual Report on Form 10-K. These pages also contain additional
discussion of the company's liabilities and exposure under the Superfund
law and additional discussion of the effects of the Clean Air Act
Amendments of 1990.
ITEM 2. PROPERTIES
The location and character of the company's oil and gas and minerals and
real estate properties and its refining, marketing, transportation and
chemical facilities are described above under Item 1. Business and
Properties. 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-30 to FS-35 of this Annual
Report on Form 10-K. Note 12 "Properties, Plant and Equipment" to the
company's financial statements contained on page FS-24 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
expenses, by geographic area and industry segment, for 1993, 1992 and 1991.
ITEM 3. LEGAL PROCEEDINGS
A. Cities Service Tender Offer Cases.
The complaint by Cities Service Co. ("Cities Services") and two individual
plaintiffs was originally filed in August 1982 in Oklahoma state court in
Tulsa. Prior proceedings have effectively eliminated the two individual
plaintiffs as parties. The defendants were initially Gulf Oil Corporation
and GOC Acquisition Corporation. Subsequent filings have identified Chevron
U.S.A. Inc. as the successor in interest to Gulf Oil Corporation. In the
original complaint Cities Service pleaded for damages of not less than $2.7
billion together with legal interest for breach of contract and
misrepresentation. The great bulk of the damages were related to claims on
behalf of shareholders of Cities Service. All of the claims by Cities
Service shareholders have now been resolved and will ultimately be
dismissed.
Plaintiff Cities Service has now made new claims by way of a motion to
amend the petition, which motion was submitted for ruling on February 28,
1994, but has not yet been ruled on by the court. The amended pleading adds
Oxy U.S.A. as the successor to plaintiff Cities Service, adds Chevron
U.S.A. Inc. (as successor to Gulf Oil Corporation) and adds Chevron
Corporation as a new defendant. In addition to the existing claims for
breach of contract and fraud, the amendments add the following causes of
action: for willful and malicious breach of contract, negligent
misrepresentation, interference with prospective economic advantage in
connection with the 1989 proposed Oxy-Cities DOE settlement, and adds the
claimed DOE liability as additional contract damages and as additional
fraud damages. The proposed amendment also adds a claim for punitive
damages based upon the alleged fraud, negligent misrepresentation, willful
breach and interference claims. The new claim requests not less than $100
million on each of the several claims, together with pre-judgment interest
and punitive damages. It also requests $12 million plus prejudgment
interest for Cities' costs in defending against DOE proceedings since 1989,
and an order entitling Cities Services to recover such "restitutionary
obligation" amounts ultimately paid by Oxy U.S.A. to the DOE in excess of
its proposed 1989 DOE settlement, and punitive damages.
- 25 -
B. In re Gulf Pension Litigation.
In two lawsuits, which were commenced on December 2, 1986 and April 24,
1987 and consolidated on July 17, 1987 in the U.S. District Court for the
Southern District of Texas as In re Gulf Pension Litigation, former
employees of Gulf Oil Corporation who were participants in the Gulf Pension
Plan contend that a partial termination of the Gulf Pension Plan has
occurred and they are entitled to immediate vesting and distribution of
plan benefits and to distribution of alleged excess plan assets, which it
is alleged have been unlawfully seized by Gulf or Chevron. The action is
brought under the Employee Retirement Income Security Act of 1974 and
common law, and is primarily an action for damages. Defendants have filed
an answer denying plaintiffs' allegations. On August 21, 1987, the Court
certified a class on these issues consisting of "all former members of the
Gulf Pension Plan and the spouses or the beneficiaries of such members." On
January 4, 1990, the Court certified a subclass of plaintiffs who also
contend that Chevron unlawfully denied them benefits due upon their alleged
involuntary termination. A partial settlement agreement was reached during
trial on November 19, 1990 and approved by the court at a January 25, 1991
hearing.
On April 10, 1991, the Court issued its opinion on the remaining issues in
the case. The Court ruled that partial terminations of the Gulf Pension
Plan occurred, and ordered all participants in the plan as of July 1, 1986
to be vested in their benefits under the plan. The Court also ruled that
participants in the Gulf Contributory Retirement Plan ("CRP") and the
Supplemental Annuity Plan of Mene Grande Oil Company ("SAP") were entitled
to the surplus assets of those plans. However, the Court ruled that
Chevron, otherwise, has the right to retain surplus funds remaining in the
Gulf Pension Plan after all obligations to the Plan Participants have been
satisfied. Accordingly, the Court found no impropriety in the merger of the
Gulf Pension Plan into the Chevron Retirement Plan or the use of plan
assets to fund a special early retirement program and pension supplement.
However, the Court did rule that Gulf and Chevron had incorrectly paid
certain investment management fees out of plan assets and had incorrectly
received a benefit from the use of pension plan assets in the negotiation
of a divestiture sale agreement.
On October 15, 1991, the court approved the terms of a second partial
settlement agreement. As a part of the second partial settlement, the
parties agreed not to appeal the partial termination issues except as
relevant to plaintiff's claim that they are entitled to surplus Gulf
Pension Plan assets that are not attributable to CRP/SAP. The second
partial settlement does not affect the court's ruling that the plaintiffs
are not entitled to approximately $620 million in surplus funds in the Gulf
Pension Plan. Plaintiffs have appealed this part of the case to the Fifth
Circuit Court of Appeals. Chevron has appealed the ruling that it
incorrectly paid management fees out of the plan's assets and that it
received a benefit from the use of pension funds. On April 29, 1993 Chevron
reached a settlement with the Internal Revenue Service regarding these
issues, which included a payment to the Chevron Retirement Plan and a
payment of excise taxes. Subsequently, Chevron's appeal was dismissed by
the court, although the underlying judgement was not vacated.
C. Clean Water Act Violations.
On September 23, 1993, the Environmental Protection Agency (EPA)
instituted an administrative proceeding seeking civil penalties in excess
of $100,000 from the company for its self-reported violations of the Clean
Water Act since July 1986 at production facilities located on the Outer
Continental Shelf of the Gulf of Mexico. The company has agreed with the
EPA to settle this matter for $121,000.
D. Premanufacture Notifications for Detergent Additives.
On September 30, 1993, the EPA instituted an administrative proceeding
seeking civil penalties of about $17 million from the company for alleged
violations of the Toxic Substances Control Act (TSCA). The EPA contends
that the company was required to file Premanufacture Notifications (PMNs)
with regard to six chemical substances manufactured or imported since 1990.
The company believes that no PMNs were required because the chemicals were
within the scope of existing TSCA inventory listings. Nevertheless, the
company reported the situation to the EPA when it was advised by a third
party that the EPA may, without public notice, have revised its
interpretation of TSCA regulations to require PMNs to be filed in such
circumstances. Thereafter, under protest, the company suspended the
production and importation of the
- 26 -
chemicals and filed PMNs for them, continuing the suspension for the
90-day period contemplated by TSCA. The detergents in question are very
similar to common detergents and intermediates used in their production,
and the EPA does not appear to claim that failure to file a PMN resulted in
any health or safety risk. The EPA permitted the company to dispose of its
current stocks of the chemicals during the period that the company
suspended their production and importation.
E. El Segundo Refinery Reformulated Gasoline Project.
On September 22, 1993, the EPA instituted an administrative proceeding
contending that the company had not received a permit required under the
Clean Air Act Amendments of 1990 (CAAA) for field activities at the El
Segundo refinery relating to the production of reformulated gasolines,
which will be federally mandated by 1995 under other provisions of the
CAAA. All company activities had been conducted in accordance with
authorization by the South Coast Air Quality Management District (SCAQMD),
the primary enforcing agency of the rule that the EPA contends the company
violated. EPA efforts to cause the company to cease all construction
activities were stayed by the Ninth Circuit Court of Appeals, and SCAQMD
has since issued the company a formal permit to construct. However, the EPA
may continue to seek civil penalties from the company for activities
conducted prior to the issuance of the permit.
Other previously reported legal proceedings have been settled or the
issues resolved so as not to merit further reporting.
- 27 -
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted during the fourth quarter of 1993 to a vote of
security holders through the solicitation of proxies or otherwise.
EXECUTIVE OFFICERS OF THE REGISTRANT AT MARCH 1, 1994
MAJOR AREA OF
NAME AND AGE EXECUTIVE OFFICE HELD RESPONSIBILITY
- ------------------- -------------------------------- ----------------------
K.T. Derr 57 Chairman of the Board since 1989 Chief Executive
Director since 1981 Officer
Executive Committee Member
since 1986
J.D. Bonney 63 Vice-Chairman of the Board Worldwide Exploration
since 1987 and Production
Director and Executive Activities, Pipe-
Committee Member since 1986 lines, Coal and
Other Minerals,
Administrative
Services, Aircraft
Services
J.N. Sullivan 56 Vice-Chairman of the Board Worldwide Refining,
since 1989 Marketing and Trans-
Director since 1988 portation Activities,
Executive Committee Member Chemicals,
since 1986 Real Estate,
Environmental,
Human Resources,
Research
W.E. Crain 64 Vice-President since 1986 Worldwide Exploration
Director and Executive and Production
Committee Member since 1988
R.E. Galvin 62 Vice-President since 1988 U.S. Exploration
President of Chevron U.S.A. and Production
Production Company since 1992
Executive Committee Member
since 1993
D.R. Hoyer 62 Vice-President since 1987 U.S. Refining,
President of Chevron U.S.A. Marketing and
Products Company since 1992 Supply
Executive Committee Member
since 1993
M.R. Klitten 49 Vice-President since 1989 Finance
Executive Committee Member
since 1989
R.H. Matzke 57 Vice-President since 1990 Overseas Exploration
President of Chevron Overseas and Production
Petroleum Inc. since 1989
Executive Committee Member
since 1993
J.E. Peppercorn 56 Vice-President since 1990 Chemicals
President of Chevron Chemical
Company since 1989
Executive Committee Member
since 1993
H.D. Hinman 53 Vice-President and General Law
Counsel since 1993
Executive Committee Member
since 1993
- 28 -
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. Messrs. Galvin, Hoyer, Matzke and
Peppercorn are rotating members of the Executive Committee, with two serving
at any one time.
R.E. Galvin - Regional Vice-President, Exploration, Land and
Production, Chevron U.S.A. Inc. - 1985
- Vice-President, Chevron Corporation and
Senior Vice-President, Exploration, Land and
Production, Chevron U.S.A. Inc. - 1988
- President, Chevron U.S.A. Production Company
(a Division of Chevron U.S.A. Inc.) - 1992
H.D. Hinman - Partner, Law Firm of Pillsbury Madison &
Sutro - 1973
- Vice-President and General Counsel,
Chevron Corporation - 1993
M.R. Klitten - Comptroller, Chevron U.S.A. Inc. - 1985
- President, Chevron Information Technology
Company - 1987
- Vice-President for Finance, Chevron Corporation - 1989
R.H. Matzke - President, Chevron Canada Resources Limited - 1986
- President, Chevron Overseas Petroleum Inc. - 1989
- Vice-President, Chevron Corporation and President,
Chevron Overseas Petroleum Inc. - 1990
J.E. Peppercorn - Senior Vice-President, Chevron Chemical Company - 1986
- President, Chevron Chemical Company - 1989
- Vice-President, Chevron Corporation and President,
Chevron Chemical Company - 1990
- 29 -
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-12 of this Annual Report on Form 10-K.
ITEM 6. SELECTED FINANCIAL DATA
The selected financial data for years 1989 through 1993 are presented on page
FS-36 of this Annual Report on Form 10-K.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Indexes to Financial Statements, Supplementary Data and Management's
Discussion and Analysis of Financial Condition and Results of Operations are
presented on page 41 of this Annual Report on Form 10-K.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Indexes to Financial Statements, Supplementary Data and Management's
Discussion and Analysis of Financial Condition and Results of Operations are
presented on page 41 of this Annual Report on Form 10-K.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information on Directors on page 4 through 6 of the Notice of Annual
Meeting of Stockholders and Proxy Statement dated March 25, 1994, is
incorporated herein by reference in this Annual Report on Form 10-K.
See Executive Officers of the Registrant on pages 28 and 29 of this Annual
Report on Form 10-K for information about executive officers of the company.
There was no late filing or failure by an insider to file a report required
by section 16 of the Exchange Act.
ITEM 11. EXECUTIVE COMPENSATION
The information on pages 15 through 17 of the Notice of Annual Meeting of
Stockholders and Proxy Statement dated March 25, 1994, 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 pages 2 and 3 of the Notice of Annual Meeting of
Stockholders and Proxy Statement dated March 25, 1994, 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.
- 30 -
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-13
Consolidated Statement of Income
for the three years ended December 31, 1993 FS-14
Consolidated Balance Sheet at December 31,
1993 and 1992 FS-15
Consolidated Statement of Cash Flows
for the three years ended December 31, 1993 FS-16
Consolidated Statement of Stockholders' Equity
for the three years ended December 31, 1993 FS-17
Notes to Consolidated Financial Statements FS-18 to FS-29
(2) FINANCIAL STATEMENT SCHEDULES:
Report of Independent Accountants on
Financial Statement Schedules 35
Schedule V - Property, Plant and Equipment 36
Schedule VI - Accumulated Depreciation, 37
Depletion and Amortization of Property,
Plant and Equipment
Caltex Group of Companies Combined
Financial Statements and Schedules C-1 to C-21
The Combined Financial Statements and Schedules of the Caltex Group
of Companies are filed as part of this report and follow the
Five-Year Financial Summary (page FS-36). All other schedules are
omitted because they are not applicable or the required information
is included in the consolidated financial statements or notes
thereto.
(3) EXHIBITS:
The Exhibit Index on pages 33 and 34 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:
The company filed no reports on Form 8-K during the fourth quarter
of 1993 and through March 30, 1994.
- 31 -
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 30th day
of March 1994.
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 30th day of March 1994.
PRINCIPAL EXECUTIVE OFFICERS DIRECTORS
(AND DIRECTORS)
KENNETH T. DERR* SAMUEL H. ARMACOST*
- ------------------------------------- --------------------------------------
Kenneth T. Derr, Samuel H. Armacost
Chairman of the Board
J. DENNIS BONNEY* WILLIAM E. CRAIN*
- ------------------------------------- --------------------------------------
J. Dennis Bonney, William E. Crain
Vice-Chairman of the Board
JAMES N. SULLIVAN* SAM GINN*
- ------------------------------------- --------------------------------------
James N. Sullivan, Sam Ginn
Vice-Chairman of the Board
CONDOLEEZZA RICE*
--------------------------------------
PRINCIPAL FINANCIAL OFFICER Condoleezza Rice
MARTIN R. KLITTEN* S. BRUCE SMART, JR.*
- ------------------------------------- --------------------------------------
Martin R. Klitten, S. Bruce Smart, Jr.
Vice-President, Finance
JOHN A. YOUNG*
--------------------------------------
John A. Young
PRINCIPAL ACCOUNTING OFFICER
DONALD G. HENDERSON* GEORGE H. WEYERHAEUSER*
- ------------------------------------- --------------------------------------
Donald G. Henderson, George H. Weyerhaeuser
Vice-President and Comptroller
*By: MALCOLM J. McAULEY
--------------------------------
Malcolm J. McAuley,
Attorney-in-Fact
- 32 -
EXHIBIT INDEX
EXHIBIT
NO. DESCRIPTION
- ------- --------------------------------------------------------------------
3.1 Restated Certificate of Incorporation of Chevron Corporation, dated
November 23, 1988, filed as Exhibit 3.1 to Chevron Corporation's
Annual Report on Form 10-K for 1989, and incorporated herein by
reference.
3.2 By-Laws of Chevron Corporation, as amended December 7, 1989,
including provisions giving attorneys-in-fact authority to sign on
behalf of officers of the corporation, filed as Exhibit 3.2 to
Chevron Corporation's Annual Report on Form 10-K for 1989, and
incorporated herein by reference.
4.1 Rights Agreement dated as of November 22, 1988 between Chevron
Corporation and Manufacturers Hanover Trust Company of California,
as Rights Agent, filed as Exhibit 4.0 to Chevron Corporation's
Current Report on Form 8-K dated November 22, 1988, and incorporated
herein by reference.
4.2 Amendment No. 1 dated as of December 7, 1989 to Rights Agreement
dated as of November 22, 1988 between Chevron Corporation and
Manufacturers Hanover Trust Company of California, as Rights Agent,
filed as Exhibit 4.0 to Chevron Corporation's Current Report on Form
8-K dated December 7, 1989, 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 January 1, 1990, filed as Exhibit 10.1 to Chevron
Corporation's Annual Report on Form 10-K for 1990, and incorporated
herein by reference.
10.2 Management Contingent Incentive Plan of Chevron Corporation, as
amended May 2, 1989, filed as Exhibit 10.2 to Chevron Corporation's
Annual Report on Form 10-K for 1989, and incorporated herein by
reference.
10.3 Chevron Corporation Excess Benefit Plan, amended and restated as of
July 1, 1990, filed as Exhibit 10.3 to Chevron Corporation's Annual
Report on Form 10-K for 1990, and incorporated herein by reference.
10.4 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.
10.5 Chevron Restricted Stock Plan for Non-Employee Directors, as amended
and restated effective January 29, 1992, filed as Appendix A to
Chevron Corporation's Notice of Annual Meeting of Stockholders and
Proxy Statement dated March 16, 1992, and incorporated herein by
reference.
10.6 Chevron Corporation Long-Term Incentive Plan, filed as Appendix A to
Chevron Corporation's Notice of Annual Meeting of Stockholders and
Proxy Statement dated March 19, 1990, and incorporated herein by
reference.
12.1 Definitions of Selected Financial Terms (page 38).
12.2 Computation of Ratio of Earnings to Fixed Charges (page 39).
22.1 Subsidiaries of Chevron Corporation (page 40).
24.1 Consent of Price Waterhouse (page 35).
24.2 Consent of KPMG Peat Marwick (page C-5 of financial statements for
the Caltex Group of Companies).
- 33 -
EXHIBIT INDEX
(continued)
EXHIBIT
NO. DESCRIPTION
- ------- --------------------------------------------------------------------
25.1 Powers of Attorney for directors and certain officers of Chevron
Corporation, authorizing, among other things, the signing of reports
on their behalf, filed as Exhibit 25.1 to Chevron Corporation's
Annual Report on Form 10-K for 1988 and incorporated herein by
reference.
25.2 Power of Attorney for a certain director of Chevron Corporation,
authorizing, among other things, the signing of reports on his
behalf, filed as Exhibit 25 to Chevron Corporation's Quarterly
Report on Form 10-Q for the quarter ended June 30, 1989, and
incorporated herein by reference.
25.3 Power of Attorney for a certain officer of Chevron Corporation,
authorizing, among other things, the signing of reports on his
behalf, filed as Exhibit 25.3 to Chevron Corporation's Annual Report
on Form 10-K for 1989 and incorporated herein by reference.
25.4 Power of Attorney for a certain director of Chevron Corporation,
authorizing, among other things, the signing of reports on her
behalf, filed as Exhibit 25 to Chevron Corporation's Quarterly
Report on Form 10-Q for the quarter ended June 30, 1991, and
incorporated herein by reference.
25.5 Power of Attorney for a certain director of Chevron Corporation,
authorizing, among other things, the signing of reports on her
behalf, filed as Exhibit 25 to Chevron Corporation's Quarterly
Report on Form 10-Q for the quarter ended March 31, 1993, and
incorporated herein by reference.
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, 225 Bush Street, San Francisco, California
94104.
- 34 -
REPORT OF INDEPENDENT ACCOUNTANTS ON
FINANCIAL STATEMENT SCHEDULES
To the Board of Directors of Chevron Corporation
Our audits of the consolidated financial statements referred to in our report
dated February 25, 1994 appearing on page FS-13 of this Annual Report on Form
10-K also included an audit of the Financial Statement Schedules listed in
Item 14(a) of this Form 10-K. In our opinion, these Financial Statement
Schedules present fairly, in all material respects, the information set forth
therein when read in conjunction with the related consolidated financial
statements.
PRICE WATERHOUSE
San Francisco, California
February 25, 1994
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the Prospectuses
constituting part of the Registration Statements on Form S-3 (No. 2-98466)
and Form S-8 (Nos. 33-3899, 33-34039 and 33-35283) of Chevron Corporation,
and to the incorporation by reference in the Prospectus constituting part of
the Registration Statement on Form S-3 (No. 33-14307) of Chevron Capital
U.S.A. Inc. and Chevron Corporation, and to the incorporation by reference in
the Registration Statement on Form S-3 (No. 33-58838) of Chevron Canada
Finance Limited and Chevron Corporation, and to the incorporation by
reference in the Prospectus constituting part of the Registration Statement
on Form S-8 (No. 2-90907) of Caltex Petroleum Corporation of our report dated
February 25, 1994 appearing on page FS-13 of this Annual Report on Form 10-K.
We also consent to the incorporation by reference of our report on the
Financial Statement Schedules which appears above.
PRICE WATERHOUSE
San Francisco, California
March 30, 1994
- 35 -
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT (INCLUDING CAPITAL LEASES)
(Millions of Dollars)
OTHER
BALANCE AT CHANGES BALANCE AT
BEGINNING ADDITIONS (1) ADD END OF
CLASSIFICATION OF PROPERTY OF PERIOD AT COST (RETIREMENTS) (DEDUCT) (2) PERIOD
- ----------------------------- ---------- ------------- ------------- ------------ ----------
--------------------------------1993------------------------------
Petroleum
Exploration and Production (3) $25,599 $1,677 $ (948) $ 9 $26,337
Refining, Marketing & Transportation 13,129 1,179 (1,272) 42 13,078
Chemicals 2,083 198 (57) (12) 2,212
Coal and Other Minerals 847 35 (22) - 860
Corporate and Other 2,352 96 (83) (45) 2,320
------- ------ ------- ----- -------
Total $44,010 $3,185 $(2,382) $ (6) $44,807
======= ====== ======= ===== =======
-------------------------------1992----------------------------
Petroleum
Exploration and Production (3) $27,800 $1,609 $(3,824) $ 14 $25,599
Refining, Marketing & Transportation 12,241 1,284 (361) (35) 13,129
Chemicals 2,132 208 (277) 20 2,083
Coal and Other Minerals 839 59 (51) - 847
Corporate and Other 2,256 209 (114) 1 2,352
------- ------ ------- ----- -------
Total $45,268 $3,369 $(4,627) $ - $44,010
======= ====== ======= ===== =======
-------------------------------1991----------------------------
Petroleum
Exploration and Production (3) $27,918 $1,761 $(1,878) $ (1) $27,800
Refining, Marketing & Transportation 11,234 1,439 (432) - 12,241
Chemicals 1,973 205 (36) (10) 2,132
Coal and Other Minerals 1,050 82 (294) 1 839
Corporate and Other 2,133 178 (64) 9 2,256
------- ------ ------- ----- -------
Total $44,308 $3,665 $(2,704) $ (1) $45,268
======= ====== ======= ===== =======
NOTES:
(1) Additions are reported net of the write-off of prior years' exploratory wells, which were $29, $57
and $35 in 1993, 1992 and 1991, respectively.
(2) Includes inter-functional transfers in all years.
(3) Includes investment in unproved oil and gas properties.
- 36 -
SCHEDULE VI - ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF
PROPERTY, PLANT AND EQUIPMENT (INCLUDING CAPITAL LEASES) (1)
(Millions of Dollars)
ACCUMULATED DEPRECIATION, DEPRECIATION, OTHER
DEPLETION AND AMORTIZATION BALANCE AT DEPLETION AND CHANGES BALANCE AT
FOR CLASSIFICATIONS OF BEGINNING AMORTIZATION ADD END OF
PROPERTY LISTED IN SCHEDULE V OF PERIOD EXPENSE (RETIREMENTS) (DEDUCT) (2) PERIOD
- ----------------------------- ---------- ------------- ------------- ------------ ----------
----------------------------- 1993 -------------------------------
Petroleum
Exploration and Production $14,916 $1,583 $ (709) $ 5 $15,795
Refining, Marketing & Transportation 5,126 566 (501) 14 5,205
Chemicals 722 149 (32) - 839
Coal and Other Minerals 329 54 (21) - 362
Corporate and Other 729 100 (68) (20) 741
------- ------ ------- ----- -------
Total $21,822 $2,452 $(1,331) $ (1) $22,942
======= ====== ======= ===== =======
----------------------------- 1992 ------------------------------
Petroleum
Exploration and Production $15,854 $1,760 $(2,705) $7 $14,916
Refining, Marketing & Transportation 4,826 527 (211) (16) 5,126
Chemicals 763 145 (196) 10 722
Coal and Other Minerals 315 50 (36) - 329
Corporate and Other 660 112 (42) (1) 729
------- ------ ------- ----- -------
Total $22,418 $2,594 $(3,190) $ - $21,822
======= ====== ======= ===== =======
----------------------------- 1991 ------------------------------
Petroleum
Exploration and Production $15,358 $1,840 $(1,342) $ (2) $15,854
Refining, Marketing & Transportation 4,603 466 (249) 6 4,826
Chemicals 656 141 (24) (10) 763
Coal and Other Minerals 398 55 (138) - 315
Corporate and Other 567 114 (27) 6 660
------- ------ ------- ----- -------
Total $21,582 $2,616 $(1,780) $ - $22,418
======= ====== ======= ===== =======
NOTES:
(1) Depreciation, depletion and amortization methods are disclosed in Note 1 to the Consolidated
Financial Statements appearing on pages FS-18 to FS-19 of this Annual Report on Form 10-K.
(2) Includes inter-functional transfers in all years.
