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1995
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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, 1995
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OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________________ to __________________
Commission File Number 1-368-2
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CHEVRON CORPORATION
(Exact name of registrant as specified in its charter)
575 Market Street,
Delaware 94-0890210 San Francisco, California 94105
- ---------------- --------------------- ------------------------- -----------
(State or other (I.R.S. Employer (Address of principal (Zip Code)
jurisdiction of Identification Number) executive offices)
incorporation or
organization)
Registrant's telephone number, including area code (415) 894-7700
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225 Bush Street, San Francisco, California 94104
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(Former name or former address, if changed since last report.)
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
Title of Each Class on Which Registered
- ---------------------------------------------- --------------------------------
Common stock par value $1.50 per share New York Stock Exchange, Inc.
Preferred stock purchase rights Chicago Stock Exchange
Pacific 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. [ ]
Aggregate market value of the voting stock held by nonaffiliates
of the Registrant
As of February 29, 1996 - $36,190 million
Number of Shares of Common Stock outstanding
as of February 29, 1996 - 652,640,311
DOCUMENTS INCORPORATED BY REFERENCE
(To The Extent Indicated Herein)
Notice of Annual Meeting and Proxy Statement Dated March 22, 1996 (in Part III)
TABLE OF CONTENTS
Page(s)
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Item Year 1995 March 22, 1996
- ---- 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 ........................... 5 -
(c) Description of Business and Properties ..... 6 -
Capital and Exploratory Expenditures ..... 6 -
Petroleum - Exploration .................. 7 -
Petroleum - Oil and Natural
Gas Production ........................... 11 -
Production Levels ...................... 11 -
Development Activities ................. 12 -
Petroleum - Natural Gas Liquids .......... 16 -
Petroleum - Reserves and
Contract Obligations ..................... 17 -
Petroleum - Refining ..................... 17 -
Petroleum - Refined Products Marketing ... 18 -
Petroleum - Transportation ............... 20 -
Chemicals ................................ 21 -
Coal and Other Minerals .................. 22 -
Research and Environmental Protection .... 23 -
2. Properties ....................................... 25 -
3. Legal Proceedings ................................ 25 -
4. Submission of Matters to
a Vote of Security Holders ....................... 27 -
Executive Officers of the Registrant ............. 27 -
PART II
5. Market for the Registrant's Common Equity
and Related Stockholder Matters .................. 29 -
6. Selected Financial Data .......................... 29 -
7. Management's Discussion and Analysis of
Financial Condition and Results of Operations .... 29 -
8. Financial Statements ............................. 29 -
8. Supplementary Data - Quarterly Results ........... 29 -
- Oil and Gas
Producing Activities ........ 29 -
9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure ........... 29 -
PART III
10. Directors and Executive
Officers of the Registrant ....................... 29 2-4
11. Executive Compensation ........................... 29 10-13
12. Security Ownership of Certain
Beneficial Owners and Management ................. 29 5
13. Certain Relationships and Related Transactions ... 29 -
PART IV
14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K .......................... 30 -
PART I
ITEM 1. BUSINESS
(A) GENERAL DEVELOPMENT OF BUSINESS
SUMMARY DESCRIPTION OF CHEVRON
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Chevron Corporation(1), a Delaware corporation, provides administrative,
financial and management support for, and manages its investments in, U.S. and
foreign subsidiaries and affiliates, which engage in fully integrated petroleum
operations, chemical operations and coal mining in the United States and
approximately 95 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. U.S. integrated petroleum
operations are conducted primarily through three divisions of the company's
wholly owned Chevron U.S.A. Inc. subsidiary. Exploration and production
("upstream") operations in the United States are carried out through Chevron
U.S.A. Production Company. U.S. refining and marketing ("downstream") activities
are performed by Chevron Products Company (formerly Chevron U.S.A. Products
Company). Warren Petroleum Company engages in all phases of the U.S. natural gas
liquids business. In January 1996, the company announced that it had entered
into exclusive negotiations to merge certain operations of Chevron U.S.A.
Production Company and Warren Petroleum Company with those of NGC Corporation.
Additional details of this proposed merger are disclosed on pages 4 and 16 of
this Annual Report on Form 10-K.
A list of the company's major subsidiaries is presented on page E-2 of this
Annual Report on Form 10-K. As of December 31, 1995, Chevron had 43,019
employees, 76 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 and natural gas 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
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Crude oil prices trended upwards throughout most of the first half of 1995 due
to concerns of possible U.S. sanctions against certain oil producing countries,
low crude oil inventories (caused by U.S. refiners' purchases of crude oil in
anticipation of the upcoming driving season) and strong demand in Asia. At
OPEC's June meeting,
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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 -
members agreed to maintain their 24.5 million barrels per day production quota
for the remainder of 1995. However, the cartel also signaled its desire to
regain market-share from non-OPEC producers in 1996, which the market perceived
as a change in OPEC's focus from price support to volume gains. This perception
caused crude prices to weaken until late November when unusually cold weather in
the northern United States increased demand. The company's average crude oil
realizations in the United States for 1995 finished $1.48 per barrel higher than
in the previous year.
Continued concerns of high storage levels coupled with a mild winter in most
parts of the United States resulted in depressed U.S. natural gas prices for the
first half of 1995. Prices began to rebound in late August due to hot summer
weather in some key gas-consuming regions in the United States and fears of
platform damages during 1995's active hurricane season. Gas prices continued to
rise dramatically in November and December as cold weather in the northern
United States increased demand for heating fuel. For the month of December, the
Henry Hub, Louisiana spot price for natural gas, a common benchmark for natural
gas prices, averaged $2.45 per thousand cubic feet (MCF), its highest December
level for Gulf Coast gas in more than 10 years. However, this late surge was
unable to reverse the effects of low gas prices earlier in the year and the
Henry Hub spot price for natural gas averaged $1.69 per MCF in 1995, a decrease
of 17 cents from 1994.
The company's average realization from U.S. crude oil production increased to
$15.34 per barrel in 1995 from $13.86 in 1994 while average liquids realizations
from international liftings, including equity affiliates, increased $1.24 per
barrel to $16.10. Average U.S. natural gas realizations from production
decreased to $1.51 per MCF in 1995 from $1.77 in 1994.
The following table compares the high, low and average Chevron posted prices for
West Texas Intermediate (WTI), an industry benchmark light crude oil, for each
of the quarters during 1995 and for the full years of 1995, 1994, and 1993:
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WEST TEXAS INTERMEDIATE CRUDE OIL
CHEVRON POSTED PRICES
(Dollars per Barrel)
1995
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1st Q 2nd Q 3rd Q 4th Q Year 1994 1993
----- ----- ----- ----- ----- ----- -----
High 18.25 19.50 18.00 18.75 19.50 19.75 20.25
Low 16.50 16.50 16.00 16.00 16.00 13.00 13.00
Average 17.36 18.33 16.76 17.16 17.40 16.18 17.68
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For the first two months of 1996, average natural gas realizations for the
company's U.S. operations were $2.23 per MCF. During this period, the company's
posted price for WTI ranged from $16.50 per barrel to $19.25, with an average of
$17.73. On March 20, 1996 the company's posted price for WTI was $22.00 per
barrel.
Chevron's refining and marketing operations in the United States were hampered
by extensive refinery downtime and weak industry refinery margins in 1995.
Unscheduled downtime and major maintenance turnarounds at the company's three
largest refineries required the company to purchase higher cost refined products
from third parties to supply the company's marketing system. In addition, the
company's Richmond, California, refinery was down for an extended period of time
late in the year for upgrades required to produce cleaner-burning gasoline that
meets California's stringent emission requirements. By June 1, 1996 gasoline
sold at service stations in California must meet this new requirement. The
company's average sales price per barrel of refined product was $26.19 per
barrel in 1995, an increase of $1.82 per barrel over 1994. However, most of this
increase reflected higher crude oil feedstock cost and the added cost of
producing federally mandated reformulated gasoline as industry refining margins
remained weak throughout much of the year due to ample product availability.
- 2 -
The company's chemical operations reported record earnings for the year as
improving worldwide economies continued to spur demand for the company's
commodity chemicals through the first half of 1995. However, industry conditions
softened during the second half of 1995 as the industry began to strike a
balance between supply and demand. The company does not expect that 1996
chemicals results will be as strong as 1995's. Sales and other operating
revenues from the company's chemical operations, including sales to other
Chevron companies, totaled $3.953 billion, an increase of $591 million over the
$3.362 billion recorded in 1994.
CHEVRON STRATEGIC DIRECTION
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Since 1992, the company has developed and implemented certain strategies to
improve its financial performance and to support Chevron's mission to create
superior value for its stockholders, customers and employees. The company
periodically reviews and modifies these "strategic intents" to reflect Chevron's
current operating environment. The eight "strategic intents" for 1996 are:
- - BUILD A COMMITTED TEAM TO ACCOMPLISH THE CORPORATE MISSION. The success of
the other seven strategic intents is strongly linked to the level of
commitment and dedication that Chevron employees bring to their jobs. In
1995, the company issued a new document to each employee. This document, "The
Chevron Way," contains the company's Mission and Vision and other key
statements - Committed Team Values, Total Quality Management, Protecting
People and the Environment and Vision Metrics - that establish a vision and
standard of excellence for each employee. The company has also made efforts
to measure employees' attitudes about the company and diagnose areas of
employee concerns over the past four years by the use of the Worldwide
Employee Survey. As a result, many programs, including leadership training,
upward feedback and the process of filling open jobs, have been developed or
revamped to address those concerns. In addition, the company has put an
increased emphasis on people skills in supervisor positions.
The company is also fostering employee commitment by sharing its success. In
January 1995 the company announced a new program called "Chevron Success
Sharing," that provides eligible employees with a cash bonus if the company
achieves certain financial goals. The total payout opportunity under the
program is 8 percent of the employee's salary. No payout was made in 1995. As
an extra enticement to achieve 1994 through 1998 financial targets, the
company announced that each eligible employee on the payroll as of January
31, 1996 has been awarded 150 special performance stock options. The grant
price was set at $51-7/8 and the options are exercisable, after a six-month
holding period, on the business day after the stock price hits $75 or higher
for three consecutive days or Chevron ranks number one in total shareholder
return versus its five major U.S. competitors for the period 1994 through
1998. If neither criteria is met, the options expire and have no value.
- - FOCUS ON REDUCING COSTS ACROSS ALL ACTIVITIES. Operating expenses, adjusted
for special items, declined about $300 million in 1995 from 1994. Compared to
1991, the base measurement year established when Chevron undertook an
extensive cost-cutting and work force reduction program in early 1992,
operating expenses in 1995 have declined about $1.3 billion. Although a
portion of the cost reduction is related to divested operations, the company
believes the majority is the result of a permanent reduction in the company's
ongoing cost structure.
The company is currently implementing reorganizations that will reduce the
costs of two of its operating companies, Chevron Products Company and Chevron
Chemical Company, and two of its departments, Human Resources and Finance, by
consolidating support functions and regional offices and outsourcing certain
job functions. Chevron also sold its office building in Denver in January
1996 as part of the company's efforts to cut costs and reduce surplus office
space. A corporatewide "breakthrough" initiative aimed at reducing corporate
energy costs has saved approximately $440 million since 1992. An additional
$100 million has been saved since 1994 through a breakthrough initiative
focusing on reducing goods and services costs by working more efficiently
with fewer suppliers. Two other breakthrough initiatives have saved
additional millions by creating a uniform project management process that is
used to evaluate and administer large capital projects and improving
inventory management in order to avoid tying up working capital in excessive
inventories.
- - CONTINUE EXPLORATION AND PRODUCTION GROWTH IN INTERNATIONAL AREAS. The
company continues to believe that its most promising area of financial and
operational growth is in its international upstream activities. As a result,
- 3 -
the company has focused its exploration and production (E&P) efforts outside
the United States. Between 1990 and 1995, total capital and exploratory (C&E)
expenditures for E&P activities grew by 19 percent, however during this same
time period, international expenditures grew by 68 percent while U.S.
expenditures declined by 25 percent. In 1990, international expenditures were
less than half (48 percent) of the total C&E expenditures related to E&P
activities. By 1995 that number had climbed to 68 percent and is estimated at
65 percent in 1996. As a measure of its success in growing its international
upstream business, the company's year end 1995 international net proved
reserves of crude oil, natural gas liquids and natural gas have almost
doubled since 1990, while international production has increased
approximately 36 percent during this same time period.
- - GENERATE CASH FROM NORTH AMERICAN UPSTREAM OPERATIONS WHILE MAINTAINING VALUE
THROUGH SUSTAINED PRODUCTION LEVELS. For 1995, this strategic intent was to
"Generate greater than $800 million a year in cash from U.S. exploration and
production." Net cash flow, after capital and exploratory expenditures, for
U.S. E&P operations of $672 million in 1995 fell short of the goal as higher
crude oil prices were more than offset by lower production volumes, lower
natural gas prices and increased capital spending. The company has several
projects under way, including major development projects in the Gulf of
Mexico, Texas and California that are expected to stabilize the company's
U.S. oil and gas production. Recognizing that opportunities to discover and
develop major new reserves in the United States are limited due to regulatory
barriers and drilling prohibitions in many of the most promising areas of
development, the company nonetheless believes that it should be able to
maintain its U.S. production through the development of attractive growth
opportunities within the company's current portfolio of assets, such as the
acceleration and expansion of deepwater projects in the Gulf of Mexico, and,
if attractive opportunities arise, through acquisitions and trades.
Accordingly, the company has increased its U.S. capital and exploratory
budget in this area and has reduced its cash generation goal for North
American operations.
In January 1996, as part of the company's efforts to enhance the value of its
North American upstream assets, the company announced that it had entered
into exclusive negotiations to merge certain gas gathering, processing, and
marketing operations of Chevron U.S.A. Production Company's Natural Gas
Business Unit and Warren Petroleum Company with those of NGC Corporation. The
company believes the merger will reduce costs through economies of scale and
will position these activities for greater growth.
- - ACHIEVE TOP FINANCIAL PERFORMANCE IN U.S. REFINING AND MARKETING. Over the
past few years, the company has focused its attention on reshaping its
refining portfolio by selling refineries in Port Arthur, Texas and
Philadelphia, Pennsylvania and spending over $1 billion on its two California
refineries in order to produce cleaner-burning fuels and to increase their
efficiency and reliability. In 1995, refinery downtime due to these upgrades,
as well as unscheduled refinery downtime and weak industry margins, caused a
77 percent drop in earnings, excluding special items. With the reshaping of
its refinery portfolio largely completed in 1995, the company expects U.S.
refining and marketing results to improve in 1996 with improved refinery
utilization. The company will be shifting the majority of its 1996 investment
spending to marketing projects aimed at meeting customers' needs and
improving the company's competitive market position.
- - GROW CALTEX IN ATTRACTIVE MARKETS WHILE ACHIEVING SUPERIOR COMPETITIVE
FINANCIAL PERFORMANCE. The company believes that the Asia-Pacific region will
continue to be an area of strong demand growth for petroleum products.
Chevron's 50 percent owned Caltex affiliate, a leading competitor in these
areas, has and is continuing to make significant capital investments to
expand and upgrade its refining capacity and its retail marketing systems. A
large refinery upgrade and expansion project is continuing in Korea, and
first production from a new refinery in Thailand is expected in mid-1996. In
China, Caltex formed a joint venture with a state-owned enterprise to build
the country's largest liquid petroleum gas terminal and blending and storage
facility. Many of Caltex's 4,200 branded service stations will receive a new
retail image over the next five years in order to build a stronger brand
identity.
In 1995, Caltex merged the refining and marketing assets of Caltex Australia
Limited, a 75 percent owned subsidiary, with those of Ampol Limited to form
Australian Petroleum Pty. Limited. The merger is expected to improve
efficiencies, reduce costs and increase market share in Australia. Caltex has
a 37.5 percent equity interest in the new company. In December 1995, Caltex
also announced that it is selling its 50 percent interest
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in Nippon Petroleum Refining Company, Limited in Japan to its partner, Nippon
Oil Company, Limited for $2 billion as part of the company's efforts to
restructure in mature markets and to provide capital for investments in
higher growth areas in the Asia-Pacific region.
- - CONTINUE TO IMPROVE COMPETITIVE FINANCIAL PERFORMANCE IN CHEMICALS WHILE
DEVELOPING ATTRACTIVE OPPORTUNITIES FOR GROWTH. Financial results for the
company's chemical operations continued to improve significantly in 1995 as
the demand for chemicals outpaced supplies in the first half of 1995 before
industry conditions began to soften later in the year. Chevron Chemical
Company reported record operational earnings of $524 million in 1995, more
than doubling 1994 earnings. In 1996 the company will be restructuring its
businesses along geographic lines to facilitate growth of its U.S. and
international operations. The company has expansion plans for its ethylene,
paraxylene and polystyrene facilities in the U.S. and has international
projects planned for Saudi Arabia and Singapore in 1996.
- - BE SELECTIVE IN NON-CORE BUSINESSES. Chevron operates four units that are
outside the corporation's core focus. These four units are Chevron Canada
Limited (CCL) and Gulf Oil Great Britain (GOGB) whose primary operations are
the refining and marketing of petroleum products in Canada and the United
Kingdom, respectively; The Pittsburg & Midway Coal Mining Co. (P&M), operator
of the company's coal interests; and Chevron Land and Development Co. (CL&D),
manager of the company's surplus fee production properties and other real
estate operations in California. These businesses are managed for cash flow
and profitability, and for growth when attractive opportunities exist.
Chevron announced in March 1995 that it was exiting the real estate
development business and was seeking prospective purchasers for its real
estate assets in California. Bids for a significant portion of these real
estate properties were received and evaluated in the third quarter of 1995.
As a result, Chevron entered into exclusive negotiations with potential
buyers for the sale of these properties and a $168 million provision for the
estimated loss from exiting the business was recorded in the third quarter.
It is anticipated that the sale of these properties will be completed in
1996.
(B) INDUSTRY SEGMENT AND GEOGRAPHIC AREA INFORMATION
The company's largest business is its integrated petroleum operations. Other
operations include chemicals and coal mining. The petroleum activities of the
company are widely distributed geographically, with major operations in the
United States, Canada, Australia, United Kingdom, Congo, Angola, Nigeria, Papua
New Guinea, Indonesia, China and Zaire. The company's Caltex affiliate, through
its subsidiaries and affiliates, conducts exploration and production and
geothermal operations in Indonesia and refining and marketing activities in the
Eastern Hemisphere, with major operations in Japan, Korea, Australia, the
Philippines, Singapore, Thailand and South Africa. Tengizchevroil (TCO), a 50/50
joint venture with a subsidiary of the national oil company of the Republic of
Kazakstan, conducts production activities in Kazakstan, a former Soviet
republic.
The company's chemicals operations are concentrated in the United States, but
include operating facilities in France, Japan and Brazil. The company's coal
operations are located 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 10 to the
Consolidated Financial Statements beginning on page FS-20 of this Annual Report
on Form 10-K.
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(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 continues to closely monitor the civil unrest and
political uncertainty in Angola, 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.
The company utilizes various derivative instruments to manage its exposure to
price risk stemming from its integrated petroleum activities. Some of the
instruments may be settled by delivery of the underlying commodity, whereas
others can only be settled in cash. All these instruments are commonly used in
the global trade of petroleum products and, with the exception of certain long-
term natural gas swaps, are of a short-term duration. The proposed merger of
certain natural gas operations of the company with NGC Corporation will result
in NGC assuming most of the natural gas derivative activities.
The company enters into forward exchange contracts as a hedge against some of
its foreign currency exposures. Interest rate swaps are entered into as part of
the company's overall strategy to manage the interest rate risk on its debt. All
commodity and financial derivative instruments used by the company are
relatively straightforward and involve little complexity. Their impact on the
company's results of operations has not been material.
CAPITAL AND EXPLORATORY EXPENDITURES
Chevron's capital and exploratory expenditures during 1995 and 1994 are
summarized in the following table:
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CAPITAL AND EXPLORATORY EXPENDITURES
(Millions of Dollars)
1995 1994
------ ------
Exploration and Production $2,579 $2,586
Refining, Marketing and Transportation 969 1,105
Chemicals 198 135
Coal and Other Minerals 33 44
All Other 109 103
------ ------
Total Consolidated Companies 3,888 3,973
Equity in Affiliates 912 846
------ ------
Total Including Affiliates $4,800 $4,819
====== ======
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Total consolidated expenditures of $3.888 billion in 1995 decreased 2 percent
when compared to 1994. This reduction was the result of a drop in Refining,
Marketing and Transportation expenditures of $136 million due largely to the
completion in 1994 of the company's program to construct new vessels that began
in 1989. This was
- 6 -
partially offset by a $63 million increase in chemical expenditures, primarily
due to the expansion of the linear low-density polyethylene manufacturing plant
at the company's Cedar Bayou, Texas, chemical facility.
Consolidated Exploration and Production (E&P) expenditures were relatively flat
at 66 percent and 65 percent of the company's total consolidated expenditures in
1995 and 1994, respectively. Major international E&P expenditures in 1995
included the acquisition of additional exploration and development interests in
the Republic of Congo and exploration and development activities associated with
the Britannia Field in the U.K. North Sea, the North West Shelf Project in
Australia, the Hibernia Project offshore Newfoundland, various waterflood and
steamflood projects in Indonesia, Areas B and C in Angola and the Escravos Gas
Project in Nigeria. Major U.S. E&P expenditures included development projects in
the Gulf of Mexico, Texas and California. Refining, marketing and transportation
outlays in 1995 included expenditures to upgrade the company's two California
refineries to produce cleaner-burning gasoline that complies with new California
emission regulations scheduled to be effective in mid-1996 and other projects
intended to upgrade and increase efficiencies at the refineries.
The company's share of capital and exploratory expenditures by its affiliates
was $912 million in 1995, an increase of 8 percent from $846 million in 1994.
The company's Caltex affiliate accounted for the vast majority of affiliates'
expenditures, which were primarily comprised of ongoing refinery
expansion/upgrade projects in Korea, Singapore and Japan and the construction of
the new Star Petroleum refinery in Thailand, scheduled for start-up in mid-1996.
The company's 1996 capital and exploratory expenditures, including its share of
equity affiliates' expenditures, is expected to increase 10 percent to $5.3
billion. Both consolidated and affiliated expenditures are forecasted to
increase by 10 percent over 1995 levels to $4.3 billion and $1 billion,
respectively.