- 37 -
EXHIBIT 12.1
DEFINITIONS OF SELECTED FINANCIAL TERMS
RETURN ON AVERAGE STOCKHOLDERS' EQUITY
Net income divided by average stockholders' equity. Average stockholders'
equity is computed by averaging the sum of the beginning of year and end of
year balances.
RETURN ON AVERAGE CAPITAL EMPLOYED
Net income plus after-tax interest expense divided by average capital
employed. Capital employed is stockholders' equity plus short-term debt plus
long-term debt plus capital lease obligations plus minority interests.
Average capital employed is computed by averaging the sum of capital employed
at the beginning of the year and at the end of the year.
TOTAL DEBT-TO-TOTAL DEBT PLUS EQUITY RATIO
Total debt, including capital lease obligations, divided by total debt plus
stockholders' equity.
CURRENT RATIO
Current assets divided by current liabilities.
INTEREST COVERAGE RATIO
Income before income tax expense and cumulative effect of change in
accounting principle, plus interest and debt expense and amortization of
capitalized interest, divided by before-tax interest costs.
- 38 -
EXHIBIT 12.2
CHEVRON CORPORATION - TOTAL ENTERPRISE BASIS
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(Dollars in Millions)
Year Ended December 31,
------------------------------------------
1993 1992(1) 1991 1990 1989
------ ------ ------ ------ ------
Net Income before Cumulative
Effect of Changes in
Accounting Principles $1,265 $2,210 $1,293 $2,157 $ 251
Income Tax Expense 1,389 1,508 1,302 2,387 1,322
Distributions Greater Than
(Less Than) Equity in
Earnings of Less Than 50%
Owned Affiliates 6 (9) (20) (6) (9)
Minority Interest (2) 2 2 6 3
Previously Capitalized
Interest Charged to
Earnings During Period 20 18 17 15 15
Interest and Debt Expense 390 490 585 707 718
Interest Portion of Rentals (2) 169 152 153 163 118
------ ------ ------ ------ ------
EARNINGS BEFORE PROVISION
FOR TAXES AND FIXED CHARGES $3,237 $4,371 $3,332 $5,429 $2,418
====== ====== ====== ====== ======
Interest and Debt Expense $ 390 $ 490 $ 585 $ 707 $ 718
Interest Portion of Rentals (2) 169 152 153 163 118
Capitalized Interest 60 46 30 24 42
------ ------ ------ ------ ------
TOTAL FIXED CHARGES $ 619 $ 688 $ 768 $ 894 $ 878
====== ====== ====== ====== ======
- ----------------------------------------------------------------------------
RATIO OF EARNINGS TO FIXED CHARGES 5.23 6.35 4.34 6.07 2.75
- ----------------------------------------------------------------------------
(1) The information for 1992 reflects the company's adoption of the Financial
Accounting Standards Board Statements No. 106, "Employers' Accounting for
Postretirement Benefits Other than pensions" and No. 109, "Accounting for
Income Taxes," effective January 1, 1992.
(2) Calculated as one-third of rentals.
- 39 -
EXHIBIT 22.1
SUBSIDIARIES OF CHEVRON CORPORATION*
Name of Subsidiary State or Country
(Reported by Principal Area of Operation) in Which Organized
- ----------------------------------------- ------------------
UNITED STATES
Chevron U.S.A. Inc. Pennsylvania
Principal Divisions:
Chevron U.S.A. Production Company
Chevron U.S.A. Products Company
Warren Petroleum Company
Chevron Capital U.S.A. Inc. Delaware
Chevron Chemical Company Delaware
Chevron Investment Management Company Delaware
Chevron Land and Development Company Delaware
Chevron Oil Finance Company Delaware
Chevron Pipe Line Company Delaware
Huntington Beach Company California
The Pittsburg & Midway Coal Mining Co. Missouri
INTERNATIONAL
Bermaco Insurance Company Limited Bermuda
Cabinda Gulf Oil Company Limited Bermuda
Chevron Asiatic Limited Delaware
Chevron Canada Limited Canada
Chevron Canada Enterprises Limited Canada
Chevron Canada Resources Canada
Chevron International Limited Liberia
Chevron International Oil Company, Inc. Delaware
Chevron Niugini Pty. Limited Papua New Guinea
Chevron Overseas Petroleum Inc. Delaware
Chevron Standard Limited Delaware
Chevron U.K. Limited United Kingdom
Chevron Transport Corporation Liberia
Chevron Nigeria Limited Nigeria
Gulf Oil (Great Britain) Limited United Kingdom
Insco Limited Bermuda
Transocean Chevron Company Delaware
*All of the subsidiaries in the above list are wholly owned, either directly
or indirectly, by Chevron Corporation. Certain subsidiaries are not listed
since, considered in the aggregate as a single subsidiary, they would not
constitute a significant subsidiary at December 31, 1993.
- 40 -
INDEX TO MANAGEMENT'S DISCUSSION AND ANALYSIS,
CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PAGE(S)
--------------
Management's Discussion and Analysis . . . . . . . . . . . . . FS-1 to FS-12
Quarterly Results and Stock Market Data . . . . . . . . . . . FS-12
Report of Management . . . . . . . . . . . . . . . . . . . . . FS-13
Report of Independent Accountants . . . . . . . . . . . . . . FS-13
Consolidated Statement of Income . . . . . . . . . . . . . . . FS-14
Consolidated Balance Sheet . . . . . . . . . . . . . . . . . . FS-15
Consolidated Statement of Cash Flows . . . . . . . . . . . . . FS-16
Consolidated Statement of Stockholder's Equity . . . . . . . . FS-17
Notes to Consolidated Financial Statements . . . . . . . . . . FS-18 to FS-29
Supplemental Information on Oil and Gas Producing Activities . FS-30 to FS-35
Five-Year Financial Summary . . . . . . . . . . . . . . . . . FS-36
- 41 -
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
KEY FINANCIAL RESULTS
Millions of dollars, except per-share amounts 1993 1992 1991
- -----------------------------------------------------------------------------
Sales and Other Operating Revenues $36,191 $38,212 $38,118
Income Before Cumulative Effect
of Changes in Accounting Principles $ 1,265 $ 2,210 $ 1,293
Cumulative Effect of Changes in
Accounting Principles - $ (641) -
Net Income $ 1,265 $ 1,569 $ 1,293
Special (Charges) Credits
Included in Income* $ (883) $ 651 $ (66)
Per Share:
Income Before Cumulative Effect
of Changes in Accounting Principles $ 3.89 $ 6.52 $ 3.69
Net Income $ 3.89 $ 4.63 $ 3.69
Dividends $ 3.50 $ 3.30 $ 3.25
=============================================================================
*Before cumulative effect of changes in accounting principles
Chevron's worldwide net income for 1993 was $1.265 billion, down 19 and 2
percent from 1992 and 1991, respectively. However, special items in all
years and the cumulative effect of adopting two new accounting standards
in 1992 affected the comparability of the company's reported results.
Special items, after related tax effects, decreased 1993 earnings $883
million, increased 1992 earnings $651 million and decreased 1991 earnings
$66 million. Also, the cumulative effect of adopting the two new accounting
standards reduced 1992 earnings $641 million. Excluding the effects of
special items and the accounting changes, 1993 earnings of $2.148 billion
were up 38 percent from $1.559 billion in 1992 and increased 58 percent
from $1.359 billion in 1991.
OPERATING ENVIRONMENT AND OUTLOOK. Crude oil prices began trending downward
at midyear. The decline accelerated during the last two months of 1993,
with prices reaching their lowest level in over five years by year-end.
During the year, Chevron's posted price for West Texas Intermediate (WTI),
a benchmark crude, declined $5.50 per barrel to $13.25 at year-end 1993.
Worldwide demand for crude oil has been dampened by the weak global economy;
production in the non-OPEC countries has increased, particularly in the
North Sea; and the OPEC producers have not adjusted their production levels
accordingly. On the other hand, natural gas prices in the United States
remained strong in 1993, with the company's average realization of $1.99
per thousand cubic feet nearly 30 cents higher than in 1992. For most of
1993, refined product prices did not decline as quickly as crude oil prices,
resulting in strong worldwide sales margins. However, late in the year, the
decline accelerated in the United States and product prices have remained
at lower levels into early 1994.
Economic indicators show evidence that the U.S. economy is improving;
however, recessionary conditions continue in other major countries. Bitter
cold weather in the U.S. Midwest and East strengthened crude oil prices
somewhat in early 1994 but by February 25 Chevron's posted price for WTI
had fallen back to the year-end 1993 level. Natural gas prices remained
firm, with average U.S. natural gas realizations in January 1994 of $2.03
per thousand cubic feet.
If both crude oil and refined product prices continue at their low levels,
the company's earnings from ongoing operations may be negatively affected.
Widely fluctuating prices have become characteristic of the petroleum
industry for the past several years. The company has made significant
progress in streamlining its businesses and reducing costs in recent years
and believes it has improved its ability to operate more competitively and
profitably.
YEAR-END 1993 MARKED THE END OF A FIVE-YEAR PERIOD, FOR WHICH AGGRESSIVE
MANAGEMENT PERFORMANCE OBJECTIVES HAD BEEN SET IN EARLY 1989. The company
declared its mission was to provide superior financial results for the
company's stockholders. The objective was set to have a higher total
stockholder return - stock appreciation plus reinvested dividends - than
five other major U.S. oil companies against which the company measures
its performance. To achieve this, the company embarked upon an aggressive
program to restructure its businesses, improve management decision making
and accountability, shed marginal and non-core assets, reduce operating
costs, improve work processes, and through selective investments, position
the company for long-term growth. Over the 1989-1993 period, Chevron's
total annual stockholder return averaged 18.9 percent, the best among its
peer group. The company disposed of marginal and non-core assets, generating
almost $4 billion in cash proceeds during this period, and reduced its
annual cost structure by about $1 billion in 1993 from
FS-1
1991 levels. Using the company's method of measuring cost performance,
costs were reduced from $7.45 per barrel in 1991 to $6.51 in 1993, a
reduction of $.94 per barrel, or nearly 13 percent.
IN EARLY 1994, THE COMPANY ANNOUNCED A NEW FIVE-YEAR GOAL OF MAINTAINING
ITS POSITION AS THE NO. 1 MAJOR U.S. OIL COMPANY IN TOTAL STOCKHOLDER
RETURN. Key elements include targeting a further $.25 per barrel reduction
in operating and administrative costs by the end of 1994; attaining a 12
percent return on capital employed, after adjusting for special items; and
pursuing growth opportunities - particularly in international exploration
and production and, through its Caltex affiliate, in refining and marketing
activities in the fast growing Asia-Pacific region.
UNITED STATES REFINING AND MARKETING DEVELOPMENTS. The company announced a
major restructuring of its U.S. refining and marketing business in May 1993.
The company's refineries at Port Arthur, Texas, and Philadelphia,
Pennsylvania, will be sold and investments in retail marketing activities in
the East will be concentrated in the Gulf Coast states. As a result, the
company's U.S. refining capacity will decrease about 350,000 barrels per
day, or 25 percent, and U.S. refined product sales volumes may decline about
250,000 barrels per day, or about 17 percent from 1993 volumes. However,
the new refining organization, while smaller, is expected to be more
efficient, with improved cash flow and return on capital employed. It will
also eliminate the large capital investments that would have been required
for these facilities under the Clean Air Act and other environmental
regulations. A provision of $543 million was recorded for the financial
effects of the restructuring. In late February 1994, the company signed a
letter of intent to sell the Philadelphia refinery to Sun Company, Inc.
While negotiations for the refinery sales are ongoing, it is expected that
the reserve will be sufficient to complete the restructuring.
UNITED STATES EXPLORATION AND PRODUCTION DEVELOPMENTS. The interim
tankering permit issued by the California Coastal Commission required the
Point Arguello partners to have signed an agreement by February 1, 1994
that would allow a pipeline developer to secure financing for construction
of a pipeline to the Los Angeles area. Because of ongoing negotiations, the
deadline was not met and tankering was suspended. With tankering, the
project had been producing over 80,000 barrels per day. The partners have
thus far maintained production volumes by routing the oil to alternate
markets, pending resolution of the negotiations and resumption of
tankering. Chevron is operator and owns approximately 25 percent of the
project.
INTERNATIONAL EXPLORATION AND PRODUCTION DEVELOPMENTS. Tengizchevroil
(TCO), the company's joint venture with the Republic of Kazakhstan to
develop the Tengiz and Korolev oil fields on the northeastern coast of
the Caspian Sea, began operations in April 1993. The oil is being exported
into world markets under a transportation/exchange agreement with Russia,
whereby TCO receives and exports crude oil from Russia in exchange for
providing Russia with comparable amounts of Tengiz crude. Natural gas,
natural gas liquids and sulfur are being sold into local markets. Upon
formation of the joint venture, Chevron's net proved reserves of crude
oil and natural gas liquids increased 1.1 billion barrels and net proved
reserves of natural gas increased 1.5 trillion cubic feet, representing the
company's share of TCO's current net proved reserves.
Crude oil production capacity is 65,000 barrels per day; however, because
of pipeline transportation constraints, production has averaged
approximately 30,000 barrels per day since April. At year-end 1993, the
company's cash investment in TCO was about $220 million. In addition,
the company has accrued future field development obligations and amounts
payable after completion and demonstrated operability of an export
pipeline system. Over the next three to five years, plans call for TCO
to spend about $1.5 billion to reach a production capacity of 260,000
barrels per day by the late 1990s. Current capacity is expected to double
to 130,000 barrels per day by 1995. The pace of field development from
130,000 to 260,000 barrels per day is dependent on the ability to export
the full production capacity. This will ultimately require the construction
of an export pipeline system, which is separate from the TCO joint
venture's Tengiz development project. Negotiations to agree on terms for a
pipeline project have proved to be very difficult, and it is currently
impossible to predict the eventual outcome or its impact on the joint
venture.
In January 1994, production began from the Alba oil field in the United
Kingdom North Sea. Chevron is operator and owns one-third of this project.
Production should peak at about 70,000 barrels per day later in 1994.
FS-2
Chevron has significant oil and gas exploration and production operations
in Nigeria and in the Angolan exclave of Cabinda, where its share of net
production is about 100,000 barrels of crude oil per day from each of these
countries. Angola has experienced civil unrest following its 1992 elections;
separately, elements seeking independence of Cabinda from Angola have
periodically created civil unrest in the area of the company's operations.
Also, the nullification of the Nigerian elections in 1993 has been followed
by a period of political uncertainty. To date, none of these events has had
a significant impact on the company's operations, but the company is closely
monitoring developments.
ENVIRONMENTAL MATTERS. Virtually all aspects of the businesses in which the
company engages are subject to various federal, state and local
environmental, health and safety laws and regulations. These regulatory
requirements continue to increase in both number and complexity and govern
not only the manner in which the company conducts its operations, but also
the products it sells. Most of the costs of complying with myriad laws and
regulations pertaining to 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 1993 was nearly $1.5 billion, of which
$675 million were capital expenditures. These amounts do not include
non-cash provisions recorded for environmental remediation programs, but
include spending charged against such reserves.
In addition to the various federal, state and local environmental laws and
regulations governing its ongoing operations and products, the company (as
well as other companies engaged in the petroleum or chemicals industries)
is required to incur expenses for corrective actions at various facilities
and waste disposal sites. An obligation to take remedial action may be
incurred as a result of the enactment of laws, such as the federal
Superfund law, or the issuance of new regulations or as the result of
accidental leaks and spills in the ordinary course of business. In addition,
an obligation may arise when a facility is closed or sold. Most of the
expenditures to fulfill these obligations relate to facilities and sites
where past operations followed practices and procedures that were considered
acceptable under regulations existing at the time performed, but now will
require investigatory and/or remedial work to ensure adequate protection to
the environment.
During 1993, the company recorded $215 million of before-tax provisions to
provide for environmental remediation efforts, including Superfund sites.
Actual expenditures charged against these provisions and other previously
established reserves amounted to $183 million in 1993. At year-end 1993,
the company's environmental remediation reserve was $746 million, including
$56 million related to Superfund sites. Receivables of $18 million have been
recorded for expected reimbursements of expenditures for environmental
cleanup.
Under provisions of the Superfund law, the Environmental Protection Agency
(EPA), as well as certain state agencies, have designated Chevron a
potentially responsible party (PRP) for remediation of a portion of 223
hazardous waste sites. At year-end 1993, the company's cumulative share of
costs and settlements for approximately 145 of these sites, for which
payments or provisions have been made in 1993 and prior years, was about
$89 million, including a provision of $6 million during 1993. 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 possible
exposure. 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.
Provisions are recorded for work at identified sites where an assessment or
remediation plan has been developed and for which costs can reasonably be
estimated. It is likely the company will continue to incur additional
charges for environmental programs 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 insurance or other sources. 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 Chevron's 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
FS-3
international petroleum or chemicals concerns. Although environmental
compliance costs are substantial, the company has no reason to believe
they vary significantly from similar costs incurred by other companies
engaged in similar businesses in similar areas. The company believes that
such costs ultimately are reflected in the petroleum and chemicals
industries' prices for products and services.
The 1990 amendments to the Clean Air Act will require significant capital
expenditures for the industry to meet clean-air regulations. The company's
capital expenditures related to air quality were $434 million in 1993.
Estimated 1994 total capital environmental expenditures are $686 million,
of which $478 million will be spent to meet federal and state clean-air
regulations for its products and facilities. This is in addition to the
ongoing costs of complying with other environmental regulations.
In addition to the reserves for environmental remediation discussed above,
the company maintains reserves for dismantlement, abandonment and
restoration of its worldwide oil, gas and mineral properties at the end of
their productive lives. Most such costs are environmentally related.
Provisions are recognized through depreciation expense as the properties are
produced. The amount of these reserves at year-end 1993 was about $1.5
billion.
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.
OTHER CONTINGENCIES. At year-end 1993 the company had $222 million of
suspended exploratory wells included in properties, plant and equipment.
The wells are suspended pending drilling of additional wells to determine
if commercially producible quantities of oil or gas reserves are present.
The ultimate disposition of these well costs is dependent on the results of
this future activity.
The company is the subject of various lawsuits and claims and other
contingent liabilities. These 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.
NEW ACCOUNTING STANDARDS. In November 1992, the Financial Accounting
Standards Board (FASB) issued Statement of Financial Accounting Standards
(SFAS) No. 112, "Employers' Accounting for Postemployment Benefits,"
which established accounting standards for employers who provide benefits
to former or inactive employees after termination but before retirement. In
May 1993, the FASB issued SFAS No. 115, "Accounting for Certain Investments
in Debt and Equity Securities." The company's current accounting practices
are substantially in compliance with the new standards. Accordingly, the
adoption of these two standards in the first quarter of 1994 will not have a
material effect on the company's consolidated financial statements and will
not affect its liquidity.
SPECIAL ITEMS. Net income is affected by transactions that are unrelated to,
or are not 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 between years. The adjacent table summarizes
the (losses) gains, on an after-tax basis, from special items included in
the company's reported net income.
Millions of dollars 1993 1992 1991
- -----------------------------------------------------------------------------
Asset Dispositions $ 122 $757 $149
Restructurings and Reorganizations (554) (40) (185)
Prior-Year Tax Adjustments (130) 72 173
Environmental Remediation Provisions (90) (44) (160)
Asset Write-Offs and Revaluations (71) (133) (24)
LIFO Inventory (Losses) Gains (46) (26) 16
Other (114) 65 (35)
- -----------------------------------------------------------------------------
Total Special Items $(883) $651 $(66)
=============================================================================
ASSET DISPOSITIONS in 1993 resulted from the company's continuing program
to dispose of marginal and non-strategic assets. The Ortho lawn and garden
products business was the major asset sold in 1993, generating a $130
million gain. In addition, oil and gas properties in the United States and
Indonesia, undeveloped coal properties in the United States and marketing
assets in Central America were sold during the year resulting in a net loss
of $8 million. In 1992, assets sold included oil and gas properties in the
United States, United Kingdom, Canada and Sudan; a U.S. fertilizer business;
and a copper interest in Chile. In addition, the stock of a U.S. oil and
gas subsidiary was exchanged with Pennzoil Company for 15,750,000 shares of
Chevron stock, a transaction valued at $1.1 billion. The
FS-4
combination of these and other smaller sales resulted in after-tax gains of
$757 million. In 1991, sales of producing properties in the United States,
Oman and Spain; non-producing properties in the United Kingdom; certain U.S.
geothermal properties; an agricultural chemicals interest, together with the
company's share of the gain on an asset sale by its Caltex affiliate,
resulted in net gains of $149 million.
RESTRUCTURINGS AND REORGANIZATIONS charges in 1993 amounted to $554 million,
primarily the second quarter provision to restructure Chevron's U.S.
refining and marketing business. This charge, totaling $543 million, was
composed primarily of a write-down of the refineries' facilities and related
inventories to their estimated realizable values. Also included in the
charges were provisions for environmental site assessments and employee
severance. The company has taken into account probable environmental cleanup
obligations in estimating the realizable value of the refineries.
Responsibility for these obligations will be negotiated with potential
buyers. In 1992, Chevron recorded a net charge of $40 million associated
with restructuring and work-force reductions - provisions of $105 million
for work-force reductions were offset by $65 million of pension settlement
gains in connection with the company's enhanced early retirement program.
During 1991, charges of $185 million were recorded for the reconfiguration
of the Port Arthur refinery and companywide work-force reductions.
PRIOR-YEAR TAX ADJUSTMENTS are generally the result of issues in open tax
years being settled with taxing authorities or being re-evaluated by the
company as a result of new developments. Also, adjustments are required
for the effect on deferred income taxes of changes in statutory tax rates.
ENVIRONMENTAL REMEDIATION PROVISIONS pertain to estimated future costs for
environmental remediation programs at certain of the company's U.S. service
stations, marketing terminals, refineries, chemical plants and other
locations; divested operations in which Chevron has liability for future
remediation costs; and sites, commonly referred to as Superfund sites, for
which the company is a PRP. In addition to an amount included in the 1993
restructuring charge discussed above, such provisions amounted to $90
million in 1993, $44 million in 1992 and $160 million in 1991.
ASSET WRITE-OFFS AND REVALUATIONS in 1993 comprised certain U.S. refinery
assets, U.S. and Canadian production assets, and miscellaneous corporate
assets. Asset write-offs in 1992 consisted of a $110 million write-down
of the company's Canadian Beaufort Sea properties and a net $23 million
charge related to certain U.S. refining, marketing and chemical fertilizer
assets. Certain U.S. refinery assets of $24 million were written off in
1991.
LIFO INVENTORY GAINS AND LOSSES result from the reduction of inventories
in certain inventory pools valued under the Last-In, First-Out (LIFO)
accounting method. LIFO losses decreased 1993 net income $46 million and
1992 net income $26 million. However, drawdowns of LIFO-valued inventories
increased net income in 1991 by $16 million as low-cost inventories, relative
to then-current costs, were liquidated. These amounts include the company's
equity share of Caltex LIFO inventory effects. Chevron's consolidated
petroleum inventories were 99 million barrels at year-end 1993, 105 million
barrels at year-end 1992 and 121 million barrels at year-end 1991.
OTHER SPECIAL ITEMS in 1993 included net additions of $70 million to
reserves for various litigation and regulatory issues and a one-time cash
bonus award to employees totaling $60 million, offset by a favorable
inventory adjustment of $16 million. In 1992, insurance recoveries and
chemical products licensing agreements of $76 million were partially
offset by $11 million of net additions to reserves for various litigation
and regulatory issues. In 1991, additions of $35 million were made to
litigation and regulatory reserves.
RESULTS OF OPERATIONS. Strong worldwide refined product sales margins and
higher U.S. natural gas prices mitigated the effects of lower crude oil
prices in 1993, but the most important contributor to the company's improved
operating performance was the large reduction in its operating and
administrative costs. Also, lower interest and exploration expenses helped
earnings. Chemicals operations continued at depressed levels.
Similar to 1993, the increase in 1992 operating earnings from 1991 levels
reflected reduced operating and administrative costs, higher U.S. natural
gas prices and improved U.S. refined product sales margins. These benefits
were partly offset by lower earnings in international refining and marketing
and worldwide chemicals operations as weak global economic conditions held
down product prices, shrinking sales margins.
FS-5
SALES AND OTHER OPERATING REVENUES were $36.2 billion, down from $38.2
billion in 1992 and $38.1 billion in 1991. Revenues declined from 1992 and
1991 levels primarily due to lower crude oil and refined products prices
partly offset by higher natural gas prices.
The $.6 billion decline in OTHER INCOME in 1993 was due to lower asset sales
gains.
OPERATING EXPENSES, adjusted for special items, declined significantly as a
result of the company's extensive cost-reduction programs initiated in early
1992. Operating expenses and administrative costs in 1993, adjusted for
special items, declined $358 million from 1992. Coupled with the $512
million reduction in 1992 from 1991 levels, the two-year reduction in costs
totaled $870 million, an 11 percent decrease from 1991. The company believes
it has achieved a significant reduction in its cost structure and that most
of the cost savings will be sustainable.
Millions of dollars 1993 1992 1991
- -----------------------------------------------------------------------------
Reported Operating Expenses* $6,267 $6,145 $6,933
Reported Selling, General
and Administrative Expenses 1,530 1,761 1,704
- -----------------------------------------------------------------------------
Total Operational Costs 7,797 7,906 8,637
Eliminate Special Charges Before Tax (531) (282) (501)
- -----------------------------------------------------------------------------
Adjusted Ongoing Operational Costs $7,266 $7,624 $8,136
=============================================================================
*Operations are charged at market rates for consumption of the company's own
fuel. These "costs" are eliminated in the consolidated financial statements.