Worldwide E&P expenditures in 1996 are expected to total $3 billion, of which
approximately 65 percent will be for international projects. These projects
include the continued development of the Hibernia Field, expansion of the North
West Shelf Project, enhanced recovery projects in Indonesia, development of the
Britannia Field in the North Sea, development of the Boscan Field in Venezuela,
development of the N'Kossa and Kitina projects and delineation work at the Moho
discovery in Congo and other exploration and development projects in West
Africa. In the U.S., major E&P expenditures include various development projects
in the Gulf of Mexico, including the deep water development of Green Canyon 205.
Worldwide refining, marketing and transportation expenditures in 1996 are
estimated at $1.5 billion. After several years of major investments in the
company's refineries to produce gasoline that meets federal, state and local
emission requirements, in 1996 the company expects to significantly reduce its
U.S. refining, marketing and transportation expenditures and concentrate the
majority of these expenditures on marketing projects aimed at meeting consumers'
needs and improving the company's market position. International refining and
marketing expenditures in 1996 include the continuation of refinery construction
and expansion/upgrade projects by the company's Caltex affiliate to meet growing
product demand in the Pacific Rim areas, and a major program to improve retail
marketing operations.
Worldwide chemical expenditures are expected to more than double in 1996 to
approximately $530 million. Forecasted expenditures include the expansion and
modernization of the company's Port Arthur, Texas, ethylene facilities and a
paraxylene expansion at the company's Pascagoula, Mississippi, refinery.
Internationally, the company expects to begin the initial phases for the joint
venture construction of a new aromatics complex using Chevron's Aromax
technology in Saudi Arabia and a fuel and lube oil additives plant in Singapore.
The actual expenditures for 1996 will depend on various conditions affecting the
company's operations, including crude oil and natural gas prices, and may differ
significantly from the company's forecast.
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, 1995. "Exploratory wells" include
delineation wells, which are wells drilled to find a new reservoir in a field
previously found to be productive
- 7 -
of oil or gas in another reservoir or to extend a known reservoir beyond the
proved area. "Wells drilling" include wells temporarily suspended.
- --------------------------------------------------------------------------------
EXPLORATORY WELL ACTIVITY
NET WELLS COMPLETED(1)
WELLS DRILLING -----------------------------------
At 12/31/95 1995 1994 1993
--------------- ----------- ----------- -----------
Gross(2) Net(2) Prod. Dry Prod. Dry Prod. Dry
------- ------ ----- ----- ----- ----- ----- -----
United States 60 52 101 24 53 17 32 14
------- ------ ----- ----- ----- ----- ----- -----
Africa 13 5 3 4 5 2 3 4
Other International 8 5 22 27 55 42 27 35
------- ------ ----- ----- ----- ----- ----- -----
Total International 21 10 25 31 60 44 30 39
------- ------ ----- ----- ----- ----- ----- -----
Total Consolidated Companies 81 62 126 55 113 61 62 53
Equity in Affiliates 8 4 1 - - 1 1 1
------- ------ ----- ----- ----- ----- ----- -----
Total Including Affiliates 89 66 127 55 113 62 63 54
======= ====== ===== ===== ===== ===== ===== =====
(1)Indicates the number of wells completed during the year regardless of when
drilling was initiated. Completion refers to the installation of permanent
equipment for the production of oil or gas or, in the case of a dry well, the
reporting of abandonment to the appropriate agency.
(2)Gross wells include the total number of wells in which the company has an
interest. Net wells are the sum of the company's fractional interests in
gross wells.
- --------------------------------------------------------------------------------
At December 31, 1995, the company owned or had under lease or similar agreements
undeveloped and developed oil and gas properties located throughout the world.
Undeveloped acreage includes undeveloped proved acreage. The geographical
distribution of the company's acreage is shown in the next table.
- --------------------------------------------------------------------------------
ACREAGE* AT DECEMBER 31, 1995
(Thousands of Acres)
Developed
Undeveloped Developed and developed
--------------- --------------- ---------------
Gross Net Gross Net Gross Net
------- ------- ------- ------- ------- -------
United States 3,358 2,157 6,013 2,547 9,371 4,704
------- ------ ------- ------- ------- -------
Canada 18,623 10,669 572 360 19,195 11,029
Africa 25,250 17,892 144 56 25,394 17,948
Asia 42,384 21,939 49 19 42,433 21,958
Europe 2,928 1,405 115 29 3,043 1,434
Other International 11,945 4,327 54 15 11,999 4,342
------- ------- ------- ------- ------- -------
Total International 101,130 56,232 934 479 102,064 56,711
------- ------- ------- ------- ------- -------
Total Consolidated Companies 104,488 58,389 6,947 3,026 111,435 61,415
Equity in Affiliates 3,205 1,603 229 114 3,434 1,717
------- ------- ------- ------- ------- -------
Total Including Affiliates 107,693 59,992 7,176 3,140 114,869 63,132
======= ======= ======= ======= ======= =======
*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.
- --------------------------------------------------------------------------------
- 8 -
The company had $250 million of suspended exploratory wells included in
properties, plant and equipment at year-end 1995. The wells are suspended
pending a final determination of the commercial potential of the related oil and
gas fields. The ultimate disposition of these well costs is dependent on the
results of future drilling activity and development decisions.
During 1995, the company explored for oil and gas in the United States and about
24 other countries. The company's 1995 exploratory expenditures, including
affiliated companies' expenditures but excluding unproved property acquisitions,
were $667 million compared with $526 million in 1994. U.S. expenditures
represented approximately 47 percent of the consolidated companies' worldwide
exploration expenditures, a 7 percent increase from the prior year. Significant
activities in Chevron's exploration program during 1995 include the following
(number of wells are on a "gross" basis):
UNITED STATES: Exploratory expenditures, excluding unproved property
acquisitions, were $312 million in 1995, compared to $209 million spent in 1994.
In addition, the company incurred costs of $31 million for unproved property
acquisitions in 1995. Exploration efforts in 1995 were concentrated in the Gulf
of Mexico and several onshore basins in Texas, California, Alaska and the Rocky
Mountains. Chevron participated in 17 exploratory wells that were completed in
1995, resulting in three discoveries in the Gulf of Mexico.
In 1995, Chevron received $65 million from the Department of Interior as
settlement for costs incurred by the company for federal offshore leases in
Florida and Alaska that remain undrilled due to state, federal, and private
objections to drilling. The company continues to pursue its claims with the U.S.
government over offshore leases in North Carolina.
AFRICA: In Africa, the company spent $103 million during 1995 on exploratory
efforts, excluding the acquisition of unproved properties, compared with $81
million in 1994. The company also acquired $8 million of unproved properties in
1995.
In Nigeria, the company's operations are managed by three subsidiaries. Chevron
Nigeria Limited (CNL) operates and holds a 40 percent interest in concessions
totaling approximately 3,450 square miles in the onshore and offshore regions of
the Niger Delta. Chevron Oil Company Nigeria Limited (COCNL) holds a 20 percent
interest in six concessions covering about 940 square miles with six offshore
oil fields operated by a partner. Chevron Petroleum Nigeria Limited (CPNL) has a
30 percent interest in two deepwater Niger Delta blocks and three inland Benue
Basin blocks and an additional sole interest in six other Benue Basin blocks.
CNL drilled 10 exploratory and appraisal wells in 1995, resulting in three new
oil field discoveries, including two significant oil discoveries in the Gbodoka
and Dibi fields in the Benin River area. Other exploration activities in 1995
included the acquisition and interpretation of 2-D and 3-D seismic data.
In Angola, the company is the operator of a 2,700 square mile concession off the
coast of Angola's Cabinda exclave. The concession is divided into three areas:
Area A, which commenced production in late 1960, includes two major areas,
Malongo and Takula; Area B, which started production in late 1994, includes the
Kokongo, Nemba and Lomba fields; and Area C, which is expected to start
production in early 1997, includes the N'Dola and Sanha fields. Chevron has a 39
percent interest in the concession. "Deepwater" Block 14, located due west of
Areas B and C, was awarded to Chevron (31 percent interest) and its partners in
February 1995. Significant exploration activities in 1995 included the
acquisition of a 3-D seismic survey covering approximately 1,330 square miles
over prospective parts of Areas A, B, and C as well as Block 14 concessions. Two
exploratory wells were drilled in Area A in 1995, resulting in an oil discovery.
Negotiations were completed to renew the Exploration Extensions in Areas B and C
through February 2000. As a part of this agreement, the drilling of two
exploratory wells is planned for late 1997 and early 1998. Interpretation of the
seismic survey for Block 14 is continuing and the drilling of an exploratory
well is planned for mid-1996.
Offshore Congo, the company has a 29.25 percent interest in the Agip operated
Marine VII license, which includes the Kitina Field and a 30 percent interest in
the Haute Mer license, which is operated by Elf Congo and includes the N'Kossa
Field. In late 1995, the Moho Marine-1 well, located 9 miles west of N'Kossa,
tested oil at a rate of over 5,700 barrels per day. An appraisal well to further
evaluate the results is planned for mid-1996. Chevron reached an agreement with
the Congolese government in December 1995 to participate in the Marine IV
license, located
- 9 -
offshore northern Congo, as operator with an 85 percent interest. If final
approval is granted, Chevron will conduct seismic studies in 1996.
In Zaire, the company has a 50 percent interest in, and is the operator of, a
390 square mile offshore concession. Approximately 90 square miles of 3-D
seismic data were acquired in the western part of the offshore Zaire concession
in 1995. Exploration drilling activity in 1995 consisted of one exploratory
well, which resulted in a dry hole that was plugged and abandoned. The drilling
of three exploratory wells is planned for 1996.
OTHER INTERNATIONAL INCLUDING AFFILIATED COMPANIES: Exploration expenditures,
excluding unproved property acquisitions, were $252 million in 1995, an increase
of $16 million from the 1994 amount of $236 million. In addition, unproved
properties of $12 million were acquired in 1995.
In Europe, Chevron participated in drilling six wells offshore the U.K. and
Ireland in 1995. In addition, during the U.K.'s 16th licensing round, the
company was awarded two blocks in the Tertiary trend west of Shetlands, three
blocks in Cardigan Bay, offshore Wales and a block adjacent to Chevron's Bressay
heavy oil discovery in the North Sea. Six blocks offshore Ireland were also
awarded to Chevron in 1995 in the Porcupine Basin Frontier Licensing Round.
In Canada, exploration efforts in 1995 continued to be concentrated in the
western part of the country near existing infrastructures that would allow any
reserves to be brought on production quickly. A total of 22 exploratory wells
were drilled in 1995, resulting in two oil, three gas and two oil and gas
discoveries.
In Indonesia, Chevron's interests in 12 contract areas are managed by its 50
percent owned P.T. Caltex Pacific Indonesia (CPI) and Amoseas Indonesia (AI)
affiliates. Four of five exploratory wells drilled by CPI in 1995 resulted in
discoveries that are currently being evaluated for their reserve potential. One
of these discoveries, Besar, was tied into existing infrastructure and placed
into production in November 1995. CPI continues its exploration efforts off the
west coast of Sumatra in search of natural gas for use in its enhanced oil
recovery efforts and will be acquiring 2-D and 3-D seismic data to support that
evaluation. In 1995, the company negotiated a 100 percent interest in a new
production sharing contract in the Lariang block, covering 1,540 square miles,
in west-central Sulawesi that will be operated by AI on behalf of Chevron. CPI
has begun negotiations for a 20 year extension of the Coastal Plains block in
Central Sumatra, currently set to expire in 2001.