For cost performance measurement, such costs are included and amounted to
$1,017, $1,251 and $1,272 in 1993, 1992 and 1991, respectively.
TAXES on income were $1.2 billion in 1993, $1.3 billion in 1992 and $959
million in 1991, equating to effective income tax rates of 47.9 percent,
36.2 percent and 42.6 percent for each of the three years, respectively.
The increase in the 1993 tax rate is due primarily to unfavorable
prior-year tax adjustments, including an increase in deferred income
taxes resulting from the 1 percent increase in the U.S. corporate income
tax rate. The lower effective tax rate for 1992 is primarily attributable
to a low overall tax cost on property dispositions, primarily the
tax-free exchange with Pennzoil. Partially offsetting these effects were
lower favorable prior-year tax adjustments in 1992 and proportionately
lower equity affiliate income that is recorded on an after-tax basis. The
1991 effective tax rate benefited from favorable prior-year tax adjustments.
CURRENCY TRANSACTIONS increased net income $46 million in 1993 and $90
million in 1992 compared with a decrease of $4 million in 1991. These
amounts include the company's share of affiliates' currency transactions.
The gain on currency transactions in 1993 resulted primarily from
fluctuations in the value of Nigerian currency relative to the U.S. dollar.
In 1992, gains resulted from fluctuations in currencies in the United
Kingdom, Canada, Australia and Nigeria.
RESULTS BY MAJOR OPERATING AREAS
Millions of dollars 1993 1992 1991
- -----------------------------------------------------------------------------
Exploration and Production
United States $ 566 $1,043 $ 285
International 580 594 717
- -----------------------------------------------------------------------------
Total Exploration and Production 1,146 1,637 1,002
- -----------------------------------------------------------------------------
Refining, Marketing and Transportation
United States (170) 297 (153)
International 252 111 486
- -----------------------------------------------------------------------------
Total Refining, Marketing and Transportation 82 408 333
- -----------------------------------------------------------------------------
Total Petroleum 1,228 2,045 1,335
Chemicals 143 89 151
Coal and Other Minerals 44 198 7
Corporate and Other (150) (122) (200)
- -----------------------------------------------------------------------------
Income Before Cumulative Effect of
Changes in Accounting Principles $1,265 $2,210 $1,293
Cumulative Effect of Changes in
Accounting Principles - (641) -
- -----------------------------------------------------------------------------
Net Income $1,265 $1,569 $1,293
=============================================================================
FS-6
SPECIAL ITEMS BY MAJOR OPERATING AREAS
Millions of dollars 1993 1992 1991
- -----------------------------------------------------------------------------
Exploration and Production
United States $(136) $413 $(46)
International (61) 14 138
- -----------------------------------------------------------------------------
Total Exploration and Production (197) 427 92
- -----------------------------------------------------------------------------
Refining, Marketing and Transportation
United States (725) (53) (335)
International 1 (3) 133
- -----------------------------------------------------------------------------
Total Refining, Marketing and Transportation (724) (56) (202)
- -----------------------------------------------------------------------------
Total Petroleum (921) 371 (110)
Chemicals 112 53 34
Coal and Other Minerals - 159 (4)
Corporate and Other (74) 68 14
- -----------------------------------------------------------------------------
Total Special Items Included in Net Income $(883) $651 $(66)
=============================================================================
U.S. EXPLORATION AND PRODUCTION earnings in 1993, excluding special items,
improved 11 percent from 1992 levels and more than doubled from 1991 results.
In 1993, the effects of lower average crude oil prices and lower crude oil
and natural gas production volumes were more than offset by lower operating
expenses and higher natural gas prices. Also, natural gas contract
settlements contributed to the earnings improvement. While the company's
average crude oil realization declined $1.92 per barrel to $14.58 in 1993,
average natural gas prices increased to $1.99 per thousand cubic feet
compared with $1.70 for 1992. Because of the company's extensive cost cutting
efforts and disposition of higher-cost oil and gas properties, 1993
earnings per equivalent barrel, excluding special items, increased $.18 to
$.95.
Millions of dollars 1993 1992 1991
- -----------------------------------------------------------------------------
Earnings Excluding Special Items $702 $ 630 $331
- -----------------------------------------------------------------------------
Asset Dispositions (54) 419 (49)
Prior-Year Tax Adjustments (40) 5 (50)
Environmental Remediation Provisions (13) (2) (3)
Asset Write-Offs and Revaluations (13) - -
Restructurings and Reorganizations (2) (35) -
LIFO Inventory Gains 1 5 1
Other (15) 21 55
- -----------------------------------------------------------------------------
Total Special Items (136) 413 (46)
- -----------------------------------------------------------------------------
Reported Earnings $566 $1,043 $285
=============================================================================
Cost cutting efforts and higher natural gas prices were also the major
factors in 1992's earnings improvement over 1991, offsetting lower crude
oil prices and lower production levels. Exploration expense declined over
the three-year period, and depreciation expense dropped in line with lower
production volumes.
Net liquids production for 1993 averaged 394,000 barrels per day, down from
432,000 in 1992 and 454,000 in 1991. Net natural gas production for 1993 was
about 2.1 billion cubic feet per day, down from approximately 2.3 billion
cubic feet per day in 1992 and 1991. The production declines in liquids and
natural gas were due primarily to the disposition of producing properties in
late 1992.
INTERNATIONAL EXPLORATION AND PRODUCTION earnings, excluding special items,
improved 11 percent over the levels of 1992 and 1991 when crude oil prices
were much higher. Because of the terms of the operating agreements in some
of the countries in which the company produces, fluctuations in crude oil
prices have less impact on earnings than in the United States. Contributing
factors to the higher 1993 earnings included lower operating expenses,
lower exploration expenses and higher production volumes.
Millions of dollars 1993 1992 1991
- -----------------------------------------------------------------------------
Earnings Excluding Special Items $641 $580 $579
- -----------------------------------------------------------------------------
Prior-Year Tax Adjustments (63) (27) 45
Asset Dispositions 29 166 93
Asset Write-Offs and Revaluations (19) (110) -
Restructurings and Reorganizations (2) (9) -
LIFO Inventory Losses (1) (1) -
Other (5) (5) -
- -----------------------------------------------------------------------------
Total Special Items (61) 14 138
- -----------------------------------------------------------------------------
Reported Earnings $580 $594 $717
=============================================================================
FS-7
Both net liquids and natural gas production have increased steadily over the
three-year period. Ongoing development projects in Indonesia and West
Africa, the mid-1992 start up of production in Papua New Guinea and the
second quarter 1993 start up of the Tengiz joint venture all contributed to
the increase in net liquids production. Increases in net natural gas
production have occurred primarily in Australia's North West Shelf Project
and in Canada. Net liquids production in 1993 was 10 percent higher than in
1991, and net natural gas production increased 5 percent over this same
three-year period. Foreign currency transaction gains were $57 million in
1993, compared with $80 million in 1992 and $19 million in 1991.
SELECTED OPERATING DATA
1993 1992 1991
- -----------------------------------------------------------------------------
U.S. EXPLORATION AND PRODUCTION
Net Crude Oil and
Natural Gas Liquids Production (MBPD) 394 432 454
Net Natural Gas Production (MMCFPD) 2,056 2,313 2,359
Natural Gas Liquids Sales (MBPD) 211 194 175
Revenues from Net Production
Crude Oil ($/bbl.) $14.58 $16.50 $17.10
Natural Gas ($/MCF) $ 1.99 $ 1.70 $ 1.53
INTERNATIONAL EXPLORATION AND PRODUCTION (1)
Net Crude Oil and
Natural Gas Liquids Production (MBPD) 556 512 504
Net Natural Gas Production (MMCFPD) 469 463 447
Natural Gas Liquids Sales (MBPD) 37 33 29
Revenues from Liftings
Liquids ($/bbl.) $16.09 $17.93 $18.36
Natural Gas ($/MCF) $ 2.08 $ 2.07 $ 2.28
U.S. REFINING AND MARKETING
Gasoline Sales (MBPD) 652 646 632
Other Refined Product Sales (MBPD) 771 824 812
Refinery Input (MBPD) 1,307 1,311 1,278
Average Refined Product
Sales Price ($/bbl.) $25.35 $25.96 $26.40
INTERNATIONAL REFINING AND MARKETING (1)
Refined Product Sales (MBPD) 923 859 823
Refinery Input (MBPD) 598 543 517
CHEMICALS SALES AND
OTHER OPERATING REVENUES (2)
United States $2,694 $2,929 $3,217
International 602 566 550
--------------------------------
Worldwide $3,296 $3,495 $3,767
=============================================================================
(1) Includes equity in affiliates for all years. Per unit revenues from net
production for 1992 and 1991 have been restated to include equity
affiliates. Refinery input in 1993 includes South Africa, where local
government restrictions prohibited this disclosure in 1992 and prior
years.
(2) Millions of dollars. Includes sales to other Chevron companies.
MBPD=thousands of barrels per day; MMCFPD=millions of cubic feet per
day; bbl.=barrel; MCF=thousands of cubic feet
U.S. REFINING AND MARKETING earnings, excluding special items, improved 59
percent from 1992 levels and more than tripled from 1991 results when weak
demand and ample supplies depressed refined products margins.
Although average product prices in 1993 declined from the prior year, lower
crude oil prices, lower operating costs and stronger markets resulted in
higher average sales margins compared with 1992. Late in 1993, margins
declined somewhat as product prices fell faster than crude oil prices. Total
product sales volumes declined 3 percent from 1992's level, although sales
of higher-valued motor fuels increased about 1 percent.
FS-8
Millions of dollars 1993 1992 1991
- -----------------------------------------------------------------------------
Earnings Excluding Special Items $ 555 $350 $ 182
- -----------------------------------------------------------------------------
Restructurings and Reorganizations (543) (1) (83)
Environmental Remediation Provisions (77) (42) (157)
LIFO Inventory (Losses) Gains (44) (22) 10
Prior-Year Tax Adjustments (38) 7 (33)
Asset Write-Offs and Revaluations (25) (31) (24)
Asset Dispositions (1) - -
Other 3 36 (48)
- -----------------------------------------------------------------------------
Total Special Items (725) (53) (335)
- -----------------------------------------------------------------------------
Reported Earnings $(170) $297 $(153)
=============================================================================
Industry conditions and operating problems that plagued the company's U.S.
refining and marketing business in 1991 largely turned around in 1992.
Cost-cutting programs, operating efficiencies generated by downsizing the
Port Arthur refinery and improved operations at other refineries all
contributed to the improved earnings in 1992. Sales of refined products
increased 2 percent over 1991 levels. Refinery operating problems in 1991
reduced product yields while increasing maintenance costs and the requirement
for outside product purchases.
INTERNATIONAL REFINING AND MARKETING earnings include international marine
results and equity earnings of the company's Caltex Petroleum Corporation
affiliate. Excluding special items, 1993 earnings more than doubled from the
weak level of 1992, but were still below 1991's strong results.
Millions of dollars 1993 1992 1991
- -----------------------------------------------------------------------------
Earnings Excluding Special Items $251 $114 $353
- -----------------------------------------------------------------------------
Asset Dispositions 13 - 59
Prior-Year Tax Adjustments (4) 7 76
LIFO Inventory Losses (3) (9) (2)
Asset Write-Offs and Revaluations (1) - -
Restructurings and Reorganizations (1) (1) -
Other (3) - -
- -----------------------------------------------------------------------------
Total Special Items 1 (3) 133
- -----------------------------------------------------------------------------
Reported Earnings $252 $111 $486
- -----------------------------------------------------------------------------
International downstream operations improved significantly as product sales
margins recovered from the prior year's weak levels in all the company's
marketing areas - Canada, the United Kingdom and in the Caltex areas of
operations, especially South Africa and Singapore. Lower crude oil and
operating costs coupled with stronger markets boosted sales margins in 1993.
Also, the company's international trading results improved significantly.
Equity earnings of Caltex were $227 million, $180 million and $259 million
for 1993, 1992, and 1991, respectively. In 1993, earnings were reduced $52
million for Chevron's share of Caltex ongoing adjustments to the carrying
value of its petroleum inventories to reflect market values; earnings in
1991 included a special gain of $59 million from an asset sale. Total refined
product sales volumes increased 7 percent from 1992 and 12 percent from 1991.
Caltex volumes increased 6 percent in each year, continuing its average
annual 6 percent growth of the past several years.
Earnings in 1992 fell from 1991 levels as weak global economic conditions held
down product prices, shrinking sales margins in all the company's areas of
operations. In 1991, operating earnings benefited from strong sales margins,
particularly in the first quarter of that year when product prices did not
fall as quickly as crude oil prices in the aftermath of the Persian Gulf War.
CHEMICALS earnings, excluding special items, fell 14 percent from 1992 levels
and 74 percent from 1991 results.
Millions of dollars 1993 1992 1991
- -----------------------------------------------------------------------------
Earnings Excluding Special Items $ 31 $36 $117
- -----------------------------------------------------------------------------
Asset Dispositions 130 13 27
Prior-Year Tax Adjustments (5) (2) -
Restructurings and Reorganizations (5) (1) -
LIFO Inventory Gains 1 1 7
Asset Write-Offs and Revaluations - 8 -
Other (9) 34 -
- -----------------------------------------------------------------------------
Total Special Items 112 53 34
- -----------------------------------------------------------------------------
Reported Earnings $143 $89 $151
- -----------------------------------------------------------------------------
Results in the company's chemicals business reflected the continued depressed
state of the commodity chemicals industry. The industry has suffered several
years of depressed prices and demand due to overcapacity coupled with weak
worldwide economies. In early 1994, the company announced additional measures
to improve profitability and competitiveness of its chemicals business,
including work-force reductions, cost reductions and reorganizations.
Provisions for the expected cost of these measures were recorded in 1993.
FS-9
In 1992, in addition to industry conditions, plant shutdowns for maintenance
and Hurricane Andrew also contributed to the earnings decline from 1991.
Foreign currency transactions, mainly related to Brazil, resulted in losses
of $10 million in 1993 and 1992 compared with losses of $6 million in 1991.
COAL AND OTHER MINERALS earnings, excluding special items, improved 13
percent from 1992 levels and quadrupled from 1991 results.
Operationally, a decline in coal earnings for 1993 was more than offset by
lower non-coal exploration expenses, due to prior-year property dispositions.
Annual coal sales in 1993 exceeded 20 million tons for the first time, but
margins declined on lower prices.
Millions of dollars 1993 1992 1991
- -----------------------------------------------------------------------------
Earnings Excluding Special Items $44 $ 39 $11
- -----------------------------------------------------------------------------
Asset Dispositions 5 159 19
Prior-Year Tax Adjustments (2) - (4)
Other (3) - (19)
- -----------------------------------------------------------------------------
Total Special Items - 159 (4)
- -----------------------------------------------------------------------------
Reported Earnings $44 $198 $ 7
=============================================================================
Operating earnings in 1992 were up more than threefold from 1991 levels,
primarily from higher coal production that increased 10 percent over the
prior year. Additionally, expenses in non-coal minerals operations were
lower as the company continued its withdrawal from those businesses. The
pending sale of lead and zinc deposits in Ireland is expected to be
completed in 1994. The sale will result in a gain.
CORPORATE AND OTHER activities include interest expense, interest income on
cash and marketable securities, real estate and insurance operations, and
other activities of a corporate nature not allocated to the business segments.
Excluding the effects of special items, the lower costs in 1993 and 1992
primarily reflected the continued decline in interest expense, due to
lower average interest rates and, in 1993, lower average debt levels.
Millions of dollars 1993 1992 1991
- -----------------------------------------------------------------------------
Results Excluding Special Items $ (76) $(190) $(214)
- -----------------------------------------------------------------------------
Prior-Year Tax Adjustments 22 82 139
Asset Write-offs and Revaluations (13) - -
Restructurings and Reorganizations (1) 7 (102)
Other (82) (21) (23)
- -----------------------------------------------------------------------------
Total Special Items (74) 68 14
- -----------------------------------------------------------------------------
Reported Earnings $(150) $(122) $(200)
=============================================================================
Reported earnings in 1992 and 1991 included provisions of $41 million and
$102 million for a companywide, voluntary enhanced early retirement program.
In 1992, $65 million of pension settlement gains were recognized in
connection with the program. These amounts were considered to be corporate
items not properly allocable to the company's business segments.
LIQUIDITY AND CAPITAL RESOURCES. Cash, cash equivalents and marketable
securities increased $321 million to $2.0 billion at year-end 1993.
Cash provided by operating activities increased $307 million in 1993
to $4.2 billion, compared with $3.9 billion in 1992 and $3.3 billion in
1991. The 1993 increase reflects higher operational earnings, adjusted for
non-cash charges, and decreased working capital requirements. Cash from
operations and proceeds from asset sales were used to fund the company's
capital expenditures, dividend payments to stockholders and retirement of
debt.
AT YEAR-END 1993, THE COMPANY CLASSIFIED $1.9 BILLION OF SHORT-TERM
OBLIGATIONS AS LONG-TERM DEBT. Settlement of these obligations, primarily
commercial paper, is not expected to require the use of working capital
in 1994 because the company has the intent and the ability to refinance
them on a long-term basis. Commercial paper not reclassified to long-term
debt also is intended to be reissued continuously or refinanced on a
long-term basis.
ON DECEMBER 31, 1993, CHEVRON HAD $3.6 BILLION IN COMMITTED CREDIT FACILITIES
WITH VARIOUS MAJOR BANKS. 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 1993.
FS-10
Chevron and one of its subsidiaries each have existing "shelf" registrations
on file with the Securities and Exchange Commission that would permit
registered offerings of up to approximately $1.05 billion of debt securities.
DURING 1993, THE COMPANY PREPAID TWO FIXED-TERM U.S. PUBLIC DEBT ISSUES
TOTALING $600 MILLION. In early 1994, an additional $200 million of
fixed-term U.S. public debt was called for early repayment. The debt issues
were refinanced with short-term commercial paper. The company has pursued an
aggressive debt management strategy focused on short-term and variable-rate
financing. This strategy, together with the general decline in interest
rates, has reduced the company's annual average before-tax interest rate
from 7.6 percent in 1991, to 5.7 percent in 1992 and to 4.6 percent in 1993.
The variable-rate component of total debt was 68 percent at the end of 1993.
Chevron's total debt was $7.538 billion at year-end 1993, down $303 million
from $7.841 billion at year-end 1992.
THE COMPANY'S FUTURE DEBT LEVEL IS PRIMARILY DEPENDENT ON ITS CAPITAL
SPENDING PROGRAM AND ITS BUSINESS OUTLOOK. While the company does not
currently expect its debt level to increase significantly during 1994, it
believes it has substantial borrowing capacity to meet unanticipated cash
requirements. In light of currently low crude oil prices, the company intends
to monitor its capital spending and may make adjustments as the year
progresses.
FINANCIAL RATIOS
1993 1992 1991
- -----------------------------------------------------------------------------
Current Ratio 0.8 0.9 0.9
Interest Coverage Ratio 7.4 8.2 5.1
Total Debt/Total Debt Plus Equity 35.0% 36.4% 34.3%
=============================================================================
The CURRENT RATIO is the ratio of current assets to current liabilities at
year-end. Two items affect the current ratio negatively, which in the
company's opinion do not affect its liquidity. Included in current assets in
all years are inventories valued on a LIFO basis, which at year-end 1993 were
lower than current costs by $671 million. Also at year-end 1993, $2.5 billion
of commercial paper included in current liabilities is planned to be
refinanced continuously. Chevron's INTEREST COVERAGE RATIO decreased in 1993
due to lower before-tax income. 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.
The company's DEBT RATIO (total debt to total debt plus equity) decreased to
35.0 percent, due primarily to a net reduction in debt of $303 million.
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. All
these ratings denote high-quality, investment-grade securities.
IN JANUARY 1994, THE COMPANY INCREASED ITS QUARTERLY DIVIDEND 5 CENTS PER
SHARE TO $.925, AN ANNUALIZED RATE OF $3.70 PER SHARE, AND PROPOSED A
TWO-FOR-ONE SPLIT OF ITS ISSUED COMMON STOCK. Stockholders will be asked to
approve an increase in the number of authorized shares of common stock from
500 million to 1 billion to accommodate the split and also to approve the
stock split at the annual meeting on May 3, 1994.
CAPITAL AND EXPLORATORY EXPENDITURES
1993 1992 1991
- ---------------------------------- -------------------- ---------------------
Millions Interna- Interna- Interna-
of dollars U.S. tional Total U.S. tional Total U.S. tional Total
- -----------------------------------------------------------------------------
Exploration
and
Production $ 763 $1,599 $2,362 $ 792 $1,458 $2,250 $1,121 $1,408 $2,529
Refining,
Marketing and
Transportation 949 748 1,697 962 749 1,711 974 775 1,749
Chemicals 199 34 233 224 37 261 195 34 229
Coal and
Other Minerals 47 10 57 65 20 85 99 14 113
All Other 91 - 91 116 - 116 166 1 167
- -----------------------------------------------------------------------------
Total $2,049 $2,391 $4,440 $2,159 $2,264 $4,423 $2,555 $2,232 $4,787
- -----------------------------------------------------------------------------
Total
Excluding
Equity in
Affili-
ates $2,029 $1,710 $3,739 $2,136 $1,666 $3,802 $2,540 $1,749 $4,289
=============================================================================
FS-11
WORLDWIDE CAPITAL AND EXPLORATORY EXPENDITURES FOR 1993, INCLUDING THE
COMPANY'S EQUITY SHARE OF AFFILIATES' EXPENDITURES, TOTALED $4.4 BILLION.
Expenditures for exploration and production accounted for 53 percent of total
outlays in 1993, 51 percent in 1992 and 53 percent in 1991. U.S. exploration
and production spending declined to 32 percent of worldwide exploration and
production expenditures in 1993, down from 35 percent in 1992 and 44 percent
in 1991, reflecting the company's increasing focus on international
exploration and production activities.
THE COMPANY PROJECTS 1994 CAPITAL AND EXPLORATORY EXPENDITURES AT
APPROXIMATELY $4.9 BILLION, including Chevron's share of spending by
affiliates. Excluding affiliates, spending will be essentially flat at $3.7
billion. The 1994 program provides $2.4 billion in exploration and production
investments, of which about 75 percent is for international projects.
The company is participating in several significant oil and gas development
projects. These projects include the development of the Hibernia field off
the coast of Newfoundland; the Tengiz project in Kazakhstan; steam and
waterflood projects in Indonesia; expansion of the North West Shelf liquefied
natural gas project in Australia; additional development in the North Sea,
Nigeria and Angola; continuing enhanced oil recovery projects in California;
and a natural gas development project in the Norphlet Trend in the Gulf of
Mexico.
Refining, marketing and transportation expenditures are estimated at about
$2.1 billion, with $1 billion of that planned for the U.S., including
upgrading U.S. refineries to produce reformulated gasolines needed to comply
with the Clean Air Act. Most of the balance will be focused on high growth
Asia Pacific Rim countries, where the company's Caltex affiliate has several
major refinery projects under way to increase capacity and meet rising
demand.
QUARTERLY RESULTS AND STOCK MARKET DATA
Unaudited
1993 1992
----------------------------------- --------------------------------------
Millions of dollars, except per-share amounts 4thQ 3rdQ 2ndQ 1stQ(1) 4thQ(1) 3rdQ(1) 2ndQ(1) 1stQ(1)
- -------------------------------------------------------------------------------------------------------------------------------
REVENUES
Sales and other operating revenues $8,778 $9,097 $9,413 $8,903 $ 9,912 $ 9,990 $9,468 $8,842
Equity in net income of affiliated companies and
other income 135 136 441 179 748 271 180 266
- -------------------------------------------------------------------------------------------------------------------------------
TOTAL REVENUES 8,913 9,233 9,854 9,082 10,660 10,261 9,648 9,108
- -------------------------------------------------------------------------------------------------------------------------------
COSTS AND OTHER DEDUCTIONS
Purchased crude oil and products and operating
expenses 6,467 6,401 7,748 6,385 7,309 7,351 7,104 6,521
Depreciation, depletion and amortization 652 615 596 589 639 637 654 664
Taxes other than on income 1,303 1,219 1,227 1,137 1,193 1,282 1,247 1,177
Interest and debt expense 73 76 81 87 96 104 114 122
- -------------------------------------------------------------------------------------------------------------------------------
TOTAL COSTS AND OTHER DEDUCTIONS 8,495 8,311 9,652 8,198 9,237 9,374 9,119 8,484
- -------------------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAX EXPENSE AND CUMULATIVE
EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES 418 922 202 884 1,423 887 529 624
INCOME TAX EXPENSE 124 502 152 383 335 420 214 284
- -------------------------------------------------------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN
ACCOUNTING PRINCIPLES $ 294 $ 420 $ 50 $ 501 $1,088 $ 467 $ 315 $ 340
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING
PRINCIPLES - - - - - - - (641)
- -------------------------------------------------------------------------------------------------------------------------------
NET INCOME (LOSS)(2) $ 294 $ 420 $ 50 $ 501 $1,088 $ 467 $ 315 $ (301)
================================================================================================================================
PER SHARE OF COMMON STOCK
- -------------------------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN
ACCOUNTING PRINCIPLES $0.91 $1.29 $0.15 $1.54 $3.30 $1.37 $0.92 $0.99
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING
PRINCIPLES - - - - - - - (1.87)
- -------------------------------------------------------------------------------------------------------------------------------
NET INCOME (LOSS) PER SHARE(3) $0.91 $1.29 $0.15 $1.54 $3.30 $1.37 $0.92 $(0.88)
===============================================================================================================================
DIVIDENDS PAID PER SHARE $0.875 $0.875 $0.875 $0.875 $0.825 $0.825 $0.825 $0.825
===============================================================================================================================
COMMON STOCK PRICE RANGE - HIGH $98 3/8 $97 3/4 $90 1/4 $83 1/8 $74 1/4 $75 3/8 $73 3/4 $70 1/8
- LOW 84 1/4 82 1/8 81 67 3/4 66 3/4 66 3/8 63 1/8 60 1/8
===============================================================================================================================
(1) To conform to the presentation adopted in the second quarter of 1993, the 1992 quarters and the 1993 first quarter have
been reclassified to net certain offsetting crude oil purchases and sales contracts. The reclassification had no effect
on net income.