In Australia, Chevron's primary interests are in two non-operated joint
ventures, with a 16.7 percent interest in the North West Shelf (NWS) Project and
a 25.7 to 50 percent interest in permits within the West Australian Petroleum
Pty. Ltd. (WAPET) joint venture. In addition, Chevron recently acquired a 25
percent interest in two Browse Basin permits and a 17.3 percent interest in one
Carnarvon Basin permit. NWS exploration activities in 1995 included the drilling
of the Perseus-1 well between the North Rankin and Goodwyn fields, which
resulted in a major gas discovery and the Sculptor-1 well, which added gas and
condensate reserves to the Echo/Yodel fields. Interpretation of the East Dampier
3-D seismic survey continued in 1995 and exploration drilling in several
prospects is planned for mid-1996. WAPET's Chrysaor-1 well was confirmed as a
significant gas discovery after tests were performed in early 1995. A 3-D
seismic survey was also shot over the Chrysaor structure in 1995.
In Papua New Guinea, Chevron and its partners drilled three exploratory wells in
the PPL-161 license. One well near the Kutubu facilities recovered oil. Further
evaluation of this well will continue into early 1996.
In China, Chevron was awarded sole interest in a production-sharing contract in
Block 62/23 and a geophysical agreement in Block 50/20, both south of Hainan
Island in the South China Sea. Seismic data was acquired for both blocks and one
well is planned for 1996. Exploration drilling in East China Sea Block 33/08
resulted in two dry holes and no further activity is planned. The company also
submitted bids for acreage in Liaodong Bay, offshore northeast China, and South
China Sea Block 63/15 in 1995.
Other areas where exploration activities occurred in 1995 include Bolivia where
the company acquired seismic data over some prospects in the southern half of
the Caipipendi Exploration Block, Colombia where evaluation of the Rio Blanco
Exploration Block continued in 1995 with the drilling of an exploratory well,
and Peru where the
- 10 -
company obtained a 100 percent interest in exploration block 52, which is
adjacent to the Camisea gas-condensate field.
PETROLEUM - OIL AND NATURAL GAS PRODUCTION
The following table summarizes the company's and its affiliates' 1995 net
production of crude oil, natural gas liquids and natural gas.
- -------------------------------------------------------------------------------
1995 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 119,870 125,410
-Gulf of Mexico 112,480 923,750
-Texas 65,670 411,520
-Colorado 13,470 -
-Wyoming 9,260 145,300
-New Mexico 8,240 101,990
-Louisiana 4,590 50,030
-Other States 15,800 109,950
--------- ---------
Total United States 349,380 1,867,950
--------- ---------
Africa 261,220 -
United Kingdom (North Sea) 71,160 28,210
Canada 48,290 242,560
Australia 25,100 208,430
Papua New Guinea 23,620 -
Indonesia 22,620 590
China 9,040 -
Other International 10,290 3,460
--------- ---------
Total International 471,340 483,250
--------- ---------
Total Consolidated Companies 820,720 2,351,200
Equity in Affiliates 179,990 81,600
--------- ---------
Total Including Affiliates 1,000,710 2,432,800
========= =========
* Net production excludes royalty interest owned by others.
- -------------------------------------------------------------------------------
PRODUCTION LEVELS:
In 1995, net crude oil and natural gas liquids production, including affiliates,
increased for the third year in a row, rising from 992,510 barrels per day in
1994 to 1,000,710 barrels per day in 1995. The increase was due to higher
production in Africa, primarily in Angola where the Kokongo Field began
producing in late 1994 and Australia, where the Goodwyn development began
production in early 1995. These production increases were partially offset by
production declines in the United States due primarily to normal field declines.
Net production of natural gas, including affiliates, decreased 8 percent from
2,630,570 thousand cubic feet per day in 1994 to 2,432,800 thousand cubic feet
per day in 1995. The decline was due to lower U.S. production, primarily
- 11 -
in the Gulf of Mexico due to normal field declines, partially offset by higher
production in Australia and in the company's affiliates' operations in Kazakstan
and Indonesia. The company has several projects under way, including major long-
term development projects in the Gulf of Mexico, which are expected to stabilize
its U.S. oil and gas production.
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 1995, 1994 and 1993 are
reported in Table III on pages FS-31 and FS-32 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 1995.
---------------------------------------------------------------------
PRODUCTIVE OIL AND GAS WELLS AT DECEMBER 31, 1995
Productive(1) Productive(1)
Oil Wells Gas Wells
----------------- ------------------
Gross(2) Net(2) Gross(2) Net(2)
-------- -------- -------- --------
United States 25,673 12,690 4,173 1,763
-------- -------- -------- --------
Canada 1,443 892 379 171
Africa 931 355 13 2
United Kingdom (North Sea) 211 35 - -
Other International 1,052 384 56 15
-------- -------- -------- --------
Total International 3,637 1,666 448 188
Total Consolidated Companies 29,310 14,356 4,621 1,951
Equity in Affiliates 4,706 2,353 31 15
-------- -------- -------- --------
Total Including Affiliates 34,016 16,709 4,652 1,966
======== ======== ======== ========
Multiple completion
wells included above: 469 227 21 11
(1)Includes wells producing or capable of producing and injection
wells temporarily functioning as producing wells. Wells that
produce both oil and gas are classified as oil wells.
(2)Gross wells include the total number of wells in which the company
has an interest. Net wells are the sum of the company's fractional
interests in gross wells.
---------------------------------------------------------------------
DEVELOPMENT ACTIVITIES:
The company's development expenditures, including affiliated companies but
excluding proved property acquisitions, were $1,765 million in 1995 and $1,508
million in 1994.
The table below summarizes the company's net interest in productive and dry
development wells completed in each of the past three years and the status of
the company's development wells drilling at December 31, 1995. (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.)
- 12 -
- --------------------------------------------------------------------------------
DEVELOPMENT WELL ACTIVITY
NET WELLS COMPLETED(1)
WELLS DRILLING -----------------------------------
At 12/31/95 1995 1994 1993
--------------- ----------- ----------- -----------
Gross(2) Net(2) Prod. Dry Prod. Dry Prod. Dry
------- ------ ----- ----- ----- ----- ----- -----
United States 133 123 281 6 194 5 293 11
------- ------ ----- ----- ----- ----- ----- -----
Africa 25 9 20 1 9 - 10 -
Other International 43 8 28 2 48 4 57 12
------- ------ ----- ----- ----- ----- ----- -----
Total International 68 17 48 3 57 4 67 12
------- ------ ----- ----- ----- ----- ----- -----
Total Consolidated Companies 201 140 329 9 251 9 360 23
Equity in Affiliates 38 19 135 - 98 - 93 -
------- ------ ----- ----- ----- ----- ----- -----
Total Including Affiliates 239 159 464 9 349 9 453 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.
- --------------------------------------------------------------------------------
Significant 1995 development activities include the following:
UNITED STATES: Chevron's U.S. development expenditures were $453 million in
1995, an increase of $37 million from the 1994 figure of $416 million.
Expenditures for proved reserve acquisitions amounted to $21 million in 1995
compared to $95 million in 1994, which included the company's acquisition of
certain gas properties in West Texas from Wes-Tex Drilling Company. Additions to
proved reserves during 1995 from extensions, discoveries and improved recovery,
before revisions, were 94 million barrels of crude oil and natural gas liquids
and 616 billion cubic feet of natural gas.
In the Gulf of Mexico, significant development activities in 1995 included the
evaluation of alternative development concepts for the Green Canyon 205 Field
located in 2,600 feet of water. The project execution plan calls for initial
production in 1998, with peak production expected to reach 55,000 barrels per
day and 72 million cubic feet of gas per day. Eleven wells drilled in the Eugene
Island 238 Field were successful, resulting in seven gas and four oil
discoveries. Three wells in the South Marsh Island 66 Field were drilled in
1995, with all three resulting in either a gas or oil discovery. In the Norphlet
trend, which stretches some 80 miles from the Destin Dome area (offshore
Florida) to the Mobile Block 861 area (offshore Mississippi), production from
three wells in the Mobile Block 916 Area offshore Alabama commenced in April
1995. Chevron's percentage interests in these fields vary from 33 to 100 percent
Offshore California, Chevron owns approximately 25 percent of the Point Arguello
project and operates two offshore platforms (Hermosa and Hidalgo), the onshore
Gaviota oil and gas plant and the interconnecting pipelines. Production from the
project averaged 59,000 barrels of oil per day in 1995, down from 78,000 in
1994. In addition, the percentage of water produced approximately doubled
between periods. Chevron's share of proved oil and gas reserves declined by 31
percent in 1995 due to production and reserve revisions, partially offset by
reserve additions resulting from two redrills on the Hermosa platform. The
company and its partners are currently reviewing options to address these
issues. About two-thirds of current production is delivered via pipeline to
various California locations. However, due to a shortage of adequate
transportation facilities to Los Angeles, the balance of production is shipped
via pipeline to markets in Texas, resulting in increased transportation costs.
Partners in the Pacific Pipeline Project, in which Chevron has a minority
interest, continue to work on the development of a 130-mile pipeline that would
carry Point Arguello oil production to Los Angeles refineries.
- 13 -
Other development projects in the U.S. included the employment of enhanced
recovery methods using steam and water to increase both the production rate and
the amount of oil ultimately recoverable from fields in California's San Joaquin
Valley, the drilling of 56 new wells in the Laredo and Terrell County areas of
Texas, which increased proved gas reserves by a combined 114 billion cubic feet,
and the signing of an agreement with the Osage Tribe and Davis Brothers Oil
Producers to begin 3-D seismic evaluation of more than 400,000 acres of tribal
land in Osage County, Oklahoma.
AFRICA: Developmental expenditures in Africa were $640 million in 1995, compared
to $276 million in 1994. The increase was primarily due to higher expenditures
in Congo, Nigeria and Angola, with Congo expenditures accounting for
approximately 55 percent of the increase. Expenditures for proved reserve
acquisitions amounted to $56 million in 1995. Additions to proved reserves from
extensions, discoveries and improved recovery, before revisions, were 173
million barrels of crude oil and natural gas liquids and 22 billion cubic feet
of natural gas.
In Nigeria, total production from 29 CNL-operated fields averaged 384,000
barrels of oil per day, an increase of about 15,000 barrels per day from 1994.
This increase was primarily due to the addition of three fields, Mejo, Ojumole
and Omuro, that were put into production in 1995. Production from non-operated
fields averaged approximately 54,000 barrels of oil per day in 1995. On-site
construction for the Escravos Gas Project began in May 1995. Fabrication of the
floating storage and offloading vessel, the offshore compression platform, and
the onshore LPG extraction plant will continue in 1996. The project is expected
to start-up in mid-1997 and will utilize gas currently being flared from the
Okan and Mefa fields.
In Angola, fifteen development wells were drilled in Area A fields during 1995.
Five were in the Malongo Area and ten were in the Takula Area. The company
expects that the combination of exploratory discoveries, infill drilling,
workovers and facility modernization should maintain production from Area A in
the near future. Areas B and C continue to be the primary focus of major
development activities, which included work on an early production system in the
Nemba Field that commenced production in January 1996.
In Congo, seven development wells have been drilled in the Kitina Field to date,
with further development drilling to continue in 1996. A platform, tied via
pipeline to processing and export facilities at the onshore Djeno terminal, is
planned for late 1997, with first oil in early 1998. Appraisal drilling at the
Kitina South structure in 1995 confirmed the existence of a separate oil pool.
At the N'Kossa Field, 14 wells have been drilled to date and two platforms were
installed that will allow a second phase of development drilling to continue
through 1996. First oil is planned for mid-1996 and the field is expected to
reach peak production of 110,000 barrels per day in late 1997.