(2) Special items included in net income. $ (221) $ (145) $ (515) $ (2) $ 546 $ 57 $ (39) $ 87
(3) Quarterly amounts do not add to the annual earnings per share for 1992 because of changes in the number of outstanding
shares during the year.
- -------------------------------------------------------------------------------------------------------------------------------
The company's common stock is listed on the New York Stock Exchange (trading symbol: CHV), as well as the Midwest;
Pacific; Vancouver; London; and Zurich, Basel and Geneva, Switzerland, stock exchanges. It also is traded on the Boston,
Cincinnati, Detroit and Philadelphia stock exchanges. As of February 10, 1994, stockholders of record numbered
approximately 144,000.
There are no restrictions on the company's ability to pay dividends. Chevron has made dividend payments to stockholders
for 82 consecutive years.
FS-12
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 Price Waterhouse, independent
accountants, selected by the Audit Committee and approved by the
stockholders. Management has made available to Price Waterhouse 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, 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.
Kenneth T. Derr Martin R. Klitten Donald G. Henderson
Chairman of the Board and Vice President, Finance Vice President and
Chief Executive Officer Comptroller
February 25, 1994
REPORT OF INDEPENDENT ACCOUNTANTS
TO THE STOCKHOLDERS AND THE BOARD OF DIRECTORS OF CHEVRON CORPORATION
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of income, stockholders' equity and cash flows
present fairly, in all material respects, the financial position of Chevron
Corporation and its subsidiaries at December 31, 1993 and 1992, and the
results of their operations and their cash flows for each of the three years
in the period ended December 31, 1993, 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 audits 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.
As discussed in Note 2 to the consolidated financial statements, effective
January 1, 1992, the company changed its methods of accounting for
postretirement benefits other than pensions and for income taxes.
Price Waterhouse
San Francisco, California
February 25, 1994
FS-13
CONSOLIDATED STATEMENT OF INCOME
Year Ended December 31
Millions of dollars, -------------------------------------
except per-share amounts 1993 1992 (1) 1991 (1)
- -----------------------------------------------------------------------------
REVENUES
Sales and other operating revenues (2) $36,191 $38,212 $38,118
Equity in net income of
affiliated companies 440 406 491
Other income 451 1,059 334
- -----------------------------------------------------------------------------
TOTAL REVENUES 37,082 39,677 38,943
- -----------------------------------------------------------------------------
COSTS AND OTHER DEDUCTIONS
Purchased crude oil and products 18,007 19,872 19,693
Operating expenses 6,267 6,145 6,933
Provision for U.S. refining and
marketing restructuring 837 - -
Exploration expenses 360 507 629
Selling, general and administrative expenses 1,530 1,761 1,704
Depreciation, depletion and amortization 2,452 2,594 2,616
Taxes other than on income (2) 4,886 4,899 4,597
Interest and debt expense 317 436 519
- -----------------------------------------------------------------------------
TOTAL COSTS AND OTHER DEDUCTIONS 34,656 36,214 36,691
- -----------------------------------------------------------------------------
INCOME BEFORE INCOME TAX EXPENSE AND
CUMULATIVE EFFECT OF CHANGES IN
ACCOUNTING PRINCIPLES 2,426 3,463 2,252
INCOME TAX EXPENSE 1,161 1,253 959
=============================================================================
INCOME BEFORE CUMULATIVE EFFECT OF CHANGES
IN ACCOUNTING PRINCIPLES $ 1,265 $ 2,210 $ 1,293
CUMULATIVE EFFECT OF CHANGES
IN ACCOUNTING PRINCIPLES - (641) -
=============================================================================
NET INCOME $1,265 $1,569 $1,293
=============================================================================
PER SHARE OF COMMON STOCK:
INCOME BEFORE CUMULATIVE EFFECT OF
CHANGES IN ACCOUNTING PRINCIPLES $3.89 $6.52 $3.69
CUMULATIVE EFFECT OF CHANGES IN
ACCOUNTING PRINCIPLES - (1.89) -
---------------------------------
NET INCOME PER SHARE OF COMMON STOCK $3.89 $4.63 $3.69
WEIGHTED AVERAGE NUMBER OF
SHARES OUTSTANDING 325,478,876 338,977,414 350,174,450
=============================================================================
(1) Reclassified. See Note 1.
(2) Includes consumer excise taxes. $4,068 $3,964 $3,659
See accompanying notes to consolidated financial statements.
FS-14
CONSOLIDATED BALANCE SHEET
At December 31
--------------------
Millions of dollars 1993 1992
- -----------------------------------------------------------------------------
ASSETS
Cash and cash equivalents $ 1,644 $ 1,292
Marketable securities, at cost 372 403
Accounts and notes receivable
(less allowance: 1993 - $66; 1992 - $66) 3,808 4,115
Inventories:
Crude oil and petroleum products 1,108 1,276
Chemicals 423 497
Materials and supplies 252 292
Other merchandise 18 70
--------------------
1,801 2,135
Prepaid expenses and other current assets 1,057 827
- -----------------------------------------------------------------------------
TOTAL CURRENT ASSETS 8,682 8,772
Long-term receivables 94 127
Investments and advances 3,623 2,451
Properties, plant and equipment, at cost 44,807 44,010
Less: accumulated depreciation, depletion
and amortization 22,942 21,822
--------------------
21,865 22,188
Deferred charges and other assets 472 432
- -----------------------------------------------------------------------------
TOTAL ASSETS $34,736 $33,970
=============================================================================
- -----------------------------------------------------------------------------
LIABILITIES AND STOCKHOLDERS' EQUITY
Accounts payable $3,325 $3,469
Accrued liabilities 2,538 2,009
Short-term debt 3,456 2,888
Federal and other taxes on income 782 967
Other taxes payable 505 502
- -----------------------------------------------------------------------------
TOTAL CURRENT LIABILITIES 10,606 9,835
Long-term debt and capital lease obligations 4,082 4,953
Non-current deferred income taxes 2,916 2,894
Reserves for employee benefit plans 1,458 1,400
Deferred credits and other non-current obligations 1,677 1,160
- -----------------------------------------------------------------------------
TOTAL LIABILITIES 20,739 20,242
- -----------------------------------------------------------------------------
Preferred stock (authorized 100,000,000 shares,
$1.00 par value, none issued) - -
Common stock (authorized 500,000,000 shares,
$3.00 par value, 356,243,534 shares issued) 1,069 1,069
Capital in excess of par value 1,855 1,840
Deferred compensation -
Employee Stock Ownership Plan (ESOP) (920) (954)
Currency translation adjustment and other 108 56
Retained earnings 13,955 13,814
Treasury stock, at cost
(1993 - 30,504,429 shares; 1992 - 31,069,745 shares) (2,070) (2,097)
- -----------------------------------------------------------------------------
TOTAL STOCKHOLDERS' EQUITY 13,997 13,728
- -----------------------------------------------------------------------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $34,736 $33,970
=============================================================================
See accompanying notes to consolidated financial statements.
FS-15
CONSOLIDATED STATEMENT OF CASH FLOWS
Year Ended December 31
----------------------------
Millions of dollars 1993 1992 1991
- -----------------------------------------------------------------------------
OPERATING ACTIVITIES
Net income $1,265 $1,569 $1,293
Adjustments
Depreciation, depletion and amortization 2,452 2,594 2,616
Dry hole expense related to
prior years' expenditures 29 57 35
Distributions less than equity
in affiliates' income (173) (144) (220)
Net before-tax losses (gains) on asset
retirements and sales 373 (568) 25
Net currency translation (gains) losses (27) (66) 4
Deferred income tax provision (160) (176) (183)
Cumulative effect of changes in
accounting principles - 641 -
Net decrease (increase) in operating
working capital (1) 463 82 (249)
Other (1) (75) (43)
- -----------------------------------------------------------------------------
NET CASH PROVIDED BY OPERATING ACTIVITIES (2) 4,221 3,914 3,278
- -----------------------------------------------------------------------------
INVESTING ACTIVITIES
Capital expenditures (3,323) (3,352) (3,693)
Proceeds from asset sales 908 1,043 768
Net sales of marketable securities (3) 30 45 18
- -----------------------------------------------------------------------------
NET CASH USED FOR INVESTING ACTIVITIES (2,385) (2,264) (2,907)
- -----------------------------------------------------------------------------
FINANCING ACTIVITIES
Net borrowings of short-term obligations 293 1,333 1,564
Proceeds from issuance of long-term debt 199 23 35
Repayments of long-term debt and
other financing obligations (854) (1,260) (711)
Cash dividends paid (1,139) (1,115) (1,139)
Purchases of treasury shares (4) (382) (286)
- -----------------------------------------------------------------------------
NET CASH USED FOR FINANCING ACTIVITIES (1,505) (1,401) (537)
- -----------------------------------------------------------------------------
EFFECT OF EXCHANGE RATE CHANGES ON CASH
AND CASH EQUIVALENTS 21 3 (20)
- -----------------------------------------------------------------------------
NET CHANGE IN CASH AND CASH EQUIVALENTS 352 252 (186)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 1,292 1,040 1,226
- -----------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT YEAR-END $1,644 $1,292 $1,040
=============================================================================
(1) The "Net decrease (increase) in operating working capital" is composed of
the following:
Decrease in accounts and notes receivable $ 187 $ 97 $ 692
Decrease in inventories 288 292 312
(Increase) decrease in prepaid expenses
and other current assets (52) 85 (151)
Increase (decrease) in accounts payable
and accrued liabilities 214 (567) (880)
(Decrease) increase in income
and other taxes payable (174) 175 (222)
- -----------------------------------------------------------------------------
Net decrease (increase) in operating
working capital $ 463 $ 82 $ (249)
=============================================================================
(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) $ 309 $ 392 $ 453
Income taxes paid $1,505 $1,236 $1,460
=============================================================================
(3) "Net sales of marketable securities" consists of the following gross
amounts:
Marketable securities purchased $(1,855) $(2,633) $(4,104)
Marketable securities sold 1,885 2,678 4,122
- -----------------------------------------------------------------------------
Net sales of marketable securities $ 30 $ 45 $ 18
=============================================================================
See accompanying notes to consolidated financial statements.
FS-16
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
Number of Shares Millions of dollars
--------------------------- -------------------------------------------------------------------
CURRENCY
CAPITAL IN DEFERRED TRANSLATION
COMMON STOCK COMMON STOCK COMMON EXCESS OF COMPENSATION ADJUSTMENT RETAINED TREASURY
ISSUED IN TREASURY STOCK PAR VALUE - ESOP AND OTHER EARNINGS STOCK
--------------------------- -------------------------------------------------------------------
BALANCE AT DECEMBER 31, 1990 356,243,534 (5,443,328) $ 1,069 $1,835 $(979) $56 $ 13,195 $ (340)
Net income - - - - - - 1,293 -
Cash dividends -
$3.25 per share - - - - - - (1,139) -
Foreign currency translation
adjustment - - - - - 13 - -
Pension Plan
minimum liability - - - - - (2) - -
ESOP expense
accrual adjustment - - - - (5) - - -
Reduction of ESOP debt - - - - 20 - - -
Purchase of treasury shares - (4,201,864) - - - - - (286)
Reissuance of treasury shares - 123,923 - 4 - - - 5
-------------------------- -------------------------------------------------------------------
BALANCE AT DECEMBER 31, 1991 356,243,534 (9,521,269) 1,069 1,839 (964) 67 13,349 (621)
Net income - - - - - - 1,569 -
Cash dividends -
$3.30 per share - - - - - - (1,115) -
Tax benefit from dividends
paid on unallocated
ESOP shares - - - - - - 11 -
Foreign currency translation
adjustment - - - - - (10) - -
Pension Plan
minimum liability - - - - - (1) - -
ESOP expense
accrual adjustment - - - - 10 - - -
Treasury shares acquired
in exchange transaction - (15,750,000) - - - - - (1,100)
Purchase of treasury shares - (5,934,461) - - - - - (382)
Reissuance of treasury shares - 135,985 - 1 - - - 6
------------------------- -------------------------------------------------------------------
BALANCE AT DECEMBER 31, 1992 356,243,534 (31,069,745) 1,069 1,840 (954) 56 13,814 (2,097)
Net income - - - - - - 1,265 -
Cash dividends -
$3.50 per share - - - - - - (1,139) -
Tax benefit from dividend
paid on unallocated
ESOP shares - - - - - - 15 -
Foreign currency translation
adjustment - - - - - 52 - -
ESOP expense
accrual adjustment - - - - 4 - - -
Reduction of ESOP debt - - - - 30 - - -
Purchase of treasury shares - (46,253) - - - - - (4)
Reissuance of treasury shares - 611,569 - 15 - - - 31
- --------------------------------------------------------------------------------------------------------------------------------
BALANCE AT DECEMBER 31, 1993 356,243,534 (30,504,429) $1,069 $1,855 $(920) $108 $13,955 $(2,070)
================================================================================================================================
See accompanying notes to consolidated financial statements.
FS-17
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Millions of dollars
NOTE 1: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Chevron Corporation and its
consolidated subsidiaries (the company) employ accounting policies that are in
accordance with generally accepted accounting principles in the United States.
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 to 50 percent, or for which
the company participates in 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.
SHORT-TERM INVESTMENTS. Short-term investments that are part of the company's
cash management portfolio are classified as cash equivalents. These
investments are highly liquid and generally have original maturities of
three months or less. All other short-term investments are classified as
marketable securities.
INVENTORIES. Crude oil, petroleum products, chemicals and other merchandise
are stated at cost, using a Last-In, First-Out (LIFO) method. In the
aggregate, these costs are below market. Materials and supplies inventories
generally are stated at average cost.
PROPERTIES, PLANT AND EQUIPMENT. All costs for development wells, related
plant and equipment (including carbon dioxide and certain other injected
materials used in enhanced recovery projects), and 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.
Proved oil and gas properties are regularly assessed for possible impairment
on an aggregate worldwide portfolio basis, applying the informal "ceiling
test" of the Securities and Exchange Commission. Under this method, the
possibility of an impairment may exist if the aggregate net book carrying
value of these properties, net of applicable deferred income taxes, exceeds
the aggregate undiscounted future cash flows, after tax, from the properties,
as calculated in accordance with accounting rules for supplemental
information on oil and gas producing activities. In addition, high-cost,
long-lead-time oil and gas projects are individually assessed prior to
production start-up by comparing the recorded investment in the project with
its fair market or economic value, as appropriate. Economic values are
generally based on management's expectations of discounted future after-tax
cash flows from the project at the time of assessment.
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 determined 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 and other mineral assets 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 an existing condition caused by past
operations are expensed. Expenditures that create future benefits or
contribute to future revenue generation are capitalized.
Liabilities related to future remediation costs are recorded when
environmental assessments and/or cleanups are probable, and the costs can be
reasonably estimated. Other than for assessments, the timing of these
accruals coincides with 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 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 in current dollars and using currently available
technology and applying current regulations as well as the company's own
internal environmental policies. Future amounts are not discounted. Probable
recoveries or reimbursements are recorded as an asset.
FS-18
NOTE 1: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Continued
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 included in income currently. 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. Effective 1992, the company accounts for income taxes in accordance
with Statement of Financial Accounting Standards No. 109, "Accounting for
Income Taxes." In 1991, the company accounted for income taxes in accordance
with Statement No. 96, "Accounting for Income 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.
RECLASSIFICATION OF CERTAIN REVENUES AND PURCHASES. To conform to the
presentation in 1993, the years 1992 and 1991 in the consolidated income
statement were reclassified to net certain offsetting forward crude oil
purchases and sales contracts. This reclassification had no effect on net
income for any period. Sales and other operating revenues, and purchased
crude oil and products, decreased $3,216 for 1992 and $2,002 for 1991, from
the amounts previously reported.
NOTE 2: ADOPTION OF STATEMENTS OF FINANCIAL ACCOUNTING STANDARDS NO. 106,
"EMPLOYERS' ACCOUNTING FOR POSTRETIREMENT BENEFITS OTHER THAN PENSIONS"
(SFAS 106) AND NO. 109, "ACCOUNTING FOR INCOME TAXES" (SFAS 109) Effective
January 1, 1992, the company adopted SFAS 106 and SFAS 109, issued by the
Financial Accounting Standards Board. The effects of these statements on
1992 net income included a charge of $641, or $1.89 per share, attributable
to the cumulative effect of adoption, including the company's share of
equity affiliates. This net charge was composed of $833, after related tax
benefits of $423, for the recognition of liabilities for retiree benefits
(primarily health and life insurance), partially offset by a credit of $192
for deferred income tax benefits and other changes stipulated by the new
income tax accounting rules.
Apart from the cumulative effect, adoption of the statements increased
earnings for 1992 by $163 after tax, or $.48 per share. Under the new income
tax accounting, benefits of $200 were recorded, largely due to the
strengthening of the dollar in 1992, which resulted in lower foreign
deferred tax liabilities. These benefits were partly offset by $37 of
additional after-tax expense for retiree benefits, when compared to the
previous practice of expensing these costs when paid.
NOTE 3: SPECIAL ITEMS AND OTHER FINANCIAL INFORMATION Net income is affected
by transactions that are unrelated to or are not 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
-----------------------------
1993 1992 1991
- -----------------------------------------------------------------------------
Asset dispositions, net
Ortho lawn and garden products $ 130 $ - $ -
Oil and gas properties (25) 209 44
Stock exchange with Pennzoil Company - 376 -
Copper interest in Chile - 159 -
Other 17 13 105
-----------------------------
122 757 149
- -----------------------------------------------------------------------------
Asset write-offs and revaluations
Oil and gas properties (31) (110) -
Refining and marketing assets (24) (31) (24)
Other (16) 8 -
-----------------------------
(71) (133) (24)
- -----------------------------------------------------------------------------
Prior-year tax adjustments (130) 72 173
- -----------------------------------------------------------------------------
Environmental remediation provisions (90) (44) (160)
- -----------------------------------------------------------------------------
Restructurings and reorganizations
Work-force reductions, net (11) (40) (102)
U.S. Refining and marketing (543) - (83)
-----------------------------
(554) (40) (185)
- -----------------------------------------------------------------------------
LIFO inventory (losses) gains (46) (26) 16
- -----------------------------------------------------------------------------
Other, net
Litigation and regulatory issues (70) (11) (35)
One-time employee bonus (60) - -
Chemicals products license agreements - 32 -
Other adjustments 16 44 -
-----------------------------
(114) 65 (35)
- -----------------------------------------------------------------------------
Total special items, after tax* $(883) $651 $(66)
=============================================================================
*Amounts include the company's share of equity affiliates' transactions.
The U.S. refining and marketing restructuring charge of $543 was primarily
composed of a writedown of two refineries and their related inventories to
estimated realizable values. Also included in the charge were provisions for
environmental site assessments and employee severance. The estimated
realizable value of the refineries took into account probable environmental
cleanup obligations. Responsibility for these obligations will be negotiated
with potential buyers. The refineries are located in Port Arthur, Texas, and
Philadelphia, Pennsylvania, and have a combined refinery capacity of about
350,000 barrels per day.
FS-19
NOTE 3: SPECIAL ITEMS AND OTHER FINANCIAL INFORMATION - Continued
Other financial information is as follows:
Year Ended December 31
-----------------------------
1993 1992 1991
- -----------------------------------------------------------------------------
Total financing interest and debt costs $371 $478 $546
Less: capitalized interest 54 42 27
- -----------------------------------------------------------------------------
Interest and debt expense 317 436 519
Research and development expenses 206 229 250
Currency transaction gains (losses)* $ 46 $ 90 $ (4)
=============================================================================
*Includes $18 and $24 in 1993 and 1992, respectively, for the company's share
of affiliates' currency transaction effects; in 1991 the net effect was zero.
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
$671 and $803 at December 31, 1993 and 1992, respectively.
NOTE 4. INFORMATION RELATING TO THE CONSOLIDATED STATEMENT OF CASH FLOWS The
Consolidated Statement of Cash Flows excludes the following non-cash
transactions:
In 1993, the company acquired a 50 percent interest in the Tengizchevroil
joint venture (TCO) in the Republic of Kazakhstan through a series of cash
and non-cash transactions. The company's interest in TCO is accounted for
using the equity method of accounting and is recorded in "Investments and
advances" in the consolidated balance sheet. The cash expended in connection
with the formation of TCO and subsequent advances to TCO have been included
in the consolidated statement of cash flows in "Capital expenditures." The
deferred payment portion of the TCO investment totaled $709 at year-end 1993
and is recorded in "Accrued liabilities" and "Deferred credits and other
non-current obligations" in the consolidated balance sheet. The timing of
these payments is dependent on the occurrence of certain future events,
including the pace of field development and the completion and successful
operation of an export pipeline system. During 1993, payments related to the
deferred portion of the TCO investment were classified as Repayments of
long-term debt and other financing obligations" in the consolidated statement
of cash flows.
The company's Employee Stock Ownership Plan (ESOP) repaid $30 and $20 of
matured debt guaranteed by Chevron Corporation in 1993 and 1991,
respectively. The company reflected this payment as reductions in debt
outstanding and in Deferred Compensation - ESOP.
The company refinanced an aggregate amount of $334 and $57 in tax exempt
long-term debt and capital lease obligations in 1993 and 1992, respectively.
In 1991, the company refinanced $970 of long-term bank notes of the ESOP
with the public issuance of SEC registered long-term notes of a like amount.
These refinancings are not reflected in the consolidated statement of cash
flows.
In 1992, the company received 15,750,000 shares of its common stock held by
a stockholder in exchange for the stock of a subsidiary owning certain U.S.
oil and gas producing properties and related facilities, cash and other
current assets and current liabilities. The value attributed to the treasury
shares received was $1,100. The property exchanged consisted of properties,
plant and equipment with a carrying value of $790 and, excluding cash, net
current liabilities of $1. Cash of $57 was included as a reduction of
proceeds from asset sales.
In 1992, the company acquired an additional ownership interest in an
affiliate, accounted for under the equity method, in a non-cash transaction.
This increase in ownership required the consolidation of the affiliate into
the company's financial statements. The principal result of this
consolidation was to increase non-current assets and liabilities by
approximately $64.
There have been other non-cash transactions that have occurred during the
years presented. These include the reissuance of treasury shares for
management compensation plans, acquisitions of properties, plant and
equipment through capital lease transactions, and changes in stockholders'
equity, long-term debt and other liabilities resulting from the accounting
for the company's ESOP. The amounts for these transactions have not been
material in the aggregate in relation to the company's financial position.
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
-----------------------------
1993 1992 1991
- -----------------------------------------------------------------------------
Additions to properties, plant and equipment $3,214 $3,342 $3,698
Additions to investments 179 47 48
Payments for other (liabilities) and assets, net (70) (37) (53)
- -----------------------------------------------------------------------------
Capital expenditures 3,323 3,352 3,693
Expensed exploration expenditures 330 450 594
Equipment acquired through a
non-cash capital lease transaction - - 2
Repayments of long-term debt
and other financing obligations 86 - -
- -----------------------------------------------------------------------------
Capital and exploratory expenditures,
excluding equity companies $3,739 $3,802 $4,289
=============================================================================
NOTE 5. STOCKHOLDERS' EQUITY Retained earnings at December 31, 1993, include
$2,087 for the company's share of undistributed earnings of equity
affiliates.
In 1988, the company declared a dividend distribution of one Right for each
outstanding share of common 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. Each Right entitles its
holder to purchase stock having a value equal to two times the exercise
price of the Right. The person or group who had acquired 10 percent
FS-20
NOTE 5. STOCKHOLDERS' EQUITY - Continued
or more of the outstanding shares of common stock without the prior consent
of the company would not be entitled to this purchase opportunity.
The Rights will expire in November 1998, or they may be redeemed by the
company at 5 cents per share 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 1993 made the Rights exercisable.
The Board of Directors has proposed a two-for-one split of the company's
issued common stock. Stockholders have been asked to approve the split and
an increase in authorized shares of common stock from 500 million to 1
billion to accommodate the split at the annual stockholders' meeting on May
3, 1994. If approved, the split will be effective May 11, 1994 for
stockholders of record on that date.
NOTE 6. FINANCIAL INSTRUMENTS
OFF-BALANCE SHEET RISK. 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. Offsetting gains and losses on these contracts
are recognized concurrently with the exchange gains and losses stemming from
the associated commitments. At December 31, 1993 and 1992, the company had
not recognized gains or losses on forward contracts with a carrying and
approximate fair value of $114 and $119, respectively.
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 and trade receivables.
The company's cash equivalents and marketable securities are in high-quality
securities placed with a wide array of institutions with high credit ratings.
This investment policy limits the company's exposure to concentrations of
credit risk.
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. At December 31, 1993, the company's long-term debt of $2,057 had
an estimated fair value of $2,238. The fair value is based on quoted market
prices at December 31, 1993, or the present value of expected cash flows
when a quoted market price was not available.