In Zaire, four development wells, two water injection wells and one workover
were completed in 1995. In 1996, the Tshiala Field development will continue
with four wells planned. To date, 78 exploratory and development wells have been
drilled and forty-one are currently on stream. Crude oil production from eight
offshore fields averaged 19,600 barrels per day in 1995.
OTHER INTERNATIONAL INCLUDING AFFILIATED COMPANIES: Development expenditures in
1995 were $672 million compared to $816 million in 1994. The decrease was
largely due to lower expenditures by the company's Tengizchevroil affiliate.
Additions to proved reserves from extensions, discoveries and improved
recoveries were 122 million barrels of crude oil and natural gas liquids and 204
billion cubic feet of natural gas.
In Europe, the company has interests in over 60 blocks in the U.K. and Ireland,
which total approximately 2.4 million gross acres, including six producing
fields in the North Sea where the company's interest varies from 4.8 to 33.3
percent. The company also has interests to the west of Shetlands, offshore Wales
and in Liverpool Bay. Offshore Ireland, Chevron has acreage in the Celtic Sea
and the Porcupine Basin. The company's share of production from these fields
averaged 71,000 barrels of crude oil and natural gas liquids and 28 million
cubic feet of gas per day in 1995. Production from Phase I of the North Sea's
Alba Field, in which Chevron has a 33.2 percent interest, averaged 69,100
barrels of oil per day in 1995. Modifications to four of the platform's well
slots, allowing the well slots to house two rather than one well, has eliminated
the need for a stand alone second platform during Phase II of the project to
develop the southern area of the reservoir. Phase II development commenced in
November 1995 when the first of eighteen development wells was spudded from the
Alba Northern platform into the southern area of the reservoir. Detailed design
engineering was started on a $46 million oil capacity upgrade, from 75,000 to
- 14 -
over 100,000 barrels per day, for the Alba Northern platform, in anticipation of
added production from Phase II. The Britannia gas field development in the North
Sea, which lies underneath the Alba Field 130 miles northeast of Aberdeen,
proceeded with the drilling of nine pre-development wells and the start of
fabrication of the steel jacket and topsides. Peak production is expected to be
approximately 740 million cubic feet of gas and 70,000 barrels of condensate per
day with initial production expected to commence in late 1998.
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. The
company drilled 26 wells that were targeted at new reserves around existing
infrastructures along with 87 development wells in existing fields. The Hibernia
Development project, in which Chevron has a 26.9 percent interest, proceeded on
schedule in 1995. The five main topsides have been interconnected. Plans for
mating the topsides to the Gravity Base Structure on which they will sit and the
towout from its fabrication site at Bull Arm, Newfoundland to the Hibernia
Field, 200 miles offshore Newfoundland, in mid-1997 are under way. Oil
production is expected to begin in late 1997 or early 1998. The company's
capitalized investment in this project was $806 million at year-end 1995. The
company streamlined its Canadian oil and gas subsidiary, Chevron Canada
Resources, by reducing its business unit structure from eight to five and
reducing its workforce by 20%, or 200 employees.
In Indonesia, the Duri Steamflood Project, begun in 1985 to assist the difficult
production process for the relatively heavy, waxy Duri crude, is being completed
in 13 stages (Areas 1-13) with seven areas currently on production. The field
has two billion barrels of recoverable oil, with total production averaging over
300,000 barrels per day in 1995. A waterflood project involving 21 fields in
Central Sumatra continued in 1995 as water injection at the Minas Field moved
into phase three of a four phase pattern waterflood project that started in
December 1993. Expansion of the waterflood efforts in 1995 included the start-up
of a new project in the Beruk Field and government approval for a similar
project in the Bekasap Field. Delivery of steam from the Darajat I plant in the
Darajat geothermal field, located 115 miles southeast of Jakarta, continued at a
steady pace in 1995. Government approval for the Darajat II plant, for which AI
has acquired an Indonesian partner, was received in January 1996. The 70
megawatt plant is expected to be operational in late 1998.
In Kazakstan, Tengizchevroil increased its production capacity to 95,000 barrels
a day at the end of 1994 with the completion of a second processing plant.
However, during most of 1995 production was constrained by the lack of
sufficient export capability and averaged only 58,000 barrels per day in 1995,
up from 46,000 barrels per day in 1994. The pace of further field development is
dependent on the availability of additional export capacity or the securing of
other marketing alternatives. The partners remain committed to realizing the
full potential of the project and continue to explore alternatives and
opportunities for the export of Tengiz crude oil.
In Australia, production from the Goodwyn Field, which is being developed as
part of the North West Shelf (NWS) Project, came on stream in February 1995 and
reached 70,000 barrels per day of condensate and 400 million cubic feet of gas
per day by year end. Development drilling will continue in 1996. The
Wanaea/Cossack development also came on stream in November 1995 and reached peak
production of 115,000 barrels of oil per day shortly thereafter. WAPET
development activities included the start of a 20 well infill drilling program
on Barrow Island in November 1995 and evaluation of alternatives for the
development of the Gorgon Field's gas reserves as either a stand-alone project
or as a co-operative expansion of the existing NWS liquefied natural gas (LNG)
project.
In Papua New Guinea, Chevron (19 percent interest) and its partners completed
engineering work on the Gobe fields in the southeastern portion of the PPL-161
license in anticipation of the submission of a Petroleum Development License
application to the Papua New Guinea government in early 1996. Evaluations for
the development of gas discoveries in the PPL-101 license (P'nyang and Juha gas
fields) and the PDL-2 license (Hedinia field gas cap) are continuing. An active
development drilling program designed to accelerate production and develop new
reserves for the Kutubu Area fields continued in 1995 and has allowed production
from these fields to remain at a rate in excess of 100,000 barrels of oil per
day throughout the year.
In China, work to develop the HZ/32-2 and HZ/32-3 fields concluded in June 1995,
bringing the total number of producing fields in the 16/08 contract area of the
Pearl River Mouth Basin in the South China Sea to four. Total output at year end
1995 from these four fields was 120,000 barrels of oil per day with Chevron's
share at 16.33 percent. The first stage of an enhanced oil recovery pilot
project using Chevron's Microbial Profile Modification
- 15 -
technology was completed at Daqing, China's largest oil field, with the
completion of the pilot area wells. The next stage, involving microbe injection
in these wells, will occur in 1996.
In Venezuela, Chevron and Maraven S.A. formed an alliance in late 1995 to
further develop the Boscan oil field. In mid-1996, Chevron will become
responsible for the operations and production of this field under a fee
arrangement, whereby Chevron will be compensated on the basis of barrels
produced. Boscan production is currently about 80,000 barrels per day. In
addition, the alliance calls for the supply of Venezuelan crude oil to Chevron
refineries in the U.S. and a Chevron/Maraven partnership that will market
asphalt and other related products in the western U.S.
PETROLEUM - NATURAL GAS LIQUIDS
Chevron's wholly owned Warren Petroleum Company is engaged in all phases of the
U.S. natural gas liquids (NGL's) business and is the largest U.S. wholesale
marketer of NGL's, selling to customers in 46 states.
Warren's business encompasses: 1) extraction, which includes 15 processing
plants with a total processing capacity of 3.3 billion cubic feet of gas per day
and equity interests in an additional 14 plants, 2) fractionation, which
includes a 220,000 barrel per day capacity fractionation plant at Mont Belvieu,
Texas and 3) distribution, which includes the Warrengas Terminal, located on the
Houston Ship Channel and linked to the Mont Belvieu complex by dedicated
pipelines. Warren also conducts Chevron's international liquefied petroleum gas
(LPG) trading and sales activities. Sales in 1995 totaled 283,000 barrels per
day (including sales of 80,000 barrels per day to other Chevron companies).
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)
1995 1994 1993
---- ---- ----
United States - Warren 203 209 208
United States - Other 10 6 3
---- ---- ----
Total United States 213 215 211
Canada 40 27 30
Other International 7 7 7
---- ---- ----
Total Consolidated Companies 260 249 248
==== ==== ====
-----------------------------------------------------
In January 1996, Chevron announced that it had entered into exclusive
negotiations with NGC Corporation to combine certain gas gathering, processing
and marketing operations of Chevron U.S.A. Production Company's Natural Gas
Business Unit and Warren Petroleum Company with the operations of NGC
Corporation. The transaction, expected to be finalized in the second quarter of
1996, will result in a Houston-based company that will operate under the name of
NGC Corporation with a natural gas sales division operating under the name of
Natural Gas Clearinghouse and an NGL division operating under the name of Warren
Petroleum Company. Chevron will have, through common and preferred stock
holdings, an approximate 28 percent equity interest in the resulting company,
which is expected to be the largest natural gas marketer in North America as
well as the largest processor and marketer of natural gas liquids in North
America. Warren's Venice, Louisiana processing complex is not part of the
proposed merger, but may be involved in a joint venture between the merged
company and Chevron. A possible second joint venture could involve Chevron's
Canadian natural gas and NGL operations.
- 16 -
PETROLEUM - RESERVES AND CONTRACT OBLIGATIONS
Table IV on pages FS-32 and FS-33 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, 1995, 1994, and 1993. During 1995, the company filed estimates of
oil and gas reserves with the Department of Energy, Energy Information Agency.
Those estimates were consistent with the reserve data reported on page FS-33 of
this Annual Report on Form 10-K.
The company sells gas from its producing operations under a variety of
contractual arrangements. Most contracts generally commit the company to sell
quantities based on production from specified properties but certain gas sales
contracts specify delivery of fixed and determinable quantities. In the United
States, the 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 is committed to deliver
approximately 279 billion cubic feet of natural gas through 2013 in Australia
and approximately 30 billion cubic feet of natural gas through 1998 in Canada.
The company believes it can satisfy these contracts from quantities available
from production of the company's proved developed Australian and Canadian
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, 1995
----------------- Refinery Inputs
Operable ---------------------
Locations Number Capacity 1995 1994 1993
- ------------------------------------- ------ -------- ----- ----- ----
Pascagoula, Mississippi 1 295 282 324 283
El Segundo, California 1 258 221 227 233
Richmond, California 1 230 202 220 228
Port Arthur, Texas(1) - - 26 158 177
Philadelphia, Pennsylvania(1) - - - 94 184
Other(2) 6 261 194 190 202
------ -------- ----- ----- -----
Total United States 9 1,044 925 1,213 1,307
------ -------- ----- ----- -----
Burnaby, B.C., Canada 1 50 47 47 43
Milford Haven, Wales United Kingdom 1 115 100 116 120
------ -------- ----- ----- -----
Total International 2 165 147 163 163
------ -------- ----- ----- -----
Total Consolidated Companies 11 1,209 1,072 1,376 1,470
Equity in Affiliate Various
Locations 15 514 451 460 435
------ -------- ----- ----- -----
Total Including Affiliate 26 1,723 1,523 1,836 1,905
====== ======== ===== ===== =====
(1)The company sold the Philadelphia, Pennsylvania refinery in August 1994 and
the Port Arthur, Texas refinery in February 1995.
(2)Refineries in El Paso, Texas; Honolulu, Hawaii; Salt Lake City, Utah; Perth
Amboy, New Jersey; Portland, Oregon; and Richmond Beach, Washington. Capacity
and input amounts for El Paso represent Chevron's share.