The reported amounts of financial instruments such as Cash equivalents,
Marketable securities and Short-term debt approximate fair value because of
their short maturity.
NOTE 7. SUMMARIZED FINANCIAL DATA - CHEVRON U.S.A. INC. At December 31, 1993,
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). These operations are
conducted by three divisions: Chevron U.S.A. Production Company, Chevron
U.S.A. Products Company and Warren Petroleum Company. Summarized financial
information for Chevron U.S.A. Inc. and its consolidated subsidiaries is
presented below:
Year Ended December 31
-----------------------------
1993 1992* 1991*
- -----------------------------------------------------------------------------
Sales and other operating revenues $28,092 $29,454 $29,073
Total costs and other deductions 27,588 28,410 28,861
Income before cumulative effect
of changes in accounting principles 325 811 90
Cumulative effect
of changes in accounting principles - (573) -
Net income 325 238 90
=============================================================================
At December 31
----------------
1993 1992
- -----------------------------------------------------------------------------
Current assets $3,661 $4,200
Other assets 14,099 14,587
Current liabilities 5,936 5,528
Other liabilities 5,738 6,795
Net equity 6,086 6,464
=============================================================================
*To conform to the presentation adopted in 1993, the 1992 and 1991 periods
have been reclassified to net certain offsetting crude oil purchases and
sales contracts. The reclassification had no effect on net income. See Note 1.
NOTE 8. LITIGATION The company is a defendant in numerous lawsuits, in
addition to those mentioned in this note. Plaintiffs may seek to recover
large and sometimes unspecified amounts, and some matters may remain
unresolved for several years.
In April 1991, a United States District Court in Texas ruled favorably on
claims brought by former employees of Gulf and participants in the Gulf
Pension Plan that a partial termination of the plan had occurred. However,
the court denied plaintiffs' claims to a share of any surplus plan assets.
In October 1991, the district court approved a partial settlement in which
the parties agreed not to appeal the partial termination claims except as
relevant to plaintiffs' claims for a share of surplus plan assets. These
claims are now before the Fifth Circuit Court of Appeals. A second partial
settlement was implemented in 1993, resulting in a charge to earnings of
$48.
A lawsuit brought against the company by OXY USA Inc., the successor in
interest to Cities Service Company, remains pending in an Oklahoma state
court. The suit involves claims for breach of contract and misrepresentation
related to the termination of Gulf Oil Corporation's offer to purchase
Cities' stock in 1982. (Gulf was acquired by Chevron in 1984.)
FS-21
NOTE 8. LITIGATION - Continued
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.
NOTE 9. GEOGRAPHIC AND SEGMENT DATA The geographic and segment distributions
of the company's identifiable assets, operating income and sales and other
operating revenues are summarized in the following tables. The company's
primary business is its integrated petroleum operations. Secondary operations
include chemicals and coal. The company's real estate and insurance
operations and worldwide cash management and financing activities are in
"Corporate and Other."
At December 31
-----------------------------
1993 1992 1991
- -----------------------------------------------------------------------------
IDENTIFIABLE ASSETS
United States
Petroleum $16,443 $18,508 $20,056
Chemicals 2,045 2,165 2,210
Coal and Other Minerals 744 762 767
----------------------------
Total United States 19,232 21,435 23,033
-----------------------------
International
Petroleum 12,202 9,671 9,018
Chemicals 412 390 402
Coal and Other Minerals 13 10 12
- -----------------------------------------------------------------------------
Total International 12,627 10,071 9,432
- -----------------------------------------------------------------------------
TOTAL IDENTIFIABLE ASSETS 31,859 31,506 32,465
Corporate and Other 2,877 2,464 2,171
- -----------------------------------------------------------------------------
TOTAL ASSETS $34,736 $33,970 $34,636
- -----------------------------------------------------------------------------
Year Ended December 31
-----------------------------
1993 1992 1991
- -----------------------------------------------------------------------------
OPERATING INCOME
United States
Petroleum $ 692 $ 1,693 $ 289
Chemicals 162 46 149
Coal and Other Minerals 59 68 27
-----------------------------
Total United States 913 1,807 465
-----------------------------
International
Petroleum 1,772 1,731 2,205
Chemicals 63 70 47
Coal and Other Minerals (3) 177 (26)
-----------------------------
Total International 1,832 1,978 2,226
- -----------------------------------------------------------------------------
TOTAL OPERATING INCOME 2,745 3,785 2,691
Corporate and Other (319) (322) (439)
Income Tax Expense (1,161) (1,253) (959)
- -----------------------------------------------------------------------------
Income Before Cumulative Effect of Changes
in Accounting Principles $ 1,265 $ 2,210 $ 1,293
Cumulative Effect of Changes in
Accounting Principles - (641) -
- -----------------------------------------------------------------------------
NET INCOME $ 1,265 $ 1,569 $ 1,293
=============================================================================
Year Ended December 31
-----------------------------
1993 1992* 1991*
-----------------------------
SALES AND OTHER OPERATING REVENUES
United States
Petroleum-Refined products $13,169 $13,964 $13,921
-Crude oil 4,086 5,138 6,649
-Natural gas 1,776 1,631 1,502
-Natural gas liquids 1,098 1,075 1,043
-Other petroleum revenues 682 700 611
-Excise taxes 2,554 2,458 2,267
-Intersegment 924 1,052 1,226
-----------------------------
Total Petroleum 24,289 26,018 27,219
-----------------------------
Chemicals-Products 2,211 2,409 2,652
-Intersegment 248 266 252
-----------------------------
Total Chemicals 2,459 2,675 2,904
-----------------------------
Coal and Other Minerals-Products 447 395 417
-----------------------------
Total United States 27,195 29,088 30,540
- -----------------------------------------------------------------------------
International
Petroleum-Refined products 2,920 2,857 2,873
-Crude oil 4,415 4,893 3,627
-Natural gas 380 364 367
-Natural gas liquids 137 115 122
-Other petroleum revenues 285 227 201
-Excise taxes 1,499 1,490 1,374
-Intersegment 1 10 13
-----------------------------
Total Petroleum 9,637 9,956 8,577
-----------------------------
Chemicals-Products 497 463 446
-Excise taxes 15 16 18
-Intersegment 6 5 4
-----------------------------
Total Chemicals 518 484 468
-----------------------------
Coal and Other Minerals-Products - 2 10
-----------------------------
Total International 10,155 10,442 9,055
- -----------------------------------------------------------------------------
Intersegment sales elimination (1,179) (1,333) (1,495)
- -----------------------------------------------------------------------------
Corporate and Other 20 15 18
- -----------------------------------------------------------------------------
TOTAL SALES AND OTHER OPERATING REVENUES $36,191 $38,212 $38,118
=============================================================================
Memo: Intergeographic Sales
United States $ 266 $ 309 $ 361
International 4,418 3,823 3,497
- -----------------------------------------------------------------------------
*To conform to the presentation adopted in 1993, the 1992 and 1991 periods
have been reclassified to net certain offsetting crude oil purchases and
sales contracts. The reclassification had no effect on net income. See Note 1.
Operating income for the geographic areas includes allocated corporate
overhead. In 1992 and 1991, the operating income for the business segments
excluded corporate charges of $63 and $154 for a companywide voluntary
enhanced early retirement program. In 1992, $103 of pension settlement gains
were recognized in connection with the program. These amounts are included
in "Corporate and Other."
Identifiable assets include all assets associated with operations in the
indicated geographic areas, including investments in affiliates.
Sales and other operating revenues for the petroleum segment are derived from
the production and sale of crude oil,
FS-22
NOTE 9. GEOGRAPHIC AND SEGMENT DATA - Continued
natural gas and natural gas liquids, and from the refining and marketing of
petroleum products. The company also obtains revenues from the transportation
and trading of crude oil and refined products. Chemicals revenues result
primarily from the sale of petrochemicals, plastic resins, and lube oil and
fuel additives. Coal and other minerals revenues relate primarily to coal
sales.
Sales and other operating revenues in the above table include both sales to
unaffiliated customers and sales from the transfer of products between
segments. Sales from the transfer of products between segments and geographic
areas are generally at estimated market prices. Transfers between geographic
areas are presented as memo items below the table.
Equity in earnings of affiliated companies has been associated with the
segments in which the affiliates operate. Sales to the Caltex Group are
included in the International petroleum segment. Information on these
affiliates is presented in Note 11. Other affiliates are either not material
or not vertically integrated with a segment's operations.
NOTE 10. LEASE COMMITMENTS Certain non-cancelable 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
-----------------
1993 1992
- -----------------------------------------------------------------------------
Petroleum
Exploration and Production $ 50 $ 50
Refining, Marketing and Transportation 554 553
- -----------------------------------------------------------------------------
604 603
Less: accumulated amortization 409 381
- -----------------------------------------------------------------------------
Net capitalized leased assets $195 $222
=============================================================================
At December 31, 1993, the future minimum lease payments under operating and
capital leases are as follows:
At December 31
--------------------
Operating Capital
Year Leases Leases
- -----------------------------------------------------------------------------
1994 $174 $ 41
1995 143 48
1996 128 43
1997 110 41
1998 100 42
Thereafter 220 500
- -----------------------------------------------------------------------------
Total $875 715
- ------------------------------------------------------------------
Less: amounts representing interest
and executory costs (292)
- -----------------------------------------------------------------------------
Net present value 423
Less: capital lease obligations
included in short-term debt (278)
- -----------------------------------------------------------------------------
Long-term capital lease obligations $145
=============================================================================
Future sublease rental income $ 46 $ -
=============================================================================
Rental expenses incurred for operating leases during 1993, 1992 and 1991 were
as follows:
At December 31
-----------------------------
1993 1992 1991
- -----------------------------------------------------------------------------
Minimum rentals $452 $408 $472
Contingent rentals 9 10 11
- -----------------------------------------------------------------------------
Total 461 418 483
Less: sublease rental income 15 14 49
- -----------------------------------------------------------------------------
Net rental expense $446 $404 $434
=============================================================================
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 11. INVESTMENTS AND ADVANCES Investments in and advances to companies
accounted for using the equity method, and other investments accounted for
at or below cost, are as follows:
At December 31
-----------------
1993 1992
- -----------------------------------------------------------------------------
Equity Method Affiliates
Caltex Group $2,147 $1,905
Other affiliates 1,353 450
- -----------------------------------------------------------------------------
3,500 2,355
Other, at or below cost 123 96
- -----------------------------------------------------------------------------
Total investments and advances $3,623 $2,451
=============================================================================
Chevron owns 50 percent each of P.T. Caltex Pacific Indonesia, an exploration
and production company operating in Indonesia; Caltex Petroleum Corporation,
which, through its subsidiaries and affiliates, conducts refining and
marketing activities in Asia, Africa, Australia and New Zealand; and American
Overseas Petroleum Limited, which, through its subsidiaries, manages certain
of the company's exploration and production operations in Indonesia. These
companies and their subsidiaries and affiliates are collectively called the
Caltex Group.
Other affiliates includes Tengizchevroil, a 50 percent owned joint venture
formed in 1993 with the Republic of Kazakhstan, to develop the Tengiz oil
field.
Equity in earnings of companies accounted for by the equity method, together
with dividends and similar distributions received from equity method
companies for the years 1993, 1992 and 1991, are as follows:
Year Ended December 31
- ----------------------------------------------------------------------------
Equity in Earnings Dividends
------------------------ -------------------------
1993 1992 1991 1993 1992 1991
- ----------------------------------------------------------------------------
Caltex Group $361 $334* $422 $172 $183 $202
Other affiliates 79 72 69 95 79 68
- ----------------------------------------------------------------------------
Total $440 $406 $491 $267 $262 $270
============================================================================
*Before cumulative effect of changes in accounting principles.
FS-23
NOTE 11. INVESTMENTS AND ADVANCES - Continued
The company's transactions with affiliated companies, primarily for the
purchase of Indonesian crude oil from P.T. Caltex Pacific Indonesia and the
sale of crude oil and products to Caltex Petroleum Corporation's refining and
marketing companies, are summarized in the following table.
Year Ended December 31
----------------------------
1993 1992 1991
- -----------------------------------------------------------------------------
Sales to Caltex Group $1,739 $1,784 $1,537
Sales to other affiliates 5 5 66
- -----------------------------------------------------------------------------
Total sales to affiliates $1,744 $1,789 $1,603
=============================================================================
Purchases from Caltex Group $ 842 $ 797 $ 821
Purchases from other affiliates 101 56 23
- -----------------------------------------------------------------------------
Total purchases from affiliates $943 $853 $844
- -----------------------------------------------------------------------------
Accounts and notes receivable in the consolidated balance sheet include $156
and $215 at December 31, 1993 and 1992, respectively, of amounts due from
affiliated companies. Accounts payable include $35 and $33 at December 31,
1993 and 1992, respectively, of amounts due to affiliated companies.
The following tables summarize the combined financial information for the
Caltex Group and substantially 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 1993 1992 1991 1993 1992 1991 1993 1992 1991
- ------------------------------------------------------------------------------------------------------------------------------
Sales and other operating revenues $15,409 $17,281 $15,445 $1,972 $1,995 $2,085 $8,229 $9,148 $8,282
Total costs and other deductions 14,392 16,255 14,251 1,542 1,458 1,674 7,633 8,543 7,587
Net income 720 720* 839 374 416 323 440 431 491
==============================================================================================================================
*After cumulative effect of $51 benefit from adoption of SFAS 106 and 109, of which Chevron's share of $25 is included in
cumulative effect of changes in accounting principles in the consolidated statement of income.
Caltex Group Other Affiliates Chevron's Share
----------------------------- -------------------------- --------------------------
At December 31 1993 1992 1991 1993 1992 1991 1993 1992 1991
- ------------------------------------------------------------------------------------------------------------------------------
Current assets $ 2,123 $ 2,378 $ 2,494 $ 766 $ 788 $ 775 $1,256 $1,375 $1,468
Other assets 6,266 5,485 4,869 3,871 2,186 2,065 4,731 3,433 3,037
Current liabilities 2,411 2,453 2,398 471 540 409 1,332 1,364 1,314
Other liabilities 1,683 1,591 1,480 2,620 746 793 1,155 1,090 1,006
Net equity 4,295 3,819 3,485 1,546 1,688 1,638 3,500 2,354 2,185
==============================================================================================================================
NOTE 12. PROPERTIES, PLANT AND EQUIPMENT
At December 31 Year Ended December 31
---------------------------------------------------- ----------------------------------------------
Gross Investment at Cost Net Investment Additions at Cost (1) Depreciation Expense
------------------------- ------------------------- ---------------------- ----------------------
1993 1992 1991 1993 1992 1991 1993 1992 1991 1993 1992 1991
- ----------------------------------------------------------------------------------------------------------------------------------
UNITED STATES
Petroleum
Exploration and Production $17,608 $17,707 $20,349 $ 6,189 $ 6,703 $ 8,189 $ 663 $ 609 $ 896 $1,064 $1,264 $1,413
Refining and Marketing 10,693 10,762 10,148 6,187 6,345 5,945 960 980 989 460 430 397
Chemicals 1,899 1,803 1,878 1,225 1,219 1,235 174 182 176 124 127 122
Coal and Other Minerals 848 836 819 488 511 516 32 58 88 54 50 48
- ----------------------------------------------------------------------------------------------------------------------------------
Total United States 31,048 31,108 33,194 14,089 14,778 15,885 1,829 1,829 2,149 1,702 1,871 1,980
- ----------------------------------------------------------------------------------------------------------------------------------
INTERNATIONAL
Petroleum
Exploration and Production 8,729 7,892 7,451 4,353 3,980 3,757 1,014 1,000 865 519 496 427
Refining and Marketing 2,385 2,367 2,093 1,686 1,658 1,470 219 304 450 106 97 69
Chemicals 313 280 254 148 142 134 24 26 29 25 18 19
Coal and Other Minerals 12 11 20 10 7 8 3 1 (6) - - 7
- ----------------------------------------------------------------------------------------------------------------------------------
Total International 11,439 10,550 9,818 6,197 5,787 5,369 1,260 1,331 1,338 650 611 522
- ----------------------------------------------------------------------------------------------------------------------------------
Corporate and Other (2) 2,320 2,352 2,256 1,579 1,623 1,596 96 209 178 100 112 114
- ----------------------------------------------------------------------------------------------------------------------------------
TOTAL $44,807 $44,010 $45,268 $21,865 $22,188 $22,850 $3,185 $3,369 $3,665 $2,452 $2,594 $2,616
==================================================================================================================================
(1) Net of dry hole expense related to prior years' expenditures of $29, $57 and $35 in 1993, 1992 and 1991, respectively.
(2) Includes primarily real estate and management information systems.
Expenses for maintenance and repairs were $875, $1,045 and $1,229 in 1993,
1992 and 1991, respectively.
FS-24
NOTE 13.TAXES
Year Ended December 31
---------------------------
1993 1992 1991
- -----------------------------------------------------------------------------
Taxes Other Than on Income
United States
Taxes on production $ 135 $ 140 $ 153
Import duties 21 18 17
Excise taxes on products and merchandise 2,554 2,458 2,267
Property and other miscellaneous
taxes (excluding payroll taxes) 380 416 428
---------------------------
3,090 3,032 2,865
Payroll taxes 122 141 145
- -----------------------------------------------------------------------------
Total United States 3,212 3,173 3,010
- -----------------------------------------------------------------------------
International
Taxes on production 7 30 14
Import duties 22 55 50
Excise taxes on products and merchandise 1,514 1,506 1,392
Property and other miscellaneous
taxes (excluding payroll taxes) 112 114 111
---------------------------
1,655 1,705 1,567
Payroll taxes 19 21 20
- -----------------------------------------------------------------------------
Total international 1,674 1,726 1,587
- -----------------------------------------------------------------------------
Total taxes other than on income $4,886 $4,899 $4,597
=============================================================================
Year Ended December 31
---------------------------
1993 1992 1991
- -----------------------------------------------------------------------------
Taxes on Income
U.S. federal
Current $ 394 $ 329 $ 163
Deferred (241) (129) (185)
Deferred - Adjustment for enacted
changes in tax laws/rates 54 - -
State and local 63 54 16
- -----------------------------------------------------------------------------
Total United States 270 254 (6)
- -----------------------------------------------------------------------------
International
Current 864 1,046 963
Deferred 48 (47) 2
Deferred - Adjustment for enacted
changes in tax laws/rates (21) - -
- -----------------------------------------------------------------------------
Total international 891 999 965
- -----------------------------------------------------------------------------
Total taxes on income $1,161 $1,253 $ 959
=============================================================================
U.S. federal income tax expense was reduced by $57, $49 and $27 in 1993, 1992
and 1991, respectively, for low-income housing and other business tax credits.
In 1993, before-tax income for U.S. operations was $687, compared with $1,592
in 1992 and $157 in 1991. Before-tax income for international operations was
$1,739, $1,871 and $2,095 in 1993, 1992 and 1991, respectively.
The deferred income tax provisions included benefits of $98, $163 and $67
related to properties, plant and equipment in 1993, 1992 and 1991,
respectively. U.S. benefits were recorded in 1993 related to the U.S.
refining and marketing restructuring provision. The 1991 U.S. deferred tax
provision included benefits accrued from the reserves established for the
Port Arthur reconfiguration and the corporate severance program.
In 1992, the tax related to the cumulative effect of adopting SFAS 106
(Note 2) was $423, representing deferred income tax benefits approximating
the statutory tax rate.
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
---------------------------
1993 1992 1991
- -----------------------------------------------------------------------------
Statutory U.S. federal income tax rate 35.0% 34.0% 34.0%
Effects of income taxes on
international operations in excess
of taxes at the U.S. statutory rate 15.6 15.2 23.7
Effects of asset dispositions (0.6) (8.0) (2.0)
State and local taxes on income,
net of U.S. federal income tax benefit 2.2 1.1 0.6
Prior-year tax adjustments 3.0 (0.6) (4.2)
Effects of enacted changes in tax
laws/rates on deferred tax liabilities 1.3 - -
Tax credits (2.4) (1.4) (1.2)
All others (0.9) (0.9) (1.8)
- -----------------------------------------------------------------------------
Consolidated companies 53.2 39.4 49.1
Effect of recording equity in income of certain
affiliated companies on an after-tax basis (5.3) (3.2) (6.5)
- -----------------------------------------------------------------------------
Effective tax rate 47.9% 36.2% 42.6%
=============================================================================
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, 1993 and 1992, deferred taxes were classified in the
consolidated balance sheet, as follows:
Year Ended December 31
----------------------
1993 1992
- -----------------------------------------------------------------------------
Prepaid expenses and other current assets $ (495) $ (313)
Deferred charges and other assets (146) (132)
Federal and other taxes on income 27 24
Non-current deferred income taxes 2,916 2,894
- -----------------------------------------------------------------------------
Total deferred taxes, net $2,302 $2,473
- -----------------------------------------------------------------------------
The reported deferred tax balances are composed of the following deferred tax
liabilities (assets):
Year Ended December 31
----------------------
1993 1992
- -----------------------------------------------------------------------------
Properties, plant and equipment $3,933 $3,869
Inventory 293 318
Miscellaneous 237 195
- -----------------------------------------------------------------------------
Deferred tax liabilities 4,463 4,382
- -----------------------------------------------------------------------------
Abandonment/environmental reserves (910) (792)
Employee benefits (535) (492)
AMT/other tax credits (486) (580)
Other accrued liabilities (472) (338)
Miscellaneous (255) (159)
- -----------------------------------------------------------------------------
Deferred tax assets (2,658) (2,361)
- -----------------------------------------------------------------------------
Deferred tax assets valuation allowance 497 452
- -----------------------------------------------------------------------------
Total deferred taxes, net $2,302 $2,473
=============================================================================
FS-25
NOTE 13. 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 $3,300 at December 31,
1993. 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 $247 would be payable upon remittance of these earnings.
NOTE 14. SHORT-TERM DEBT
At December 31
-----------------
1993 1992
- -----------------------------------------------------------------------------
Commercial paper $4,391 $4,023
Current maturities of long-term debt 167 89
Current maturities of long-term capital leases 23 24
Redeemable long-term obligations
Long-term debt 297 320
Capital leases 255 255
Notes payable 203 277
- -----------------------------------------------------------------------------
5,336 4,988
Reclassified to long-term debt (1,880) (2,100)
- -----------------------------------------------------------------------------
Total short-term debt $3,456 $2,888
=============================================================================
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.
Selected data on the company's commercial paper activities are shown below:
Weighted Weighted
Average Maximum Average
Interest Outstanding Average Interest
Balance at Rate at at Any Amount Rate for
Year December 31 December 31 Month End Outstanding the Year
- -----------------------------------------------------------------------------
1993 $4,390 3.3% $4,891 $4,445 3.1%
1992 $4,023 3.5% $4,441 $3,958 3.6%
1991 $2,748 4.8% $2,748 $1,863 5.7%
=============================================================================
The average amounts outstanding and weighted average interest rates during
each year are based on average daily balances outstanding. Amounts used in
the above computations include amounts that have been classified as long-term
debt during 1993, 1992 and 1991.
NOTE 15. LONG-TERM DEBT
At December 31
-----------------
1993 1992
- -----------------------------------------------------------------------------
8.11% amortizing notes due 2004 (1) $ 750 $ 750
8.25% notes due 1996 (2) - 301
8.75% notes due 1996 (2) - 300
9.375% sinking-fund debentures due 2016 278 292
6.76% serial notes due 1994-1997 (1), (3) 190 220
7.875% notes due 1997 (4) 200 199
5.6% notes due 1998 190 -
9.75% sinking-fund debentures due 2017 179 190
4.625% 200 million Swiss franc issue due 1997 136 137
Other long-term obligations (6.88%) (3)
(less than $50 individually) 223 318
Other foreign currency obligations (6.81%) (3) 78 66
- -----------------------------------------------------------------------------
Total including debt due within one year 2,224 2,773
Debt due within one year (167) (89)
Reclassified from short-term debt (3.17%) (3) 1,880 2,100
- -----------------------------------------------------------------------------
Total long-term debt $3,937 $4,784
=============================================================================
(1) Guarantee of ESOP debt.
(2) Debt retired before maturity date.
(3) Weighted average interest rate at December 31, 1993.
(4) Called in early 1994.
Chevron and one of its wholly owned subsidiaries have "shelf" registrations
on file with the Securities and Exchange Commission (SEC) that would permit
the issuance of $1,050 of debt securities pursuant to Rule 415 of the
Securities Act of 1933.
At year-end 1993, the company had $3,595 of committed credit facilities with
banks worldwide, $1,880 of which had termination dates beyond one year. These
credit agreements provide commitments for term loans of up to $3,280 and
revolving credit for short-term advances of up to $315. The facilities also
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 nor at year-end.
At December 31, 1993 and 1992, the company classified $1,880 and $2,100,
respectively, of short-term debt as long-term. Settlement of these
obligations is not expected to require the use of working capital in 1994,
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, 1993, is as follows: 1994-$167, 1995-$89, 1996-$93, 1997-$435 and
1998-$198.
NOTE 16. EMPLOYEE BENEFIT PLANS
PENSION PLANS. The company has defined benefit pension plans for most
employees. The principal plans provide for automatic membership on a
non-contributory basis. The retirement benefits provided by these plans are
based primarily on years of service and on average career earnings or the
highest consecutive three years' average earnings. The company's policy is
to fund at least the minimum necessary to satisfy requirements of the
Employee Retirement Income Security Act.
FS-26
NOTE 16. EMPLOYEE BENEFIT PLANS - Continued
The net pension expense (credit) for all of the company's pension plans for
the years 1993, 1992 and 1991 consisted of:
1993 1992 1991
- -----------------------------------------------------------------------------
Cost of benefits earned during the year $103 $106 $100
Interest cost on projected
benefit obligations 276 302 295
Actual return on plan assets (472) (309) (799)
Net amortization and deferral 101 (134) 346
- -----------------------------------------------------------------------------
Net pension expense (credits) $ 8 $(35) $(58)
=============================================================================
In addition to the net pension expense in 1993, the company recognized a net
settlement loss of $63 and a curtailment loss of $4 reflecting the
termination of a former Gulf pension plan and lump-sum payments from other
company pension plans. In 1992, the company recorded charges of $65 and a
curtailment loss of $7, offset by net lump-sum settlement gains of $101
related to an early retirement program offered to employees of its U.S. and
certain Canadian subsidiaries. In 1991, charges of $154 related to the early
retirement programs and lump sum settlement gains of $25 were recognized.
At December 31, 1993 and 1992, the weighted average discount rates and
long-term rates for compensation increases used for estimating the benefit
obligations and the expected rates of return on plan assets were as follows:
1993 1992
- -----------------------------------------------------------------------------
Assumed discount rates 7.4% 8.1%
Assumed rates for compensation increases 5.1% 5.5%
Expected return on plan assets 9.1% 9.2%
- -----------------------------------------------------------------------------
The pension plans' assets consist primarily of common stocks, bonds, cash
equivalents and interests in real estate investment funds. The funded status
for the company's combined plans at December 31, 1993 and 1992, was as
follows:
Plans with
Plans with Assets Accumulated
in Excess of Benefits
Accumulated in Excess of
Benefits Plan Assets
------------------- -----------------
At December 31 1993 1992 1993 1992
- -----------------------------------------------------------------------------
Actuarial present value of:
Vested benefit obligations $(2,854) $(2,869) $(183) $(161)
=============================================================================
Accumulated benefit obligations $(2,949) $(2,947) $(194) $(168)
=============================================================================
Projected benefit obligations $(3,456) $(3,395) $(229) $(184)
Plan assets at fair values 3,831 3,893 1 6
- -----------------------------------------------------------------------------
Plan assets greater (less) than
projected benefit obligations 375 498 (228) (178)
Unrecognized net transition
(assets) liabilities (349) (426) 20 22
Unrecognized net losses 41 17 74 34
Unrecognized prior service costs 84 85 7 -
Minimum liability adjustment - - (52) (52)
- -----------------------------------------------------------------------------
Net pension cost prepaid
(accrued) $ 151 $ 174 $(179) $(174)
- -----------------------------------------------------------------------------
The net transition assets and liabilities generally are being amortized by
the straight-line method over 15 years.
PROFIT SHARING/SAVINGS PLAN AND SAVINGS PLUS 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 and the Savings Plus Plan.
Charges to expense for the profit sharing part of the Profit Sharing/Savings
Plan and the Savings Plus Plan were $95, $84 and $104 in 1993, 1992 and 1991,
respectively.
EMPLOYEE STOCK OWNERSHIP PLAN (ESOP). In December 1989, the company
established an ESOP as part of the Profit Sharing/Savings Plan. The ESOP
Trust Fund borrowed $1,000 and purchased 14.1 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. As interest
and principal payments are made on the ESOP debt, shares are released from a
suspense account and allocated to profit sharing accounts of plan participants.
The ESOP is expected to satisfy most of the company's obligations to the
profit sharing part of the Profit Sharing/Savings Plan during the next 11
years. Other company obligations to the profit sharing part of the plan will
be satisfied by cash contributions. The company recorded expense for the ESOP
of $60, $50 and $44 in 1993, 1992 and 1991, respectively, including $74, $75
and $69 of interest expense related to the ESOP loan. All dividends paid on
the shares held by the ESOP will be used to service the ESOP debt. The
dividends used were $47, $35 and $40 in 1993, 1992 and 1991, respectively.
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
makes outright distributions of cash for services rendered or deferred
awards in the form of stock units. Awards under LTIP may take the form of,
but are not limited to, stock options, restricted stock, stock units and
non-stock grants. Stock options become exercisable not earlier than one year
and not later than 10 years from the date of grant.
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. As of December 31, 1993, 2,151,505 shares were under option at
exercise prices ranging from $63.875 to $87.75 per share. Stock option
transactions for 1993 and 1992 are as follows:
FS-27
NOTE 16. EMPLOYEE BENEFIT PLANS - Continued
At December 31
----------------
Thousands of shares 1993 1992
- -----------------------------------------------------------------------------
Outstanding January 1 1,967 1,265
Granted 706 725
Exercised (509) (6)
Forfeited (12) (17)
- -----------------------------------------------------------------------------
Outstanding December 31 2,152 1,967
=============================================================================
Exercisable December 31 1,456 1,250
=============================================================================
Charges to expense for the combined management incentive plans were $36, $20
and $37 in 1993, 1992 and 1991, respectively.
OTHER BENEFIT PLANS. In addition to providing pension benefits, the company
makes contributions toward certain health care and life insurance plans for
active and qualifying retired employees. Substantially all employees in the
United States and in certain international locations may become eligible for
coverage under these benefit plans. The company's annual contributions for
medical and dental benefits are limited to the lesser of actual medical and
dental 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.
Under SFAS 106, adopted effective January 1, 1992, the company's net
postretirement benefits expense was as follows:
1993 1992
--------------------- --------------------
Health Life Total Health Life Total
- -----------------------------------------------------------------------------
Cost of benefits earned
during the year $23 $ 3 $ 26 $23 $ 4 $ 27
Interest cost
on benefit obligation 76 30 106 70 30 100
- -----------------------------------------------------------------------------
Net postretirement
benefits expense $99 $33 $132 $93 $34 $127
=============================================================================
1991 expense under the cash method was $60.
Non-pension postretirement benefits are funded by the company when incurred.
A reconciliation of the funded status of these benefit plans is as follows:
At December 31, 1993 At December 31, 1992
------------------------ -----------------------
Health Life Total Health Life Total
- -----------------------------------------------------------------------------
Accumulated
postretirement benefit
obligation (APBO)
Retirees $ (593) $(320) $ (913) $(598) $(281) $ (879)
Fully eligible
active participants (139) (64) (203) (109) (47) (156)
Other active
participants (271) (56) (327) (272) (49) (321)
- -----------------------------------------------------------------------------
Total APBO (1,003) (440) (1,443) (979) (377) (1,356)
Fair value
of plan assets - - - - - -
- -----------------------------------------------------------------------------
APBO (greater) than
plan assets (1,003) (440) (1,443) (979) (377) (1,356)
Unrecognized
net loss (gain) 63 25 88 69 (12) 57
- -----------------------------------------------------------------------------
Accrued postretirement
benefit costs $ (940) $(415) $(1,355) $(910) $(389) $(1,299)
=============================================================================
For measurement purposes, separate health care cost-trend rates were utilized
for pre-age 65 and post-age 65 retirees. The 1994 annual rates of increase
were assumed to be 8.0 percent and 8.9 percent, respectively, decreasing to
average ultimate rates of 5.9 percent in 1997 for pre-age 65 and 5.4 percent
in 1997 for post-age 65. An increase in the assumed health care cost-trend
rates of 1 percent in each year would increase the aggregate of service and
interest cost for the year 1993 by $19 and would increase the December 31,
1993 accumulated postretirement benefit obligation (APBO) by $166.
At December 31, 1993 the weighted average discount rate was 7.25 percent
and the assumed rate of compensation increase related to the measurement
of the life insurance benefit was 5.0 percent.
FS-28
NOTE 17. OTHER CONTINGENT LIABILITIES AND COMMITMENTS The U.S. federal income
tax and California franchise tax liabilities of the company have been settled
through 1976 and 1987, respectively. Settlement of open tax matters is not
expected to have a material effect on the consolidated financial position of
the company and, in the opinion of management, adequate provision has been
made for income and franchise taxes for all years either under examination or
subject to future examination. The Internal Revenue Service (IRS) has asserted
tax deficiencies against the other three stockholders of Arabian American Oil
Co. (Aramco) regarding the pricing of crude oil purchased from Saudi Arabia
during the period 1979 through 1981. In December 1993, the U.S. Tax Court
ruled in favor of Exxon and Texaco on this issue. It is not known if the IRS
will appeal this decision. The IRS may have until late 1995 to appeal since
other tax issues related to the 1979-81 period must be resolved. Chevron has
not received any proposed tax deficiency concerning this issue. In July 1991,
the IRS issued a "Designated Summons" that requires Chevron to produce
additional documents in connection with the Saudi pricing issue. The
Designated Summons extends the statutory period for assessing additional tax.
As directed by the District Court, Chevron completed production of documents
before year-end 1993. Further motions regarding compliance with the Summons
are expected in 1994. After Chevron complies with the Summons, the IRS may
propose tax deficiencies similar to those asserted against other Aramco
stockholders. The company believes that it properly accounted for the Saudi
crude in its tax return and that it owes no additional U.S. taxes.
At December 31, 1993, the company and its subsidiaries, as direct or indirect
guarantors, had contingent liabilities of $234 for notes of affiliated
companies and $45 for notes of others.
The company and its subsidiaries have certain other contingent liabilities
with respect to guarantees and claims and has long-term commitments under
various agreements, the payments and future commitments for which are not
material in the aggregate.
In September 1990, the Minerals Management Service of the U.S. Department of
the Interior (the Service) issued a preliminary determination letter to the
effect that the company owed additional royalty payments on natural gas the
company produced from federal leasehold interests and sold under long-term
supply contracts. The company made royalty payments based on the contract
price received, rather than on the basis of published weighted average gas
prices, which were higher. The company has submitted an answer refuting the
preliminary determination. The Service has the matter under review and has
not rendered an order directing payment. However, the parties are continuing
to explore settlement.
In March 1992, an agency within the Department of Energy (DOE) issued a
Proposed Remedial Order (PRO) claiming Chevron failed to comply with DOE
regulations in the course of its participation in the Tertiary Incentive
Program. Although the DOE regulations involved were rescinded in March 1981,
following decontrol of crude oil prices in January 1981, and the statute
authorizing the regulations expired in September 1981, the PRO purports to be
for the period April 1980 through April 1990. The DOE claims the company
overrecouped under the regulations by $125 during the period in question.
Including interest through December 1993, the total claim amounted to $273.
The company asserts that in fact it incurred a loss through participation in
the DOE program. The Office of Hearings and Appeals has granted Chevron's
motion for evidentiary hearing and discovery. No date has yet been set for the
evidentiary hearing.
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, operating refineries, closed refineries, oil fields, service
stations, terminals and land development areas. 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 insurance.
The company's operations, particularly oil and gas exploration and production,
can be affected by changing economic, regulatory and political environments in
the various countries, including the United States, in which it operates. In
certain locations, host governments have imposed restrictions, controls and
taxes, and, in others, political conditions have existed that may threaten the
safety of employees and the company's continued presence in those countries.
Internal unrest or strained relations between a host government and the
company or other governments may affect the company's operations. Those
developments have, at times, significantly affected the company's related
operations and results, and are carefully considered by management when
evaluating the level of current and future activity in such countries.
Areas in which the company has significant operations include the United
States, Australia, United Kingdom, Canada, Nigeria, Angola, Papua New Guinea,
China, Indonesia and Zaire. The company's Caltex affiliates have significant
operations in Indonesia, Japan, Korea, Australia, the Philippines, Thailand
and South Africa. The company's Tengizchevroil affiliate operates in
Kazakhstan.
FS-29
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 69), this section
provides supplemental information on oil and gas exploration and producing
activities of the company in six separate tables. The first three tables
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 other geographic
category includes activities in the United Kingdom North Sea, Canada, Papua
New Guinea, Australia and other countries. Amounts shown for affiliated
companies are Chevron's 50 percent equity share in each of P.T. Caltex Pacific
Indonesia (CPI), an exploration and production company operating in Indonesia,
and Tengizchevroil (TCO), an exploration and production company operating in
the Republic of Kazakhstan, which began operations in April 1993.
TABLE I - COSTS INCURRED IN EXPLORATION, PROPERTY ACQUISITIONS AND
DEVELOPMENT (1)
Consolidated Companies
- ------------------------------------------------------
Millions of Affiliated
dollars U.S. Africa Other Total Companies Worldwide
- -----------------------------------------------------------------------------
YEAR ENDED DECEMBER 31, 1993
Exploration
Wells $ 123 $ 57 $126 $ 306 $ 1 $ 307
Geological and
geophysical 12 40 40 92 9 101
Rentals and other 48 7 70 125 - 125
- -----------------------------------------------------------------------------
Total exploration 183 104 236 523 10 533
- -----------------------------------------------------------------------------
Property acquisitions (2)
Proved (3) 12 - 14 26 276 302
Unproved 11 9 10 30 420 450
- -----------------------------------------------------------------------------
Total property
acquisitions 23 9 24 56 696 752
- -----------------------------------------------------------------------------
Development 475 239 566 1,280 171 1,451
- -----------------------------------------------------------------------------
Total Costs
Incurred $ 681 $352 $826 $1,859 $877(4) $2,736
=============================================================================
YEAR ENDED DECEMBER 31, 1992
Exploration
Wells $ 96 $ 59 $ 83 $ 238 $ 1 $ 239
Geological and
geophysical 84 48 137 269 8 277
Rentals and other 9 1 21 31 - 31
- -----------------------------------------------------------------------------
Total exploration 189 108 241 538 9 547
- -----------------------------------------------------------------------------
Property acquisitions (2)
Proved (3) 19 - 36 55 - 55
Unproved 16 1 10 27 - 27
- -----------------------------------------------------------------------------
Total property
acquisitions 35 1 46 82 - 82
- -----------------------------------------------------------------------------
Development 483 189 682 1,354 171 1,525
- -----------------------------------------------------------------------------
Total Costs
Incurred $ 707 $298 $969 $1,974 $180 $2,154
=============================================================================
YEAR ENDED DECEMBER 31, 1991
Exploration
Wells $ 205 $ 65 $150 $ 420 $ 1 $ 421
Geological and
geophysical 98 45 164 307 8 315
Rentals and other 18 2 8 28 2 30
- -----------------------------------------------------------------------------
Total exploration 321 112 322 755 11 766
- -----------------------------------------------------------------------------
Property acquisitions (2)
Proved (3) - 1 4 5 - 5
Unproved 59 8 33 100 - 100
- -----------------------------------------------------------------------------
Total property
acquisitions 59 9 37 105 - 105
- -----------------------------------------------------------------------------
Development 665 152 569 1,386 164 1,550
- -----------------------------------------------------------------------------
Total Costs
Incurred $1,045 $273 $928 $2,246 $175 $2,421
- -----------------------------------------------------------------------------
(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.
(4) In 1993, Total Costs Incurred for affiliated companies includes
$146 for CPI.
FS-30
TABLE II - CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES
Consolidated Companies
- -------------------------------------------------------
Affiliated
Millions of dollars U.S. Africa Other Total Companies Worldwide
- -----------------------------------------------------------------------------
AT DECEMBER 31, 1993
Unproved properties $ 404 $ 31 $ 206 $ 641 $ 420 $ 1,061
Proved properties
and related
producing assets 15,655 1,528 4,646 21,829 1,005 22,834
Support equipment 750 105 303 1,158 546 1,704
Deferred
exploratory wells 139 23 60 222 - 222
Other uncompleted
projects 269 296 879 1,444 466 1,910
- -----------------------------------------------------------------------------
Gross capitalized
costs 17,217 1,983 6,094 25,294 2,437 27,731
- -----------------------------------------------------------------------------
Unproved properties
valuation 280 20 103 403 - 403
Proved producing
properties -
Depreciation and
depletion 9,645 799 2,467 12,911 386 13,297
Future abandonment
and restoration 1,002 195 276 1,473 13 1,486
Support equipment
depreciation 338 52 149 539 238 777
- -----------------------------------------------------------------------------
Accumulated
provisions 11,265 1,066 2,995 15,326 637 15,963
- -----------------------------------------------------------------------------
Net Capitalized
Costs $ 5,952 $ 917 $3,099 $ 9,968 $1,800* $11,768
=============================================================================
AT DECEMBER 31, 1992
Unproved properties $ 481 $ 23 $ 217 $ 721 $ - $ 721
Proved properties
and related
producing assets 15,682 1,358 4,087 21,127 622 21,749
Support equipment 685 92 270 1,047 374 1,421
Deferred
exploratory wells 100 30 66 196 1 197
Other uncompleted
projects 443 203 910 1,556 368 1,924
- -----------------------------------------------------------------------------
Gross capitalized
costs 17,391 1,706 5,550 24,647 1,365 26,012
- -----------------------------------------------------------------------------
Unproved properties
valuation 327 17 110 454 - 454
Proved producing
properties -
Depreciation and
depletion 9,276 700 2,225 12,201 335 12,536
Future abandonment
and restoration 967 168 226 1,361 13 1,374
Support equipment
depreciation 296 50 133 479 218 697
- -----------------------------------------------------------------------------
Accumulated
provisions 10,866 935 2,694 14,495 566 15,061
- -----------------------------------------------------------------------------
Net Capitalized
Costs $ 6,525 $ 771 $ 2,856 $10,152 $ 799 $10,951
=============================================================================
AT DECEMBER 31, 1991
Unproved properties $ 658 $ 24 $ 389 $ 1,071 $ - $ 1,071
Proved properties
and related
producing assets 18,088 1,212 3,925 23,225 534 23,759
Support equipment 658 90 212 960 347 1,307
Deferred
exploratory wells 109 50 124 283 1 284
Other uncompleted
projects 528 179 656 1,363 322 1,685
- -----------------------------------------------------------------------------
Gross capitalized
costs 20,041 1,555 5,306 26,902 1,204 28,106
- -----------------------------------------------------------------------------
Unproved properties
valuation 429 12 110 551 - 551
Proved producing
properties -
Depreciation and
depletion 10,322 613 2,166 13,101 299 13,400
Future abandonment
and restoration 1,024 147 216 1,387 12 1,399
Support equipment
depreciation 262 60 117 439 203 642
- -----------------------------------------------------------------------------
Accumulated
Provisions 12,037 832 2,609 15,478 514 15,992
- -----------------------------------------------------------------------------
Net Capitalized
Costs $ 8,004 $ 723 $2,697 $11,424 $ 690 $12,114
=============================================================================
*At December 31, 1993, Net Capitalized Costs for affiliated companies
includes $860 for CPI.
FS-31
Unaudited
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 1993, 1992 and 1991 are shown below.
Net income from exploration and production activities as reported on Page
FS-6 includes the allocation of corporate overhead and income taxes computed
on an effective rate basis.
In accordance with SFAS 69, allocated corporate overhead is excluded from
the results below, and income taxes are based on statutory tax rates,
reflecting allowable deductions and tax credits. Interest expense is
excluded from both reported results.
Consolidated Companies
- -------------------------------------------------------
Affiliated
Millions of dollars U.S. Africa Other Total Companies Worldwide
- -----------------------------------------------------------------------------
YEAR ENDED DECEMBER 31, 1993
Revenues from net
production
Sales $1,539 $ 247 $ 779 $2,565 $ 63 $2,628
Transfers 1,912 1,040 661 3,613 487 4,100
- -----------------------------------------------------------------------------
Total 3,451 1,287 1,440 6,178 550 6,728
Production expenses (1,274) (208) (402) (1,884) (204) (2,088)
Proved producing
properties
depreciation,
depletion and
abandonment
provision (958) (126) (311) (1,395) (58) (1,453)
Exploration expenses (99) (79) (174) (352) (9) (361)
Unproved properties
valuation (31) (4) (12) (47) - (47)
Other income
(expense) (2) 20 - 8 28 6 34
- -----------------------------------------------------------------------------
Results before
income taxes 1,109 870 549 2,528 285 2,813
Income tax expense (422) (625) (243) (1,290) (152) (1,442)
- -----------------------------------------------------------------------------
RESULTS OF PRODUCING
OPERATIONS $ 687 $ 245 $ 306 $1,238 $133* $1,371
=============================================================================
YEAR ENDED DECEMBER 31, 1992
Revenues from net
production
Sales $1,558 $ 365 $ 816 $2,739 $ 19 $2,758
Transfers 2,301 1,097 580 3,978 519 4,497
- -----------------------------------------------------------------------------
Total 3,859 1,462 1,396 6,717 538 7,255
Production expenses (1,477) (194) (508) (2,179) (153) (2,332)
Proved producing
properties
depreciation,
depletion and
abandonment
provision (1,126) (110) (301) (1,537) (38) (1,575)
Exploration expenses (182) (79) (226) (487) (8) (495)
Unproved properties
valuation (38) (5) (17) (60) - (60)
Other income
(expense) (2) 431 27 72 530 (15) 515
- -----------------------------------------------------------------------------
Results before
income taxes 1,467 1,101 416 2,984 324 3,308
Income tax expense (420) (856) (231) (1,507) (170) (1,677)
- -----------------------------------------------------------------------------
Results of Producing
Operations $1,047 $ 245 $ 185 $1,477 $154 $1,631
=============================================================================
YEAR ENDED DECEMBER 31, 1991
Revenues from net
production
Sales $1,609 $ 268 $ 694 $2,571 $ 20 $2,591
Transfers 2,364 1,138 778 4,280 563 4,843
- -----------------------------------------------------------------------------
Total 3,973 1,406 1,472 6,851 583 7,434
Production expenses (1,870) (149) (439) (2,458) (148) (2,606)
Proved producing
properties
depreciation,
depletion and
abandonment
provision (1,259) (100) (252) (1,611) (35) (1,646)
Exploration expenses (220) (92) (298) (610) (10) (620)
Unproved properties
valuation (77) (3) (21) (101) - (101)
Other income
(expense) (2) 107 (5) 117 219 (15) 204
- -----------------------------------------------------------------------------
Results before
income taxes 654 1,057 579 2,290 375 2,665
Income tax expense (246) (894) (403) (1,543) (212) (1,755)
- -----------------------------------------------------------------------------
Results of Producing
Operations $ 408 $ 163 $ 176 $ 747 $163 $ 910
=============================================================================
*For 1993, Results of Producing Operations for affiliated companies
includes $134 for CPI.
FS-32
TABLE III - RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES (1)
- Continued
Per Unit Average Consolidated Companies
Sales Price and ------------------------------
Production Affiliated
Cost (1), (3) U.S. Africa Other Total Companies Worldwide
- -----------------------------------------------------------------------------
YEAR ENDED DECEMBER 31, 1993
Average sales prices
Liquids,
per barrel $14.48 $16.21 $16.06 $15.33 $13.06 $15.05
Natural gas,
per thousand
cubic feet 1.98 - 2.08 2.00 .13 1.99
Average production
costs, per barrel 4.91 2.62 4.22 4.34 4.77 4.38
=============================================================================
YEAR ENDED DECEMBER 31, 1992
Average sales prices
Liquids,
per barrel $16.02 $18.40 $17.66 $17.00 $14.87 $16.77
Natural gas,
per thousand
cubic feet 1.69 - 1.96 1.73 - 1.73
Average production
costs, per barrel 5.11 2.44 5.85 4.78 4.23 4.74
=============================================================================
YEAR ENDED DECEMBER 31, 1991
Average sales prices
Liquids,
per barrel $16.73 $19.00 $18.36 $17.63 $15.25 $17.36
Natural gas,
per thousand
cubic feet 1.53 - 2.24 1.63 - 1.63
Average production
costs, per barrel 6.29 2.01 5.10 5.37 3.87 5.26
=============================================================================
Average sales price
for liquids
($/bbl.)
DECEMBER 1993 $10.73 $12.94 $13.63 $12.05 $10.46 $11.82
December 1992 15.22 17.60 17.26 16.35 14.15 16.07
December 1991 15.08 17.39 18.76 16.43 14.38 16.19
=============================================================================
Average sales price
for natural gas
($/MCF)
DECEMBER 1993 $ 2.19 $ - $ 2.34 $ 2.21 $ .26 $ 2.20
December 1992 2.17 - 1.99 2.14 - 2.14
December 1991 1.93 - 2.51 2.00 - 2.00
=============================================================================
(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 per unit average
sales price and production cost. This has no effect on the amount of
Results of Producing Operations.
(2) Includes gas-processing fees, net sulfur income, natural gas contract
settlements, currency transaction gains and losses, miscellaneous
expenses, etc. In 1993, the United States includes before-tax losses
on property dispositions and other special charges totaling $150.
In 1992, before-tax gains on property dispositions of $326 in the
United States were offset partially by net charges of $44 for
severance programs, regulatory issues and other adjustments; Other
includes $192 of before-tax gains on sales of producing and
nonproducing properties, partially offset by a before-tax charge of
$165 for the write-down of Beaufort Sea properties. In 1991, losses
and property dispositions in the United States were offset by
favorable adjustments to litigation and other reserves; the Other
geographic segment included $89 of before-tax gains on property
dispositions.
(3) Natural gas converted to crude oil equivalent gas (OEG) barrels at a
rate of 6 MCF=1 OEG barrel.
TABLE IV - RESERVE QUANTITIES INFORMATION
The company's estimated net proved underground oil and gas reserves and
changes thereto for the years 1993, 1992 and 1991 are shown in the
following table. These quantities are estimated by the company's reserves
engineers and reviewed by the company's Reserves Advisory Committee using
reserve definitions prescribed by the Securities and Exchange Commission.
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 over time as
additional information becomes available.
Proved reserves do not include additional quantities recoverable beyond the
term of 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.