- --------------------------------------------------------------------------------
Based on refinery statistics published in the December 18, 1995 issue of The Oil
and Gas Journal, Chevron had the largest U.S. refining capacity and ranked among
the top ten in worldwide refining capacity including its share of affiliate's
refining capacity. The company wholly owned and operated nine refineries in the
United States and one
- 17 -
each in Canada and the United Kingdom. At year-end 1995, the company's Caltex
Petroleum Corporation affiliate owned or had interests in 15 operating
refineries in Japan (4), Australia (2), Korea, the Philippines, New Zealand,
Bahrain, Singapore, Pakistan, Thailand, Kenya and South Africa. In 1995, Caltex
merged its Australian refining and marketing assets with those of Ampol Limited,
acquiring a 37.5 percent equity interest in a refinery in Brisbane, Australia
and reducing its interest in a Sydney, Australia refinery from 75 percent to
37.5 percent. In December 1995 Caltex announced that it is selling its 50
percent interest in Nippon Petroleum Refining Company, Limited, which includes
two refineries in Japan, to its partner, Nippon Oil Company, Limited. The
company's share of refining capacity for these two refineries totaled 255
thousand barrels per day at year end 1995.
Distillation operating capacity utilization in 1995 averaged 82 percent in the
United States and 85 percent worldwide (including affiliate), compared with 93
percent in the United States and 94 percent worldwide in 1994. Chevron's
capacity utilization of its U.S. cracking and coking facilities, which are the
primary facilities used to convert heavier products to gasoline and other light
products, averaged 79 percent in 1995, down from 90 percent in 1994. The company
imports crude oil for its U.S. refining operations. Imported crude oil accounted
for almost half of U.S. refinery inputs in 1995.
In 1995, the company concluded work on various expansion/upgrade projects at its
Richmond and El Segundo, California, refineries. Over the past few years,
approximately $700 million was spent at each refinery on projects aimed at
meeting regional clean air requirements and to produce cleaner-burning motor
gasoline and diesel fuel as required by the California Air Resources Board and
the Federal Clean Air Act Amendments of 1990. These projects also included the
upgrading of key processing units to improve yields of high value light
products, and to improve their reliability and cost efficiency.
At the Milford Haven, Wales refinery, a $27 million upgrade project to comply
with legislation on gasoil sulfur is scheduled to be completed by the end of May
1996, with the objective of supplying low sulfur diesel fuel by August.
Caltex and its partner completed construction of a 130,000 barrels-per-day
grassroots refinery in Map Ta Phut in March 1996, with full production
commencing in mid-1996. At the Yocheon refinery in South Korea, construction of
a new crude unit and hydrotreater that will increase production of gasoline and
low-sulfur diesel fuel is continuing. The anticipated start-up date of these new
units is late 1996. At the Singapore export refinery, a major expansion/upgrade
project was completed in 1995. This project increased the refinery's capacity by
60,000 barrels per day and enables it to further upgrade low value heavy fuels
to premium distillates.
PETROLEUM - REFINED PRODUCTS MARKETING
PRODUCT SALES: The company and its Caltex Petroleum Corporation affiliate market
petroleum products throughout much of the world. The principal trademarks for
identifying these products are "Chevron," "Gulf" (principally in the United
Kingdom) and "Caltex." U.S. sales volumes of refined products by the company
during 1995 amounted to 1,117 thousand barrels per day, equivalent to
approximately 7 percent of total U.S. consumption. Worldwide sales volumes,
including the company's share of affiliate's sales, averaged 2,086 thousand
barrels per day in 1995, a decrease of about 7 percent from 1994. This decrease
was largely due to the sale of the company's Philadelphia, Pennsylvania,
refinery in August 1994 and its Port Arthur, Texas refinery in February 1995 as
well as refinery downtime in 1995. This decrease was partially offset by higher
sales recorded by the company's Caltex affiliate.
- 18 -
The following table shows the company's and its affiliate's refined product
sales volumes, excluding intercompany sales, over the past three years.
-----------------------------------------------------------
REFINED PRODUCTS SALES VOLUMES
(Thousands of Barrels Per Day)
1995 1994 1993
------ ------ ------
United States
Gasolines 552 615 652
Gas Oils and Kerosene 196 277 325
Jet Fuel 241 260 247
Residual Fuel Oil 38 65 94
Other Petroleum Products* 90 97 105
------ ------ ------
Total United States 1,117 1,314 1,423
------ ------ ------
International
United Kingdom 97 118 111
Canada 58 56 50
Other International 157 140 168
------ ------ ------
Total International 312 314 329
------ ------ ------
Total Consolidated Companies 1,429 1,628 1,752
Equity in Affiliate 657 620 594
------ ------ ------
Total Including Affiliate 2,086 2,248 2,346
====== ====== ======
* Principally naphtha, lubes, asphalt and coke.
-----------------------------------------------------------
The company's Canadian sales volumes consist of refined product sales in British
Columbia and Alberta by the company's Chevron Canada Limited subsidiary. In the
United Kingdom, the reported sales volumes comprise a full range of product
sales by the company's Gulf Oil (Great Britain) Ltd. subsidiary. The 1995
volumes reported for "Other International" relate primarily to international
sales of aviation, marine fuels, gas oils and refined products in Latin America,
the Far East and elsewhere. The equity in affiliate's sales in 1995 consists of
the company's interest in Caltex Petroleum Corporation, which operates in
approximately 60 countries including the Philippines, Thailand, New Zealand,
South Africa and, through Caltex affiliates, in Australia, Japan and Korea.
Due to the global nature and interdependence of the company's oil and petroleum
products trading and marketing businesses, the company realigned the operations
of its principal international trading company, Chevron International Oil
Company, with those of its U.S. counterpart, Chevron Products Company and its
international upstream company, Chevron Overseas Petroleum Inc. in January 1996.
In connection with this realignment, Chevron Products Company's lubricants
division announced that it will reorganize into a Global Business Unit to better
serve international markets.
Retail Outlets: In the United States, the company supplies, directly or through
jobbers, approximately 8,400 motor vehicle, aircraft and marine retail outlets,
including more than 1,900 company-owned or -leased motor vehicle service
stations. The company's gasoline market area is concentrated in the southern,
southwestern and western states. Chevron estimates it is the fifth largest
seller of gasoline in the United States and is among the top three marketers in
14 states.
Non-fuel revenues continue to be an area of growth and opportunities for the
company. After testing consumers' interest in 1994 and 1995, Chevron signed an
agreement with McDonald's to develop a network of retail sites that join Chevron
service stations and convenience stores with McDonald's restaurants in 12
western and southwestern
- 19 -
states. Revenues from direct mail marketing, introduced in 1993, continued to
grow in 1995 as did revenues from convenience stores and enhanced car wash
facilities.
The company expanded its "FastPay" system, increasing the total service stations
with the system to about 3,000 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.
In December 1995, the company announced the realignment of its U.S. gasoline
marketing business, combining several regional offices and consolidating support
functions with the aim of increasing the focus of the organization on customer
service and sales growth. The reorganization will leave service station
operations largely unaffected, but will reduce the number of non-service station
support personnel by 130 positions.
Internationally, the company's branded products are sold in 193 owned or leased
stations in British Columbia, Canada and in 523 (208 owned or leased) stations
in the United Kingdom.
PETROLEUM - TRANSPORTATION
TANKERS: Chevron's controlled seagoing fleet at December 31, 1995 is summarized
in the following table. All controlled tankers were utilized in 1995.
----------------------------------------------------------------------------
CONTROLLED TANKERS AT DECEMBER 31, 1995
U.S. Flag Foreign Flag
---------------------------- ----------------------------
Cargo Capacity Cargo Capacity
Number (Millions of Barrels) Number (Millions of Barrels)
------ --------------------- ------ ---------------------
Owned - - 19 18
Bareboat Charter 6 2 10 14
Time-Charter - - 7 3
--- --- ---- ----
Total 6 2 36 35
=== === ==== ====
----------------------------------------------------------------------------
Federal law requires that cargo transported between U.S. ports be carried in
ships built and registered in the United States, owned and operated by U.S.
entities and manned by U.S. crews. At year-end 1995, 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 1995, 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 above, the company owns
a one-sixth undivided interest in each of six 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 primarily to
various Japanese gas and electric utilities.
Chevron continued to upgrade and "right-size" its fleet of vessels in 1995 by
selling one 2.0 million barrel capacity tanker and one 500,000 barrel capacity
tanker in its international and U.S. fleet, respectively. The company also had a
net reduction in its time-chartered fleet by one tanker and 1.2 million barrels
of capacity during 1995. Four
- 20 -
international tankers were sold for $282 million and leased back in 1995 to
provide fleet management flexibility in the form of charter termination options.
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 crude oil, refined
products and natural gas pipelines in the U.S. The company also has direct or
indirect interests in other U.S. and international pipelines. The company's
ownership interests in pipelines are summarized in the following table:
-------------------------------------------------------------------
PIPELINE MILEAGE AT DECEMBER 31, 1995
Wholly Partially
Owned Owned(1) Total
------ ---------- ------
United States:
Crude oil(2) 5,189 605 5,794
Natural gas 405 32 437
Petroleum products 4,265 1,472 5,737
------ ------ ------
Total United States 9,859 2,109 11,968
------ ------ ------
International:
Crude oil - 772 772
Natural gas - 228 228
Petroleum products 12 84 96
------ ------ ------
Total International 12 1,084 1,096
------ ------ ------
Worldwide 9,871 3,193 13,064
====== ====== ======
(1)Reflects equity interest in lines.
(2)Includes gathering lines related to the transportation function.
Excludes gathering lines related to the U.S. production function.
-------------------------------------------------------------------
The company sold its 50 percent interest in Kenai Pipe Line Company, located in
Alaska, in March 1995 and its 15 percent interest in Platte Pipe Line Company,
located in the central United States, in February 1996.
CHEMICALS
The company's chemicals operation manufactures and markets commodity chemical
products for industrial use and chemical additives for fuels and lubricants. At
year-end 1995, Chevron Chemical Company owned and operated 19 U.S. manufacturing
facilities in 10 states, owned manufacturing facilities in Brazil and France,
and owned a majority interest in a manufacturing facility in Japan. The
principal U.S. plants are located at Cedar Bayou, Orange and Port Arthur, Texas;
St. James and Belle Chasse, Louisiana; Marietta, Ohio; Pascagoula, Mississippi;
and Richmond, California. The company's three major operating divisions in 1995
were "Olefins and Derivatives," "Aromatics and Derivatives," and "Oronite
Additives." Chevron completed its withdrawal from the fertilizer business with
the sale of its remaining fertilizer plant in St. Helens, Oregon in January
1996.
- 21 -
The following table shows, by chemical division, 1995 revenues and the number of
owned or majority owned chemical manufacturing facilities and combined operating
capacities as of December 31, 1995.
- ------------------------------------------------------------------------------
CHEMICAL OPERATIONS
Manufacturing
Facilities
-------------- 1995
Inter- Annual Revenue(1)
Division U.S. national Capacity ($ Millions)
--------------------------- ----- -------- -------------------- ------------
Olefins and Derivatives 10 - 7,035 million lbs. $1,541
Aromatics and Derivatives 5 - 5,126 million lbs. 1,263
Oronite Additives 2 3 181 million gal. 876
Other (including
excise tax)(2) 2 - 89
--- ---- ------
Totals 19 3 $3,769
=== ==== ======
(1)Excludes intercompany sales.
(2)No meaningful common measurement for annual capacity.