Upon formation of the Tengizchevroil joint venture in April 1993, the
company recognized 1.1 billion barrels of net proved crude oil and natural
gas liquids reserves and 1.5 trillion cubic feet of net natural gas
reserves, which represented its 50 percent ownership.
FS-33
Unaudited
TABLE IV - RESERVE QUANTITIES INFORMATION - Continued
NET PROVED RESERVES OF CRUDE OIL,
CONDENSATE AND NATURAL GAS LIQUIDS NET PROVED RESERVES OF NATURAL GAS
Millions of barrels Billions of cubic feet
------------------------------------------------------ ----------------------------------------------------
Consolidated Companies
------------------------------- Consolidated Companies
Affiliated ------------------------------ Affiliated
U.S. Africa Other Total Companies Worldwide U.S. Africa Other Total Companies Worldwide
- ----------------------------------------------------------------------------- ---------------------------------------------------
RESERVES AT
JANUARY 1, 1991 1,653 617 524 2,794 447 3,241 7,086 - 2,215 9,301 142 9,443
Changes
attributable to:
Revisions 35 58 27 120 39 159 395 - 539 934 5 939
Improved recovery 37 1 9 47 7 54 3 - 20 23 6 29
Extensions and
discoveries 19 34 18 71 3 74 195 - 86 281 12 293
Purchases (1) 20 - 4 24 - 24 43 - 3 46 - 46
Sales (2) (30) - (17) (47) - (47) (292) - (35) (327) - (327)
Production (166) (74) (64) (304) (45) (349) (861) - (148) (1,009) (15) (1,024)
- ---------------------------------------------------------------------------- ----------------------------------------------------
RESERVES AT
DECEMBER 31, 1991 1,568 636 501 2,705 451 3,156 6,569 - 2,680 9,249 150 9,399
Changes
attributable to:
Revisions 38 19 24 81 34 115 255 - (11) 244 17 261
Improved recovery 23 12 2 37 198 235 1 - - 1 3 4
Extensions and
discoveries 22 27 21 70 2 72 346 - 19 365 - 365
Purchases (1) 4 - 8 12 - 12 14 - 65 79 - 79
Sales (2) (129) - (20) (149) - (149) (839) - (78) (917) - (917)
Production (158) (79) (64) (301) (44) (345) (847) - (157) (1,004) (12) (1,016)
- ---------------------------------------------------------------------------- ----------------------------------------------------
RESERVES AT
DECEMBER 31, 1992 1,368 615 472 2,455 641 3,096 5,499 - 2,518 8,017 158 8,175
Changes
attributable to:
Revisions (36) 42 (2) 4 53 57 383 - (142) 241 (3) 238
Improved recovery 74 - 25 99 21 120 7 - - 7 2 9
Extensions and
discoveries 24 105 18 147 2 149 349 - 44 393 - 393
Purchases (1) 10 - 18 28 1,106 1,134 24 - 9 33 1,533 1,566
Sales (2) (17) - (7) (24) - (24) (27) - (21) (48) - (48)
Production (144) (80) (71) (295) (52) (347) (751) - (151) (902) (20) (922)
- ---------------------------------------------------------------------------- ----------------------------------------------------
RESERVES AT
DECEMBER 31, 1993 1,279 682 453 2,414 1,771 (3) 4,185 5,484 - 2,257 7,741 1,670 (3) 9,411
============================================================================ ====================================================
Developed reserves
- ---------------------------------------------------------------------------- -----------------------------------------------------
At January 1, 1991 1,460 487 337 2,284 274 2,558 6,512 - 1,761 8,273 137 8,410
At December 31, 1991 1,421 524 313 2,258 338 2,596 5,971 - 2,006 7,977 135 8,112
At December 31, 1992 1,251 498 315 2,064 368 2,432 4,812 - 1,845 6,657 150 6,807
AT DECEMBER 31, 1993 1,151 503 310 1,964 932 2,896 4,863 - 1,647 6,510 714 7,224
============================================================================ =====================================================
(1) Includes reserves acquired through property exchanges.
(2) Includes reserves disposed of through property exchanges, including, in 1992 in the United States, the exchange of an oil
and gas subsidiary for 15,750,000 shares of Chevron common stock owned by a stockholder.
(3) At December 31, 1993, Net Proved Reserves of Crude Oil, Condensate and Natural Gas Liquids for affiliated companies includes
669 for CPI; Net Proved Reserves of Natural Gas includes 142 for CPI.
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 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 69 requires assumptions as to
the timing of future production from proved reserves and 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-34
Unaudited
TABLE V - STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATED TO PROVED OIL AND GAS RESERVES - CONTINUED
Consolidated Companies
---------------------------------------------
Millions Affiliated
of dollars U.S. Africa Other Total Companies Worldwide
- ---------------------------------------------------------------------------------------------------------------------
AT DECEMBER 31, 1993
Future cash inflows from production $24,990 $ 8,680 $10,590 $44,260 $19,660 $63,920
Future production and development costs (13,510) (3,640) (4,740) (21,890) (13,900) (35,790)
Future income taxes (3,490) (3,020) (1,660) (8,170) (2,280) (10,450)
- ---------------------------------------------------------------------------------------------------------------------
Undiscounted future net cash flows 7,990 2,020 4,190 14,200 3,480 17,680
10 percent midyear annual discount for
timing of estimated cash flows (3,400) (700) (1,500) (5,600) (2,340) (7,940)
- ---------------------------------------------------------------------------------------------------------------------
STANDARDIZED MEASURE OF DISCOUNTED
FUTURE NET CASH FLOWS $ 4,590 $ 1,320 $ 2,690 $ 8,600 $ 1,140* $ 9,740
=====================================================================================================================
AT DECEMBER 31, 1992
Future cash inflows from production $32,820 $10,770 $13,910 $57,500 $10,820 $68,320
Future production and development costs (15,240) (2,280) (5,670) (23,190) (6,870) (30,060)
Future income taxes (5,420) (4,020) (2,420) (11,860) (2,010) (13,870)
- ---------------------------------------------------------------------------------------------------------------------
Undiscounted future net cash flows 12,160 4,470 5,820 22,450 1,940 24,390
10 percent midyear annual discount for
timing of estimated cash flows (5,450) (1,560) (2,700) (9,710) (930) (10,640)
- ---------------------------------------------------------------------------------------------------------------------
Standardized Measure of Discounted
Future Net Cash Flows $ 6,710 $ 2,910 $ 3,120 $12,740 $ 1,010 $13,750
=====================================================================================================================
AT DECEMBER 31, 1991
Future cash inflows from production $35,090 $11,060 $14,540 $60,690 $ 7,960 $68,650
Future production and development costs (21,520) (2,260) (6,640) (30,420) (3,980) (34,400)
Future income taxes (3,740) (5,510) (3,170) (12,420) (2,240) (14,660)
- ---------------------------------------------------------------------------------------------------------------------
Undiscounted future net cash flows 9,830 3,290 4,730 17,850 1,740 19,590
10 percent midyear annual discount for
timing of estimated cash flows (4,280) (1,250) (2,020) (7,550) (630) (8,180)
- ---------------------------------------------------------------------------------------------------------------------
Standardized Measure of Discounted
Future net Cash Flows $ 5,550 $ 2,040 $ 2,710 $10,300 $ 1,110 $11,410
=====================================================================================================================
*At December 31, 1993, the Standardized Measure of Discounted Future Net Cash Flows for affiliated companies
includes $800 for CPI.
TABLE VI - CHANGES IN THE STANDARDIZED MEASURE
OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED RESERVES
Consolidated Companies Affiliated Companies Worldwide
-------------------------- ------------------------ ---------------------------
Millions of dollars 1993 1992 1991 1993 1992 1991 1993 1992 1991
- ------------------------------------------------------------------------------------------------------------------------------
PRESENT VALUE AT JANUARY 1 $12,740 $10,300 $17,710 $1,010 $1,110 $1,730 $13,750 $11,410 $19,440
- ------------------------------------------------------------------------------------------------------------------------------
Sales and transfers of oil and gas
produced, net of production costs (4,294) (4,538) (4,363) (346) (385) (435) (4,640) (4,923) (4,798)
Development costs incurred 1,280 1,354 1,386 171 171 164 1,451 1,525 1,550
Purchases of reserves 30 89 106 436 - - 466 89 106
Sales of reserves (72) (1,723) (665) - - - (72) (1,723) (665)
Extensions, discoveries and improved
recovery, less related costs 922 912 728 5 810 54 927 1,722 782
Revisions of previous quantity estimates 1,210 1,217 1,445 560 (817) 522 1,770 400 1,967
Net changes in prices, development and
production costs (6,602) 2,633 (17,420) (1,123) (401) (2,186) (7,725) 2,232 (19,606)
Accretion of discount 1,775 1,641 3,101 205 239 380 1,980 1,880 3,481
Net change in income tax 1,611 855 8,272 222 283 881 1,833 1,138 9,153
- ------------------------------------------------------------------------------------------------------------------------------
Net change for the year (4,140) 2,440 (7,410) 130 (100) (620) (4,010) 2,340 (8,030)
- ------------------------------------------------------------------------------------------------------------------------------
PRESENT VALUE AT DECEMBER 31 $ 8,600 $12,740 $10,300 $1,140 $1,010 $1,110 $9,740 $13,750 $11,410
==============================================================================================================================
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." The decline at year-end 1993 is due primarily to lower crude oil prices.
FS-35
FIVE-YEAR FINANCIAL SUMMARY (1)
Millions of dollars, except per-share amounts 1993 1992 (2) 1991 (2) 1990 1989
- ---------------------------------------------------------------------------------------------------------------------------------
CONSOLIDATED STATEMENT OF INCOME DATA
REVENUES
Sales and other operating revenues
Refined products $16,089 $16,821 $16,794 $19,385 $15,682
Crude oil 8,501 10,031 10,276 11,303 6,791
Natural gas 2,156 1,995 1,869 2,056 1,693
Natural gas liquids 1,235 1,190 1,165 1,305 937
Other petroleum 967 927 812 769 719
Chemicals 2,708 2,872 3,098 3,325 3,048
Coal and other minerals 447 397 427 443 470
Excise taxes 4,068 3,964 3,659 2,933 2,473
Corporate and other 20 15 18 21 103
- ---------------------------------------------------------------------------------------------------------------------------------
Total sales and other operating revenues 36,191 38,212 38,118 41,540 31,916
Equity in net income of affiliated companies 440 406 491 371 350
Other income 451 1,059 334 655 519
- ---------------------------------------------------------------------------------------------------------------------------------
TOTAL REVENUES 37,082 39,677 38,943 42,566 32,785
COSTS, OTHER DEDUCTIONS AND INCOME TAXES 35,817 37,467 37,650 40,409 32,534
- ---------------------------------------------------------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES $ 1,265 $ 2,210 $ 1,293 $ 2,157 $ 251
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES - (641) - - -
- ---------------------------------------------------------------------------------------------------------------------------------
NET INCOME (LOSS) $ 1,265 $ 1,569 $ 1,293 $ 2,157 $ 251
=================================================================================================================================
PER SHARE OF COMMON STOCK:
INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES $3.89 $6.52 $3.69 $6.10 $0.73
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES - (1.89) - - -
- ---------------------------------------------------------------------------------------------------------------------------------
NET INCOME (LOSS) PER SHARE OF COMMON STOCK $3.89 $4.63 $3.69 $6.10 $0.73
=================================================================================================================================
CASH DIVIDENDS PER SHARE $3.50 $3.30 $3.25 $2.95 $2.80
=================================================================================================================================
CONSOLIDATED BALANCE SHEET DATA (YEAR-END)
Current assets $ 8,682 $ 8,722 $ 9,031 $10,089 $ 8,620
Properties, plant and equipment (net) 21,865 22,188 22,850 22,726 23,040
Total assets 34,736 33,970 34,636 35,089 33,884
Short-term debt 3,456 2,888 1,706 59 126
Other current liabilities 7,150 6,947 7,774 8,958 7,457
Long-term debt and capital lease obligations 4,082 4,953 5,991 6,710 7,390
Stockholders' equity 13,997 13,728 14,739 14,836 13,980
Per share $ 42.97 $ 42.22 $ 42.51 $ 42.29 $ 39.38
=================================================================================================================================
SELECTED DATA
Return on average stockholders' equity 9.1% 11.0% 8.7% 15.0% 1.8%
Return on average capital employed 6.8% 8.5% 7.5% 11.9% 3.2%
Total debt/total debt plus equity 35.0% 36.4% 34.3% 31.3% 35.0%
Capital and exploratory expenditures (3) $ 4,440 $ 4,423 $ 4,787 $ 4,269 $ 3,982
Common stock price - High $98 3/8 $75 3/8 $80 1/8 $81 5/8 $72
- Low $67 3/4 $60 1/8 $63 1/2 $63 1/8 $45 3/4
- Year-end $87 1/8 $69 1/2 $69 $72 5/8 $67 3/4
Common shares outstanding at year-end (in thousands) 325,739 325,174 346,722 350,800 355,024
Weighted average shares outstanding for the year (in thousands) 325,479 338,977 350,174 353,463 341,889
Number of employees at year-end 47,576 49,245 55,123 54,208 54,826
=================================================================================================================================
(1) Comparability between years is affected by changes in accounting methods: 1992 and 1993 reflect adoption of Statements of
Financial Accounting Standards (SFAS) No. 106, "Employers' Accounting for Postretirement Benefits other than Pensions" and
SFAS No. 109, "Accounting for Income Taxes"; 1989 through 1991 reflect the adoption of SFAS No. 96, "Accounting for Income
Taxes".
(2) To conform to the presentation adopted in 1993, the years 1992 and 1991 have been reclassified to net certain offsetting
crude oil purchases and sales contracts. This classification had no effect on net income. These types of transactions were
insignificant in 1990 and prior years.
(3) Includes equity in affiliates' expenditures. $701 $621 $498 $433 $389
FS-36
CALTEX GROUP OF COMPANIES
COMBINED FINANCIAL STATEMENTS
AND SCHEDULES
December 31, 1993
C-1
CALTEX GROUP OF COMPANIES
COMBINED FINANCIAL STATEMENTS AND SCHEDULES
DECEMBER 31, 1993
INDEX
SCHEDULE
NUMBER PAGE(S)
-------- -----------
General Information . . . . . . . . . . . . . . . . . . C-3 to C-4
Independent Auditors' Report . . . . . . . . . . . . . C-5
Combined Balance Sheet . . . . . . . . . . . . . . . . C-6 to C-7
Combined Statement of Income . . . . . . . . . . . . . C-8
Combined Statement of Retained Earnings . . . . . . . C-9
Combined Statement of Cash Flows . . . . . . . . . . . C-9
Notes to Combined Financial Statements . . . . . . . . C-10 to C-19
Property, Plant and Equipment . . . . . . . . . . . . V C-20
Accumulated Depreciation, Depletion and Amortization . VI C-21
NOTE: All other 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. The private joint venture was created in Bahrain
in 1936 by its two owners to produce, refine and market crude oil and refined
products. Headquartered in Irving, Texas, the Group is comprised of the
following companies:
Caltex Petroleum Corporation, a company incorporated in Delaware, that
through its many subsidiaries and affiliates, conducts refining and
marketing activities in the Eastern Hemisphere;
P. T. Caltex Pacific Indonesia, an exploration and production company
incorporated and operating in Indonesia;
American Overseas Petroleum Limited, a company incorporated in the
Bahamas, that, through its subsidiaries, manages certain exploration and
production operations in Indonesia in which Chevron and Texaco have
interests, but not necessarily jointly nor in the same properties.
A brief description of each company's operations and the Group's
environmental activities follows:
CALTEX PETROLEUM CORPORATION (CALTEX)
- -------------------------------------
Through its subsidiaries and affiliates, Caltex operates in 63 countries with
some of the highest economic and petroleum growth rates in the world,
principally in Africa, Asia, the Middle East, New Zealand and Australia.
Certain refining and marketing operations are conducted through joint
ventures, with equity interests in 14 refineries in 11 countries. Caltex'
share of refinery inputs approximated 869,000 barrels per day in 1993.
Caltex continues to improve its refineries with investments designed to
provide higher yields and meet environmental regulations. Construction of a
new 130,000 barrels per day refinery in Thailand is progressing with
completion anticipated in 1996. At year end 1993, Caltex had over 7,800
employees, of which about 3% were located in the United States.
With a strong presence in its principal operating areas, Caltex has an
average market share of 17.3% with refined product sales of approximately
1.3 million barrels per day in 1993. Caltex built 130 new branded retail
outlets during 1993 and refurbished 294 existing locations in its aim to
upgrade its retail distribution network.
Caltex conducts international crude oil and refined product logistics and
trading operations from a subsidiary in Singapore. Other offices are located
in London, Bahrain and Tokyo. The company has an interest in a fleet of
vessels and owns or has equity interests in numerous pipelines, terminals
and depots. Currently, Caltex is active in the petrochemical business,
particularly in Japan and South Korea.
P. T. CALTEX PACIFIC INDONESIA (CPI)
- ------------------------------------
CPI holds a Production Sharing Contract in Central Sumatra for which the
Indonesian government granted an extension to the year 2021 during 1992.
CPI also acts as operator for four other petroleum contract areas in Sumatra,
which are jointly held by Chevron and Texaco. Exploration is pursued
throughout an area comprising 2.446 million acres with production established
in the giant Minas and Duri fields, along with more than 80 smaller fields.
Gross production from fields operated by CPI for 1993 was 674,000 barrels per
day. CPI entitlements are sold to its shareholders, who use it in their
systems or sell it to third parties. In addition, during 1993 CPI began gas
exploration activities in the Nias block held jointly by Chevron and Texaco.
At year end 1993, CPI had over 6,400 employees, all located in Indonesia.
C-3
CALTEX GROUP OF COMPANIES
GENERAL INFORMATION
AMERICAN OVERSEAS PETROLEUM LIMITED (AOPL)
- ------------------------------------------
In addition to coordinating the CPI activities, AOPL, through its subsidiary
Amoseas Indonesia Inc., manages Texaco's and Chevron's undivided interest
holdings which include ten contract areas in Indonesia, excluding Sumatra.
Production is currently established in two contract areas, while exploration
is being pursued in seven others. One in Darajat in West Java contains
geothermal reserves sufficient to supply a 55-megawatt power generating
plant for over 30 years. Production of the geothermal reserves is expected
to begin in 1994 while the state owned utility company completes construction
of an associated power station. AOPL's 1993 share of production amounted to
38,400 barrels per day. At year end, AOPL had 281 employees, of which about
15% were located in the United States.
ENVIRONMENTAL ACTIVITIES
- ------------------------
The Group's activities are subject to environmental, health and safety
regulations in each of the countries in which it operates. Such regulations
vary significantly in degree of scope, standards and enforcement. The
Group's policy is to comply with all applicable environmental, health and
safety laws and regulations. The Group has an active program to ensure 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. At December 31, 1993, the Group
had accrued $12 million for various remediation activities. 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, 1993, the Group, including its equity share
of nonsubsidiary companies, incurred capital costs of $147 million and
nonremediation related operating expenses of $92 million. The major
component of the Group's expenditures is for the prevention of air pollution.
Based upon existing statutory and regulatory requirements, investment and
operating plans and known exposures, the Group believes environmental
expenditures will not materially affect its liquidity, financial position or
results of operations.
C-4
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, 1993 and 1992, and the related combined
statements of income, retained earnings, and cash flows for each of the years
in the three-year period ended December 31, 1993. In connection with our
audits of the combined financial statements, we also have audited the
financial statement schedules as listed in the accompanying index.
These combined financial statements and financial statement schedules are
the responsibility of the Group's management. Our responsibility is to
express an opinion on these combined financial statements and financial
statement schedules 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, 1993 and 1992 and the results of its
operations and its cash flows for each of the years in the three-year period
ended December 31, 1993, in conformity with generally accepted accounting
principles. Also in our opinion, the related financial statement schedules,
when considered in relation to the basic combined financial statements taken
as a whole, present fairly, in all material respects, the information set
forth therein.
As discussed in Notes 1 and 6 to the combined financial statements, effective
January 1, 1992, the Group adopted the provisions of the Financial Accounting
Standards Board's Statements of Financial Accounting Standards No. 106,
"Employers' Accounting for Postretirement Benefits Other Than Pensions" and
No. 109, "Accounting for Income Taxes."
KPMG PEAT MARWICK
Dallas, Texas
February 15, 1994
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
We hereby consent to the incorporation by reference in the Prospectuses
constituting part of the Registration Statements on Form S-3 (No. 2-98466)
and Form S-8 (Nos. 33-3899, 33-34039 and 33-35283) of Chevron Corporation,
and to the incorporation by reference in the Prospectus constituting part of
the Registration Statement on Form S-3 (No. 33-14307) of Chevron Capital
U.S.A. Inc. and Chevron Corporation, and to the incorporation by reference
in the Registration Statement on Form S-3 (No. 33-58838) of Chevron Canada
Finance Limited and Chevron Corporation, and to the incorporation by
reference in the Registration Statement on Form S-8 (No. 2-90907) of Caltex
Petroleum Corporation of our report dated February 15, 1994, relating to the
combined balance sheets of the Caltex Group of Companies as of December 31,
1993 and 1992 and the related combined statements of income, retained
earnings and cash flows and related financial statement schedules for each of
the years in the three-year period ended December 31, 1993, which report
appears in the December 31, 1993 Annual Report on Form 10-K of Chevron
Corporation.
KPMG PEAT MARWICK
Dallas, Texas
March 25, 1994
C-5
CALTEX GROUP OF COMPANIES
COMBINED BALANCE SHEET - DECEMBER 31, 1993 AND 1992
(MILLIONS OF DOLLARS)
ASSETS
1993 1992
CURRENT ASSETS: ------ ------
Cash and cash equivalents (including time
deposits of $64 in 1993 and $121 in 1992) $ 166 $ 239
Notes and accounts receivable, less allowance
for doubtful accounts of $14 in 1993 and $15 in 1992:
Trade 950 1,020
Other 155 115
Nonsubsidiary companies 112 173
------ ------
1,217 1,308
Inventories:
Crude oil 148 239
Refined products 532 512
Materials and supplies 56 55
------ ------
736 806
Deferred income taxes 4 25
------ ------
Total current assets 2,123 2,378
INVESTMENTS AND ADVANCES:
Nonsubsidiary companies at equity 1,796 1,427
Miscellaneous investments and long-term receivables,
less allowance of $7 in 1993 and 1992 195 173
------ ------
1,991 1,600
PROPERTY, PLANT AND EQUIPMENT, AT COST:
Producing 3,027 2,783
Refining 1,483 1,259
Marketing 2,252 2,107
Marine 35 35
Capitalized leases 119 113
------ ------
6,916 6,297
Less: Accumulated depreciation, depletion and amortization 2,878 2,628
------ ------
4,038 3,669
PREPAID AND DEFERRED CHARGES 237 216
------ ------
Total assets $8,389 $7,863
====== ======
See accompanying Notes to Combined Financial Statements.
C-6
CALTEX GROUP OF COMPANIES
COMBINED BALANCE SHEET - DECEMBER 31, 1993 AND 1992
(MILLIONS OF DOLLARS)
LIABILITIES AND STOCKHOLDERS' EQUITY
1993 1992
------ ------
CURRENT LIABILITIES:
Notes payable to banks and other
financial institutions $ 966 $ 830
Long-term debt due within one year 51 51
Accounts payable:
Trade and other 967 1,081
Stockholder companies 87 229
Nonsubsidiary companies 149 76
------ ------
1,203 1,386
Accrued liabilities 86 91
Estimated income taxes 105 95
------ ------
Total current liabilities 2,411 2,453
LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS 530 486
ACCRUED LIABILITY FOR EMPLOYEE BENEFITS 98 92
DEFERRED CREDITS 646 605
DEFERRED INCOME TAXES 263 270
MINORITY INTEREST IN SUBSIDIARY COMPANIES 146 138
STOCKHOLDERS' EQUITY:
Common stock 355 355
Additional paid-in capital 2 2
Retained earnings 3,688 3,310
Currency translation adjustment 250 152
------ ------
Total stockholders' equity 4,295 3,819
COMMITMENTS AND CONTINGENT LIABILITIES ------ ------
Total liabilities and stockholders' equity $8,389 $7,863
====== ======
See accompanying Notes to Combined Financial Statements.
C-7
CALTEX GROUP OF COMPANIES
COMBINED STATEMENT OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(MILLIONS OF DOLLARS)
1993 1992 1991
------- ------- -------
SALES AND OTHER OPERATING REVENUES (1) $15,409 $17,281 $15,445
OPERATING CHARGES:
Cost of sales and operating expenses (2) 13,431 15,348 13,394
Selling, general and administrative expenses 496 479 444
Depreciation, depletion and amortization 295 263 257
Maintenance and repairs 170 165 156
------- ------- -------
14,392 16,255 14,251
------- ------- -------
Operating income 1,017 1,026 1,194
OTHER INCOME (DEDUCTIONS):
Equity in net income of
nonsubsidiary companies 140 163 188
Dividends, interest and other income 99 83 288
Foreign exchange, net 23 21 (5)
Interest expense (93) (102) (131)
Minority interest in subsidiary companies (8) (13) (8)
------- ------- -------
161 152 332
------- ------- -------
Income before provision for income taxes
and cumulative effects of changes in
accounting principles 1,178 1,178 1,526
------- ------- -------
PROVISION FOR INCOME TAXES:
Current 433 456 649
Deferred 25 53 38
------- ------- -------
Total provision for income taxes 458 509 687
------- ------- -------
Income before cumulative effects
of changes in accounting principles 720 669 839
Cumulative effects of changes in
accounting principles - 51 -
------- ------- -------
Net income $ 720 $ 720 $ 839
======= ======= =======
(1) Includes sales to:
Stockholder companies $ 907 $ 835 $1,124
Nonsubsidiary companies $2,684 $3,075 $2,610
(2) Includes purchases from:
Stockholder companies $3,333 $3,917 $3,181
Nonsubsidiary companies $2,618 $2,198 $2,217
See accompanying Notes to Combined Financial Statements.