- ------------------------------------------------------------------------------
The company is reorganizing its Olefins and Aromatics divisions to take better
advantage of strengths in U.S. markets and to increase the company's focus on
developing international growth opportunities. The former Olefins and Aromatics
divisions will be combined to form one U.S. Chemicals Division that will be
headquartered in Houston, Texas. A new International Group, headquartered in San
Ramon, California, will be responsible for coordination of non-U.S. supply
sources, marketing, and new manufacturing projects overseas. The Oronite
Additives Division, which already operates internationally, is unaffected by the
reorganization.
Expansion of the linear low density polyethylene (LLDPE) manufacturing facility
at Cedar Bayou, Texas was completed in the first quarter of 1996. The expansion
increased the plant's production capacity of LLDPE by 340 million pounds per
year. The company announced plans to expand and modernize its ethylene
production facilities at Port Arthur, Texas. The project, expected to begin in
1996 and last through year-end 1997, will increase plant capacity from 1 billion
to 1.7 billion pounds per year. The company's Marietta, Ohio polystyrene plant
is also slated for a $50 million expansion, which is targeted for an April 1997
start-up. At the company's Pascagoula, Mississippi refinery, construction on a
paraxylene facility expansion is scheduled to begin in 1996, with an anticipated
start-up date in 1998. Internationally, in a 50/50 joint venture, the company
expects to begin construction of a $600 million aromatics complex using the
company's Aromax technology in Jubail, Saudi Arabia in 1996. The company has
also contracted to build a fuel and lube oil additives plant in Singapore.
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 three surface and
two underground mines as of year-end 1995. Two of the mines are located in New
Mexico and one each in Wyoming, Alabama and Kentucky. 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 southwest and southeast. P&M also has a 33 percent
interest in the Black Beauty Coal Company whose principal operations are in
Indiana and Illinois.
Sales of coal from P&M's wholly-owned mines and from its interest in the Black
Beauty Coal Company were 17.3 million tons in 1995, a decrease of 15 percent
from 1994 sales of 20.4 million tons. The decrease was primarily due to lower
sales at the McKinley, New Mexico mine (caused by an abundance of hydroelectric
power and high customer coal inventories that led to reduced demand), a
reduction in the company's interest in Black Beauty Coal Company from 50 percent
to 33 percent in late August 1994 and reduced sales from the Edna, Colorado coal
mine that was idled in December 1994. About 60 percent of 1995 sales came from
two mines, the McKinley Mine and the
- 22 -
Kemmerer Mine in Wyoming. The average selling price for coal from mines owned
and operated by P&M was $23.67 per ton in 1995 compared to $24.39 per ton in
1994, contributing $350 million and $414 million to Chevron's consolidated sales
and other operating revenues in 1995 and 1994, respectively. At year-end 1995,
P&M controlled approximately 507 million tons of developed and undeveloped coal
reserves, including significant reserves of environmentally desirable low-sulfur
coal.
Demand growth for coal in the United States 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. In 1995, the
electric utility industry consumed over 80 percent of all coal produced in the
United States. Approximately 88 percent of P&M's coal sales are made to electric
utilities. Of those sales, about 50 percent are under contracts longer than 10
years and 20 percent are under three to ten year contracts based on original
contract terms. Generally, these contracts contain index adjusted pricing
provisions and minimum take requirements that have helped mitigate the effects
of short-term fluctuations in coal prices and consumption levels on P&M.
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 1995
numbered approximately 2,300.
Chevron's research and development expenses were $185 million, $179 million and
$206 million for the years 1995, 1994 and 1993, respectively.
In August 1995 the company agreed to license its Isodewaxing technology to
China's Daqing Petroleum Administrative Bureau for a planned lube base oil plant
750 miles northeast of Bejing. The company's Isodewaxing technology also was
selected by Neste Oy for a new lube oil manufacturing facility at Porvoo
Refinery near Helsinki, Finland. Isodewaxing is a catalytic process that
changes the characteristics of waxy molecules in crude feedstocks, resulting in
a greater yield of high-quality base oils at a lower operating cost than
conventional solvent-based processing.
Licenses under the company's patents are generally made available to others in
the petroleum and chemical industries. However, the company's business is not
dependent upon licensing patents.
ENVIRONMENTAL PROTECTION: One of Chevron's goals is to be recognized worldwide
for environmental excellence. Chevron's revised corporate policy on Health,
Environment and Safety was approved by the stockholders in 1991. In 1992, a
comprehensive program of 102 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 Association's program called "Responsible Care." It is also
similar to the American Petroleum Institute's program called "Strategies for
Today's Environmental Partnership." In 1994, the company published an
environmental, health and safety performance report named "Measuring Progress -
A Report on Chevron's Environmental Performance." This report describes the
company's environmental performance since its last environmental report issued
in 1990 and summarizes the company's policy and approach to environmental
protection.
The company's oil and gas exploration activities, along with those of many other
petroleum companies, have been hampered by drilling moratoria, imposed because
of environmental concerns, in areas where the company has leasehold interests.
Difficulties and delays in obtaining necessary permits, 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
- 23 -
position, its liquidity, or its competitive position relative to other U.S. 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.
Since 1991, the company has spent over $1.6 billion in capital expenditures on
air quality projects at its refining facilities, primarily in order to comply
with federal and state clean air regulations and to provide consumers with fuels
that reduce air pollution and air toxicity. As of January 1, 1995, the Clean Air
Act Amendments of 1990 require that only reformulated gasoline (RFG) may be sold
in the nine worst ozone areas in the United States and other areas have
voluntarily opted into the RFG requirement. In addition, the California Air
Resources Board requires a more stringent reformulated gasoline be sold
statewide in all service stations beginning on June 1, 1996.
The Federal Oil Pollution Act of 1990 (OPA) created federal authority to direct
private responses to oil spills, to improve preparedness and response
capabilities, and to impose monetary damages on spillers for restoration and
loss of use of the resources during restoration. Under OPA, owners or operators
of vessels operating in U.S. waters or transferring cargo in waters within the
U.S. Exclusive Economic Zone are required to possess a Certificate of Financial
Responsibility for each of these vessels. The Certificate is issued by the U.S.
Coast Guard after the owner or operator has demonstrated the ability to meet
Coast Guard guidelines for financial responsibility in the case of an oil spill.
OPA also requires the scheduled phase-out, by year-end 2014, of all single hull
tankers for trading to U.S. ports or transferring cargo in waters within the
U.S. Exclusive Economic Zone, which has and will continue to result in the
utilization of more costly double hull tankers. A separate single hull phase-out
schedule under the International Maritime Organization's Regulation 13 is
leading to the utilization of more costly double hull tankers in Europe and some
other parts of the world. Chevron has been actively involved in the Marine
Preservation Association, a non-profit organization that funds the Marine Spill
Response Corporation (MSRC). MSRC owns the largest stockpile of oil spill
response equipment in the nation and operates five strategically located U.S.
coastal regional centers. In addition, the company is a member of many oil-spill
response cooperatives in areas in which it operates around the world.
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.
In 1995, the company's U.S. capitalized environmental expenditures were $607
million, representing approximately 29 percent of the company's total
consolidated U.S. capital and exploratory expenditures. The company's U.S.
capitalized environmental expenditures were $645 million and $620 million in
1994 and 1993, respectively. These environmental expenditures include capital
outlays to retrofit existing facilities, as well as those associated with new
facilities. The expenditures are predominantly in the petroleum segment and
relate mostly to air and water quality projects and activities at the company's
refineries, oil and gas producing facilities and marketing facilities. For 1996,
the company estimates that capital expenditures for environmental control
facilities will be approximately $188 million. The actual expenditures for 1996
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 are expected to stabilize at the estimated
1996 levels with the completion of air quality projects in 1995 to produce
cleaner-burning fuels at the company's two California refineries.
Under provisions of the Superfund law, Chevron has been designated as a
potentially responsible party (PRP) for remediation of a portion of 251
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 1995, the company's
environmental remediation reserve related to Superfund sites amounted to $60
million. Forecasted expenditures for the largest of these sites, located in
California, amounts to approximately 18 percent of the reserve.
- 24 -
The company's 1995 environmental expenditures, remediation provisions and year-
end environmental reserves are discussed on pages FS-2 through FS-3 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, natural gas, coal 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-29 to FS-34 of this Annual Report on Form 10-K.
Note 13, "Properties, Plant and Equipment," to the company's financial
statements contained on page FS-23 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 1995, 1994 and 1993.
ITEM 3. LEGAL PROCEEDINGS
A. CITIES SERVICE TENDER OFFER CASES.
The complaint by Cities Service Co. ("Cities Service") 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 been dismissed.
Plaintiff Cities Service filed its Second Amended Petition on April 25, 1994,
adding Oxy U.S.A. as the successor to plaintiff Cities Service, adding Chevron
U.S.A. Inc. as successor to Gulf Oil Corporation and adding Chevron Corporation
as a new defendant. In addition to the existing claims for breach of contract
and fraud, the amendments added the following causes of action: willful and
malicious breach of contract, negligent misrepresentation, interference with
prospective economic advantage in connection with the 1989 proposed Oxy-Cities
Department of Energy ("DOE") settlement, and the claimed DOE liability as
additional contract damages and as additional fraud damages. The amendment also
added a claim for punitive damages based upon the alleged fraud, negligent
misrepresentation, willful breach and interference claims and requested not less
than $100 million on each of the several claims, together with pre-judgment
interest and punitive damages. It also requested $12 million plus prejudgment
interest for Cities' costs in defending against DOE proceedings since 1989, and
an order entitling Cities Service 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.
Defendants answered, in part, the plaintiff's Second Amended Petition and moved
to dismiss the claims for negligent misrepresentation, malicious breach of
contract and interference with prospective economic advantage. In addition,
defendant Chevron Corporation moved to dismiss the petition for lack of subject
matter jurisdiction.
The motion to dismiss the new tort claim and certain other claims was denied and
an answer to these claims was timely filed. Chevron Corporation's motion to
dismiss for lack of personal jurisdiction was granted on September 7, 1994.
Plaintiff's motion to dismiss defendants' counterclaim was also granted.
The Oklahoma Supreme Court has denied defendants' petition for certiorari on the
trial court's certified interlocutory order concerning the defenses based upon
certain conditions in the contract and alleged misstatements by plaintiff
concerning its potential DOE liability.
- 25 -
Plaintiff's motion to bifurcate this case for two trials was granted by the
trial court on January 23, 1995. The first, and now only, trial will concern
plaintiff's claims for alleged breach of contract, willful and malicious breach
of contract, and negligent misrepresentation. Jury selection is expected to
begin in late March 1996. The second trial was to have covered plaintiff's
claims for alleged interference with prospective economic advantage in
connection with the proposed 1989 DOE settlement, and the claimed DOE liability
as additional damages under another claim of breach of contract. These claims
were settled in November 1995.
B. PERTH AMBOY NEW SOURCE PERFORMANCE STANDARD PENALTY.
The United States Environmental Protection Agency (EPA) claims that Chevron's
Perth Amboy refinery violated various provisions of the Clean Air Act New Source
Performance Standards ("NSPS") as a result of refinery modifications conducted
in 1973 and 1983. The EPA issued a compliance order in November 1993 and in 1994
issued a formal determination that the NSPS applied to the refinery. Chevron
paid a penalty of approximately $700,000 to settle the matter.
C. PREMANUFACTURE NOTIFICATION FOR DETERGENT ADDITIVES.
On September 30,1993, the EPA instituted an administrative proceeding, assessing
civil penalties of about $17 million 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 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. The company has challenged the
penalty assessment through an administrative appeal.