C-8
CALTEX GROUP OF COMPANIES
COMBINED STATEMENT OF RETAINED EARNINGS
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(MILLIONS OF DOLLARS)
1993 1992 1991
------- ------- -------
Balance at beginning of year $3,310 $2,955 $2,518
Net income 720 720 839
Cash dividends (342) (365) (402)
------- ------- -------
Balance at end of year $3,688 $3,310 $2,955
======= ======= =======
COMBINED STATEMENT OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(MILLIONS OF DOLLARS)
1993 1992 1991
------- ------- -------
OPERATING ACTIVITIES:
Net income $ 720 $ 720 $ 839
Adjustments to reconcile net income to net
cash provided by operating activities:
Cumulative effects of changes in
accounting principles - (51) -
Depreciation, depletion and amortization 295 263 257
Dividends from nonsubsidiary companies,
less than equity in net income (103) (133) (162)
Asset sales (4) (4) (200)
Deferred income taxes 25 53 38
Prepaid charges and deferred credits (41) 25 45
Changes in operating working capital 31 (58) 127
Other 10 (46) 5
------- ------- -------
Net cash provided by operating activities 933 769 949
------- ------- -------
INVESTING ACTIVITIES:
Capital expenditures (763) (711) (640)
Investments in and advances to
nonsubsidiary companies (149) (17) (1)
Net purchases of investment instruments (21) (11) (14)
Proceeds from asset sales 73 144 85
------- ------- -------
Net cash used in investing activities (860) (595) (570)
------- ------- -------
FINANCING ACTIVITIES:
Proceeds from borrowings having original terms
in excess of three months 745 831 643
Repayments of borrowings having original terms
in excess of three months (704) (857) (553)
Net increase (decrease) in other borrowings 140 94 (37)
Dividends paid, including minority interest (342) (365) (407)
------- ------- -------
Net cash used in financing activities (161) (297) (354)
------- ------- -------
Effect of exchange rate changes on cash
and cash equivalents 15 (8) (17)
------- ------- -------
NET CHANGE IN CASH AND CASH EQUIVALENTS (73) (131) 8
CASH AND CASH EQUIVALENTS AT
BEGINNING OF YEAR 239 370 362
------- ------- -------
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 166 $ 239 $ 370
======= ======= =======
See accompanying Notes to Combined Financial Statements.
C-9
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(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 Petroleum Corporation and subsidiaries,
American Overseas Petroleum Limited and subsidiaries and P.T. Caltex Pacific
Indonesia after the elimination of intercompany balances and transactions. A
subsidiary of Chevron Corporation and two subsidiaries of Texaco Inc.
(stockholders) each own 50% of the outstanding common shares. The Group is
primarily engaged in exploring, producing, refining and marketing crude oil
and refined products in the Eastern Hemisphere. The Group employs accounting
policies that are in accordance with generally accepted accounting principles
in the United States.
TRANSLATION OF FOREIGN CURRENCIES
The U.S. dollar is the functional currency for all principal subsidiary
operations. Nonsubsidiary companies in Japan and Korea use the local currency
as the functional currency.
INVENTORIES
Crude oil and refined product inventories are stated at the lower of cost
(primarily determined on the last-in, first-out (LIFO) method) or current
market value. Costs include applicable purchase and refining costs, duties,
import taxes, freight, etc. Materials and supplies are valued at average
cost.
INVESTMENTS AND ADVANCES
Investments in and advances to nonsubsidiary companies in which 20% to 50% of
the voting stock is owned by the Group, or in which the Group has the ability
to exercise significant influence, are accounted for by the equity method.
Under this method, the Group's equity in the earnings or losses of these
companies is included in current results, and the related investments reflect
the equity in the book value of underlying net assets. Investments in other
nonsubsidiary companies are carried at cost and related 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 the producing area, including intangible
development costs, are computed using the unit-of-production method.
All other assets are depreciated by class on a uniform straight line basis.
Depreciation rates are based upon the estimated useful life of each class of
property. In view of the numerous depreciation classifications, it is not
practical to provide a schedule of depreciation rates.
Maintenance and repairs necessary to maintain facilities in operating
condition are charged to income as incurred. Additions and betterments that
materially extend the life of properties are capitalized. Upon disposal of
properties, any net gain or loss is included in other income.
C-10
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - CONTINUED
DEFERRED INCOME TAXES
Effective January 1, 1992, deferred income taxes are recognized according to
the asset and liability method specified in Statement of Financial Accounting
Standards (SFAS) No. 109 "Accounting for Income Taxes" by applying individual
jurisdiction tax rates applicable to future years to differences between the
financial statement and tax basis carrying amounts of assets and liabilities.
The effect of tax rate changes on previously recorded deferred taxes is
recognized in the current year. Deferred income taxes for 1991 were
recognized under the method specified in SFAS No. 96.
No provision has been made for possible income taxes that might be payable if
accumulated earnings of subsidiary companies and nonsubsidiary companies
accounted for by the equity method were distributed, since such earnings have
been or are intended to be indefinitely reinvested.
ENVIRONMENTAL MATTERS
Compliance with environmental regulations is determined in relation to the
existing laws in each of the countries in which the Group operates and the
Group's own internal standards. The Group capitalizes expenditures that
create future benefits or contribute to future revenue generation.
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 nondiscounted
estimated costs using data 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 realization is determined to be probable.
RECLASSIFICATIONS
Certain amounts have been reclassified for preceding periods to conform with
the current year's presentation.
(2) INVENTORIES
The excess of current cost over the stated value of inventory maintained on
the LIFO basis was approximately $40 million and $91 million at December 31,
1993 and 1992, respectively. The reduction of LIFO inventories in certain
countries resulted in an increase in the earnings of consolidated
subsidiaries and nonsubsidiary companies at equity of approximately $1
million in 1993. Previous reductions in LIFO inventories resulted in a
decrease in earnings of $2 million in 1992 and an increase in earnings of $4
million in 1991.
Charges of $104 million and $25 million reduced income in 1993 and 1991,
respectively, to reflect a market value of certain inventories lower than
their LIFO carrying value. Earnings of $14 million were recorded in 1992 to
reflect a partial recovery of the 1991 charge.
C-11
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(3) NONSUBSIDIARY COMPANIES AT EQUITY
Investments in and advances to nonsubsidiary companies at equity at December
31 include the following (in millions):
Equity Share 1993 1992
------------ ------ ------
Nippon Petroleum Refining Company, Ltd. 50% $ 829 $ 727
Koa Oil Company, Ltd. 50% 310 268
Honam Oil Refinery Company, Ltd. 50% 423 357
All other Various 234 75
------ ------
$1,796 $1,427
====== ======
Shown below is summarized combined financial information for these non-
subsidiary companies (in millions):
100% Equity Share
---------------- -----------------
1993 1992 1993 1992
------ ------ ------ ------
Current assets $4,680 $5,149 $2,316 $2,564
Other assets 6,147 4,851 2,975 2,410
Current liabilities 4,900 4,946 2,349 2,470
Other liabilities 2,306 2,173 1,146 1,078
Net worth 3,621 2,881 1,796 1,426
100% Equity Share
------------------------- ----------------------
1993 1992 1991 1993 1992 1991
------- ------- ------- ------ ------ ------
Operating revenues $10,679 $10,502 $10,267 $5,304 $5,216 $5,102
Operating income 494 645 839 242 319 416
Net income 281 326 380 140 163 188
Retained earnings at December 31, 1993, includes $1.2 billion representing the
Group's share of undistributed earnings of nonsubsidiary companies at equity.
Cash dividends received from these nonsubsidiary companies were $37 million,
$30 million, and $26 million in 1993, 1992 and 1991, respectively.
Sales to the other 50 percent owner of Nippon Petroleum Refining Company, Ltd.
of products refined by Nippon Petroleum Refining Company, Ltd. and Koa Oil
Company, Ltd. were approximately $1.9 billion, $2 billion, and $2.1 billion
in 1993, 1992, and 1991, respectively.
C-12
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(4) NOTES PAYABLE
Information regarding short-term financing, consisting primarily of demand
loans, promissory notes, acceptance credits and overdrafts, is shown below
(dollars in millions):
Weighted Maximum Weighted Average
Average Outstanding Average Interest Rate
Borrowings At Interest Rate At Any Amount On Average
Year End At Year End Month End Outstanding Outstanding
------------- ------------- ---------- ----------- --------------
1993 $966 4.7% $1,041 $902 4.6%
1992 830 5.0 1,063 898 5.7
1991 907 7.2 996 875 9.9
Unutilized lines of credit available for short-term financing totaled $814
million at December 31, 1993.
(5) LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS
Long-term debt and capital lease obligations, with related interest rates at
December 31, 1993, consist of the following (in millions):
1993 1992
U.S. dollars: ---- ----
Variable interest rate term loans $173 $155
Fixed interest rate term loans with 7.6% average rate 220 205
Australian dollars:
Debentures with interest rates at 12.5% due 1995 - 1996 8 11
Promissory notes payable with 4.9% average rate 76 65
Capital lease obligations 33 33
New Zealand dollars:
Term loans with interest rates 6 - 6.35% due 1996-1997 14 -
Other 6 17
---- ----
$530 $486
==== ====
At December 31, 1993 and 1992, $101 million and $110 million, respectively, of
notes payable were classified as long-term debt. Settlement of these
obligations is not expected to require the use of working capital in 1994, as
the Group has both the intent and ability to refinance this debt on a long-
term basis. At December 31, 1993 and 1992, $101 million and $110 million,
respectively, of long-term committed credit facilities were available with
major banks to support notes payable classified as long-term debt.
Maturities subsequent to December 31, 1993 follow (in millions): 1994 - $51
(included on the combined balance sheet as a current liability); 1995 - $151;
1996 - $147; 1997 - $37; 1998 - $86; 1999 and thereafter - $109.
C-13
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(6) EMPLOYEE BENEFITS
The Group has retirement plans covering substantially all eligible employees.
Generally, these plans provide defined benefits based on final or final
average pay, as defined. The benefit levels, vesting terms and funding
practices vary among plans.
The funded status of retirement plans, primarily foreign and inclusive of
nonsubsidiary companies at equity, at December 31 follows (in millions):
Assets Exceed Accumulated
Accumulated Benefits
FUNDING STATUS Benefits Exceed Assets
------------ -------------
1993 1992 1993 1992
---- ---- ---- ----
Actuarial present value of:
Vested benefit obligation $280 $240 $117 $100
Accumulated benefit obligation 309 264 137 117
Projected benefit obligation 484 432 195 170
Amount of assets available for benefits:
Funded assets at fair value $450 $403 $ 39 $ 26
Net pension (asset) liability recorded (11) (8) 128 123
---- ---- ---- ----
Total assets $439 $395 $167 $149
==== ==== ==== ====
Assets less than projected
benefit obligation $(45) $(37) $(28) $(21)
Consisting of:
Unrecognized transition net assets
(liabilities) 31 38 (2) (4)
Unrecognized net losses (44) (42) (23) (16)
Unrecognized prior service costs (32) (33) (3) (1)
Weighted average rate assumptions:
Discount rate 9.5% 11.1% 6.5% 6.5%
Rate of increase in compensation 7.4% 9.0% 4.7% 4.7%
Expected return on plan assets 10.3% 11.4% 5.5% 4.9%
EXPENSES (Funded & Unfunded Combined) 1993 1992 1991
---- ---- ----
Cost of benefits earned during the year $ 27 $ 26 $ 21
Interest cost on projected benefit obligation 58 54 49
Actual return on plan assets (59) (9) (64)
Net amortization and deferral 16 (38) 22
---- ---- ----
$ 42 $ 33 $ 28
==== ==== ====
The Group adopted SFAS No. 106 "Employers' Accounting for Postretirement
Benefits Other Than Pensions" effective January 1, 1992, using the immediate
recognition option. SFAS No. 106 requires accrual, during the employees'
service with the Group, of the cost of their retiree health and life
insurance benefits. Prior to 1992, postretirement benefits were included in
expense as the benefits were paid.
C-14
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(6) EMPLOYEE BENEFITS - Continued
Certain companies within the Group provide health care and life insurance
benefits to retired employees. The plans which provide these benefits are
unfunded. As of December 31, 1993 and 1992, the accumulated postretirement
benefit obligation amounted to $47 million and $43 million, respectively,
with related accruals of $44 million and $43 million, respectively. The net
periodic postretirement benefit costs amounted to $6 million for each of the
years ending December 31, 1993 and 1992.
In November 1992 the Financial Accounting Standards Board issued SFAS No.
112 "Employers' Accounting for Postemployment Benefits." This new standard
requires companies to accrue, no later than 1994, for the cost for benefits
provided to former or inactive employees after employment but prior to
retirement. Adoption of this new standard is not expected to materially
impact the combined financial statements of the Group.
(7) OPERATING LEASES
The Group has various operating leases involving service stations, equipment
and other facilities for which net rental expense was $110 million, $95
million, and $53 million in 1993, 1992 and 1991, respectively.
Future net minimum rental commitments under operating leases having
noncancelable terms in excess of one year are as follows (in millions):
1994 - $42; 1995 - $42; 1996 - $42; 1997 - $37; 1998 - $31; 1999 and
thereafter - $146.
(8) CONTINGENT LIABILITIES
On January 25, 1990, Caltex Petroleum Corporation and certain of its
subsidiaries were named as defendants, along with privately held Philippine
ferry and shipping companies and the shipping company's insurer, in a lawsuit
filed in Houston, Texas State Court. After removal to Federal District Court
in Houston, the litigation's disposition turned on questions of federal court
jurisdiction and whether the case should be dismissed for forum non
conveniens. The plaintiffs' petition purported to be a class action on
behalf of at least 3,350 parties, who were either survivors of, or next of
kin of persons deceased in a collision in Philippine waters on December 20,
1987. One vessel involved in the collision was carrying Group products in
connection with a freight contract. Although the Group had no direct or
indirect ownership or operational responsibility for either vessel, various
theories of liability were alleged against the Group. No specific monetary
recovery was sought although the petition contained a variety of demands for
various categories of compensatory as well as punitive damages. These issues
were resolved in the Group's favor by the Federal District Court in March
1992, and that decision is now final. However, the plaintiffs had
separately filed another lawsuit, alleging the same causes of action as in
the Texas litigation, in Louisiana State Court in New Orleans in late 1988
but never served the Group until late December of 1993, after the decision
in the Texas litigation became final. Subsequent to receipt of the service,
the Group has removed this case to Federal District Court in New Orleans and
has moved for its dismissal. Management is contesting this case vigorously.
It is not possible to estimate the amount of damages involved, if any.
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 party insurance.
C-15
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(8) CONTINGENT LIABILITIES - Continued
The Group is also involved in certain other litigation and Internal Revenue
Service tax audits that could involve significant payments if such items are
all ultimately resolved adversely to the Group.
While it is impossible to ascertain the ultimate legal and financial
liability with respect to the above mentioned 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, results
of operations, or liquidity.
(9)FINANCIAL INSTRUMENTS
Certain Group companies are parties to financial instruments with off-balance
sheet credit and market risk, principally interest rate risk. As of December
31, the Group had commitments outstanding for interest rate swaps and foreign
currency transactions for which the notional or contractual amounts are as
follows (in millions):
1993 1992
---- ----
Interest rate swaps $344 $317
Commitments to purchase foreign currencies $338 $141
Commitments to sell foreign currencies $ 89 $ 20
The interest rate swaps are intended to hedge against fluctuations in interest
rates on debt, 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.
Commitments to purchase and sell foreign currencies are made to provide
exchange rate protection for specific transactions and to maximize economic
benefit based on expected currency movements. The above purchase and sale
commitments are at year end exchange rates and mature during the following
year. These commitments are marked to market and the resulting gains and
losses are recognized in current year income unless the contract is a specific
hedge of an identifiable transaction. There were no material differences
between the notional and estimated fair value for these commitments.
The Group's long-term debt, excluding capital lease obligations, of $497
million and $453 million at December 31, 1993 and 1992, respectively, had fair
values of $511 million and $462 million at December 31, 1993 and 1992,
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, Notes and accounts receivable, and all current liabilities
approximate fair value because of their short maturity.
Certain Group companies were contingently liable as guarantors for $7
million and $12 million at December 31, 1993 and 1992, respectively. The
Group also had commitments of $36 million and $96 million at December 31,
1993 and 1992, respectively, in the form of letters of credit which have
been issued on behalf of Group companies to facilitate either the Group's or
other parties' ability to trade in the normal course of business.
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 concentrations 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
or country is not considered sufficient. Credit losses have been
historically within management's expectations.
C-16
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(10) OTHER INCOME/DEDUCTIONS
In 1991, dividends, interest and other income included gains from asset sales
on a before and after tax basis of $200 million and $120 million, respectively.
Asset sales in 1993 and 1992 were not significant.
Net foreign exchange (exclusive of the currency translation adjustment) for
consolidated subsidiaries and nonsubsidiary companies at equity, after
applicable income taxes, amounted to gains of $32 million and $43 million in
1993 and 1992, respectively. The gain in 1991 was less than $1 million.
(11) TAXES
Taxes charged to income consist of the following (in millions):
1993 1992 1991
------ ------ ------
Taxes other than income taxes:
Duties, import and excise taxes $1,978 $1,891 $1,802
Other 29 29 29
------ ------ ------
Total taxes other than income taxes 2,007 1,920 1,831
Provision for income taxes 458 509 687
------ ------ ------
$2,465 $2,429 $2,518
====== ====== ======
The provision for income taxes, substantially all foreign, has been computed
on an individual company basis at rates in effect in the various countries of
operation. The actual tax expense differs from the "expected" tax expense
(computed by applying the U.S. Federal corporate tax rate to income before
provision for income taxes) as follows:
1993 1992 1991
----- ----- -----
Computed "expected" tax expense 35.0% 34.0% 34.0%
Effect of recording equity in net
income of nonsubsidiary companies
on an after tax basis (4.2) (4.9) (4.2)
Effect of dividends received
from subsidiary and
nonsubsidiary companies 4.2 3.8 3.3
Foreign income subject to foreign taxes
in excess of U.S. statutory tax rate 7.4 11.6 10.4
Decrease in deferred tax asset valuation
allowance (3.1) (.4) -
Other (.4) (.9) 1.5
----- ----- -----
38.9% 43.2% 45.0%
===== ===== =====
C-17
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(11) TAXES - Continued
Deferred income taxes are provided for the temporary differences between the
financial reporting basis and the tax basis of assets and liabilities.
Temporary differences and tax loss carryforwards which give rise to deferred
tax assets and liabilities at December 31, 1993 and 1992 are as follows (in
millions):
Deferred Deferred
Tax Assets Tax Liabilities
--------------- --------------
1993 1992 1993 1992
---- ---- ---- ----
Inventory $ 10 $ 27 $ 18 $ 17
Depreciation - - 298 275
Retirement plans 33 28 3 2
Tax loss carryforwards 29 36 - -
Other 28 30 34 30
---- ---- ---- ----
100 121 353 324
Valuation allowance (6) (42) - -
---- ---- ---- ----
Total deferred taxes $ 94 $ 79 $353 $324
==== ==== ==== ====
The valuation allowance has been established to record deferred tax assets at
amounts where recoverability is more likely than not. Net income was
increased by $36 million and $5 million for changes in the deferred tax asset
valuation allowance during 1993 and 1992, respectively.
Undistributed earnings for which no deferred income tax provision has been
made approximated $3.6 billion at December 31, 1993. Such earnings have been
or are intended to be indefinitely reinvested. These earnings would become
taxable in the U.S. only upon remittance as dividends. It is not practical
to estimate the amount of tax that might be payable on the eventual
remittance of such earnings. On remittance, certain foreign countries impose
withholding taxes which, subject to certain limitations, are then available
for use as tax credits against a U.S. tax liability, if any.
(12) CASH FLOWS
For purposes of the statement of cash flows, all highly liquid debt
instruments with original maturities of three months or less are considered
cash equivalents.
The "Changes in Operating Working Capital" consists of the following (in
millions):
1993 1992 1991
---- ---- ----
Notes and accounts receivable $ 82 $(45) $418
Inventories 66 (114) 62
Accounts payable (147) 212 (317)
Accrued liabilities 16 (27) (2)
Estimated income taxes 14 (84) (34)
---- ---- ----
Total $ 31 $(58) $127
==== ==== ====
C-18
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(12) CASH FLOWS - Continued
"Net Cash Provided by Operating Activities" includes the following cash
payments for interest and income taxes (in millions):
1993 1992 1991
---- ---- ----
Interest paid (net of capitalized interest) $ 92 $106 $132
Income taxes paid $391 $528 $662
In 1991, an asset sale was funded with receivables of $120 million, which
were subsequently collected in 1992. No other significant non-cash investing
or financing transactions occurred in 1993, 1992 or 1991.
(13) INVESTMENTS IN DEBT AND EQUITY SECURITIES
In May 1993, the Financial Accounting Standards Board issued SFAS No. 115
"Accounting For Certain Investments in Debt and Equity Securities." This
new standard requires companies, no later than 1994, to classify debt and
equity securities into one of three categories: held-to-maturity,
available-for-sale, or trading. Debt which will be held to maturity will be
carried at amortized cost. Certain securities considered available-for-sale
shall be carried at fair value and unrealized holding gains and losses shall
be carried as a net amount in a separate component of stockholders' equity
until realized. Securities classified as trading shall be carried at fair
value and unrealized holding gains and losses shall be included in earnings.
Adoption of this new standard will not materially impact the combined
financial position or the results of operations of the Group.
(14) OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCING ACTIVITIES
The financial statements of Chevron Corporation and Texaco Inc. contain
required supplementary information on oil and gas producing activities,
including disclosures on equity affiliates. Accordingly, such disclosures
are not presented herein.
C-19
CALTEX GROUP OF COMPANIES
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(MILLIONS OF DOLLARS)
OTHER
BALANCE AT ADDI- RETIRE- CHANGES BALANCE
BEGINNING TIONS MENTS ADD AT END
CLASSIFICATION OF PERIOD AT COST OR SALES (DEDUCT) OF PERIOD
- -------------------------------------------------------------------------------
Year ended
December 31, 1993
Producing $2,783 $247 $ 3 $ - $3,027
Refining 1,259 237 6 (7) (1) 1,483
Marketing 2,107 262 108 (9) (2) 2,252
Marine 35 - - - 35
Capitalized leases 113 8 2 - 119
------ ---- ---- ---- ------
Total $6,297 $754 $119 $(16) $6,916
====== ==== ==== ==== ======
Year ended
December 31, 1992
Producing $2,462 $322 $ 1 $ - $2,783
Refining 1,111 166 18 - 1,259
Marketing 1,915 253 46 (15) (3) 2,107
Marine 55 - 20 - 35
Capitalized leases 113 - - - 113
------ ---- ---- ---- ------
Total $5,656 $741 $ 85 $(15) $6,297
====== ==== ==== ==== ======
Year ended
December 31, 1991
Producing $2,179 $284 $ 1 $ - $2,462
Refining 1,008 105 2 - 1,111
Marketing 1,689 243 39 22 (1) 1,915
Marine 54 1 - - 55
Capitalized leases 111 3 1 - 113
------ ---- ---- ---- ------
Total $5,041 $636 $ 43 $ 22 $5,656
====== ==== ==== ==== ======
(1) Reclassification
(2) Currency translation adjustment $(4) and reclassification $(5)
(3) Currency translation adjustment
C-20
CALTEX GROUP OF COMPANIES
SCHEDULE VI - ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(MILLIONS OF DOLLARS)
ADDITIONS OTHER
BALANCE AT CHARGED TO RETIRE- CHANGES BALANCE
BEGINNING COSTS AND MENTS ADD AT END
CLASSIFICATION OF PERIOD EXPENSES OR SALES (DEDUCT) OF PERIOD
- -------------------------------------------------------------------------------
Year ended
December 31, 1993
Producing $1,158 $128 $ 1 $ - $1,285
Refining 646 51 6 (2) (1) 689
Marketing 736 104 32 (2) (2) 806
Marine 7 2 - - 9
Capitalized leases 81 10 2 - 89
------ ---- --- ---- ------
Total $2,628 $295 $41 $(4) $2,878
====== ==== === ==== ======
Year ended
December 31, 1992
Producing $1,051 $106 $(1) $ - $1,158
Refining 614 47 15 - 646
Marketing 672 98 25 (9) (3) 736
Marine 23 2 18 - 7
Capitalized leases 73 10 2 - 81
------ ---- --- ---- ------
Total $2,433 $263 $59 $(9) $2,628
====== ==== === ==== ======
Year ended
December 31, 1991
Producing $ 940 $111 $ - $ - $1,051
Refining 567 49 2 - 614
Marketing 609 85 22 - 672
Marine 21 2 - - 23
Capitalized leases 64 10 1 - 73
------ ---- --- ---- ------
Total $2,201 $257 $25 $ - $2,433
====== ==== === ==== ======
(1) Reclassification
(2) Currency translation adjustment $(1) and reclassification $(1)
(3) Currency translation adjustment
C-21