D. 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 was
federally mandated by January 1, 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. The EPA also sought civil penalties from the company for
activities conducted prior to the issuance of the permit. Chevron paid a penalty
of approximately $435,000 to settle the matter.
Other previously reported legal proceedings have been settled or the issues
resolved so as not to merit further reporting
- 26 -
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted during the fourth quarter of 1995 to a vote of security
holders through the solicitation of proxies or otherwise.
EXECUTIVE OFFICERS OF THE REGISTRANT AT MARCH 1, 1996
Major Area of
Name and Age Executive Office Held Responsibility
- -------------------- -------------------------------- -----------------------
K. T. Derr 59 Chairman of the Board since 1989 Chief Executive Officer
Director since 1981
Executive Committee Member
since 1986
J. N. Sullivan 58 Vice-Chairman of the Board Worldwide Refining,
since 1989 Marketing and Trans-
Director since 1988 portation Activities,
Executive Committee Member Chemicals, Real Estate,
since 1986 Environmental, Human
Resources, Coal,
Administrative
Services, Aircraft
Services
R. E. Galvin 64 Vice-President since 1988 North American Explora-
Director since 1996 tion and Production,
President of Chevron U.S.A. Natural Gas Liquids,
Production Company since 1992 Research(joint with
Executive Committee Member R.H. Matzke)
since 1993
D. J. O'Reilly 49 Vice-President since 1991 U.S. Refining, Market-
President of Chevron Products ing and Supply
Company since 1994
Executive Committee Member
since 1994
M. R. Klitten 51 Vice-President and Chief Finance
Financial Officer since 1989
Executive Committee Member
since 1989
R. H. Matzke 59 Vice-President since 1990 Overseas Exploration
President of Chevron Overseas and Production,
Petroleum Inc. since 1989 Research (joint
Executive Committee Member with R.E. Galvin)
since 1993
J. E. Peppercorn 58 Vice-President since 1990 Chemicals
President of Chevron Chemical
Company since 1989
Executive Committee Member
since 1993
H. D. Hinman 55 Vice-President and General Law
Counsel since 1993
Executive Committee Member
since 1993
- 27 -
The Executive Officers of the Corporation consist of the Chairman of the Board,
the Vice-Chairman of the Board, and such other officers of the Corporation who
are either Directors or members of the Executive Committee, or are chief
executive officers of principal business units. Except as noted below, all of
the Corporation's Executive Officers have held one or more of such positions for
more than five years.
H. D. Hinman - Partner, Law Firm of Pillsbury Madison & Sutro - 1973
- Vice-President and General Counsel, Chevron Corporation - 1993
D. J. O'Reilly - Senior Vice-President, Chevron Chemical Company - 1989
- Vice-President for Strategic Planning and Quality, Chevron
Corporation - 1991
- Vice-President, Chevron Corporation and
President, Chevron U.S.A. Products Company - 1994
- 28 -
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
The information on Chevron's common stock market prices, dividends, principal
exchanges on which the stock is traded and number of stockholders of record is
contained in the Quarterly Results and Stock Market Data tabulations, on page
FS-11 of this Annual Report on Form 10-K.
ITEM 6. SELECTED FINANCIAL DATA
The selected financial data for years 1991 through 1995 are presented on page
FS-35 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 34 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 34 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 pages 2 through 4 of the Notice of Annual
Meeting of Stockholders and Proxy Statement dated March 22, 1996, is
incorporated herein by reference in this Annual Report on Form 10-K. See
Executive Officers of the Registrant on pages 27 and 28 of this Annual Report on
Form 10-K for information about executive officers of the company.
Item 405 of Regulation S-K calls for disclosure of any known late filing or
failure by an insider to file a report required by Section 16 of the Exchange
Act. This disclosure is contained on pages 20 through 21 of the Notice of Annual
Meeting of Stockholders and Proxy Statement dated March 22, 1996 and is
incorporated herein by reference in this Annual report on Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION
The information on pages 10 through 13 of the Notice of Annual Meeting of
Stockholders and Proxy Statement dated March 22, 1996, is incorporated herein by
reference in this Annual Report on Form 10-K.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information on page 5 of the Notice of Annual Meeting of Stockholders and
Proxy Statement dated March 22, 1996, 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.
- 29 -
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(A) THE FOLLOWING DOCUMENTS ARE FILED AS PART OF THIS REPORT:
(1) FINANCIAL STATEMENTS: PAGE (S)
--------------
Report of Independent Accountants FS-12
Consolidated Statement of Income
for the three years ended December 31, 1995 FS-12
Consolidated Balance Sheet at
December 31, 1995 and 1994 FS-13
Consolidated Statement of Cash Flows for
the three years ended December 31, 1995 FS-14
Consolidated Statement of Stockholders' Equity
for the three years ended December 31, 1995 FS-15
Notes to Consolidated Financial Statements FS-16 to FS-28
(2) FINANCIAL STATEMENT SCHEDULES:
Caltex Group of Companies Combined
Financial Statements C-1 to C-20
The Combined Financial Statements of the Caltex Group of Companies
are filed as part of this report. All schedules are omitted
because they are not applicable or the required information is
included in the combined financial statements or notes thereto.
(3) EXHIBITS:
The Exhibit Index on pages 32 and 33 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:
A Current Report on Form 8-K, dated December 6, 1995, was filed
by the company on December 6, 1995. This report announced that
the Registrant's 50 percent owned affiliate, Caltex Petroleum
Corporation ("Caltex"), had signed a letter of intent to sell its
50 percent interest in Nippon Petroleum Refining Company, Limited
to Caltex's partner, Nippon Oil Company, Limited.
A Current Report on Form 8-K, dated January 4, 1996, was filed by
the company on January 4, 1996. This report announced the
Registrant's adoption, in the fourth quarter of 1995, of
Statement of Financial Accounting Standards No. 121, "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets
to be Disposed Of."
A Current Report on Form 8-K, dated January 22, 1996, was filed
by the company on January 22, 1996. This report announced that
the Registrant and NGC Corporation had signed an exclusivity
agreement to negotiate the merger of certain natural gas
gathering, processing and marketing operations.
- 30 -
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 27th day of March
1996.
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 27th day of March 1996.
PRINCIPAL EXECUTIVE OFFICERS (AND DIRECTORS) DIRECTORS
KENNETH T. DERR* SAMUEL H. ARMACOST*
- -------------------------------------- ----------------------------------
Kenneth T. Derr, Chairman of the Board Samuel H. Armacost
JAMES N. SULLIVAN* RAYMOND E. GALVIN*
- -------------------------------------- ----------------------------------
James N. Sullivan, Raymond E. Galvin
Vice-Chairman of the Board
SAM GINN*
----------------------------------
PRINCIPAL FINANCIAL OFFICER Sam Ginn
MARTIN R. KLITTEN* CARLA A. HILLS*
- -------------------------------------- ----------------------------------
Martin R. Klitten, Vice-President Carla A. Hills
and Chief Financial Officer
CHARLES M. PIGOTT*
---------------------------------
Charles M. Pigott
PRINCIPAL ACCOUNTING OFFICER
CONDOLEEZZA RICE*
DONALD G. HENDERSON* ---------------------------------
- -------------------------------------- Condoleezza Rice
Donald G. Henderson,
Vice-President and Comptroller
JOHN A. YOUNG*
--------------------------------
John A. Young
GEORGE H. WEYERHAEUSER*
--------------------------------
George H. Weyerhaeuser
*By: /s/ LYDIA I. BEEBE
---------------------------------
Lydia I. Beebe, Attorney-in-Fact
- 31 -
EXHIBIT INDEX
EXHIBIT
NO. DESCRIPTION
- ------- -----------------------------------------------------------------------
3.1 Restated Certificate of Incorporation of Chevron Corporation, dated
August 2, 1994, filed as Exhibit 3.1 to Chevron Corporation's Quarterly
Report on Form 10-Q for the quarter and six month period ended June 30,
1994, and incorporated herein by reference.
3.2 By-Laws of Chevron Corporation, as amended July 27, 1994, 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 Quarterly Report on Form 10-Q for the quarter and six
month period ended June 30, 1994, 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 Computation of Ratio of Earnings to Fixed Charges (page E-1).
21.1 Subsidiaries of Chevron Corporation (page E-2).
23.1 Consent of Price Waterhouse LLP (page E-3).
- 32 -
EXHIBIT INDEX
(continued)
EXHIBIT
NO. DESCRIPTION
- ------- -----------------------------------------------------------------------
23.2 Consent of KPMG Peat Marwick LLP (page E-4).
24.1 Powers of Attorney for directors and certain officers of Chevron
to Corporation, authorizing the signing of the Annual Report on Form 10-K
24.12 on their behalf.
27.1 Financial Data Schedule
99.1 Definitions of Selected Financial Terms (page E-5).
Copies of above exhibits not contained herein are available, at a fee of $2 per
document, to any security holder upon written request to the Secretary's
Department, Chevron Corporation, 575 Market Street, San Francisco, California
94105.
- 33 -
INDEX TO MANAGEMENT'S DISCUSSION AND ANALYSIS,
CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PAGE(S)
----------------
Management's Discussion and Analysis ......................... FS-1 to FS-10
Quarterly Results and Stock Market Data ...................... FS-11
Report of Management ......................................... FS-11
Report of Independent Accountants ............................ FS-12
Consolidated Statement of Income ............................. FS-12
Consolidated Balance Sheet ................................... FS-13
Consolidated Statement of Cash Flows ......................... FS-14
Consolidated Statement of Stockholder's Equity ............... FS-15
Notes to Consolidated Financial Statements ................... FS-16 to FS-28
Supplemental Information on Oil and Gas Producing Activities . FS-29 to FS-34
Five-Year Financial Summary .................................. FS-35
- 34 -
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
KEY FINANCIAL RESULTS
Millions of dollars, except per-share amounts 1995 1994 1993
- -----------------------------------------------------------------------------
Sales and Other Operating Revenues $36,310 $35,130 $36,191
Net Income $ 930 $ 1,693 $ 1,265
Special (Charges) Credits
Included in Net Income $(1,032) $ 22 $ (883)
Per Share:
Net Income $ 1.43 $ 2.60 $ 1.94
Dividends $ 1.925 $ 1.85 $ 1.75
Return On:
Average Capital Employed 5.3% 8.7% 6.8%
Average Stockholders' Equity 6.4% 11.8% 9.1%
=============================================================================
Chevron's net income for 1995 was $930 million, down substantially from $1.693
billion in 1994 and $1.265 billion in 1993. However, special items, particularly
in 1995 and 1993, and a new accounting standard on asset impairment that was
adopted in 1995, affected the comparability of the company's reported results.
Special items and the new accounting standard, after related tax effects,
decreased reported earnings by $1.032 billion in 1995 and $883 million in 1993,
while increasing earnings by $22 million in 1994. Excluding the effects of the
new accounting standard in 1995 and special items in all years, operating
earnings of $1.962 billion in 1995 were up 17 percent from the $1.671 billion
earned in 1994, but down 9 percent from 1993's operating earnings of $2.148
billion.
OPERATING ENVIRONMENT AND OUTLOOK. After four years of declining crude oil
prices, Chevron's crude oil realizations increased in 1995. The company's
U.S. realizations averaged $1.48 per barrel higher than in 1994, and
international realizations were up $1.24. However, worldwide crude oil supplies
continue to be plentiful and are expected to remain so for the foreseeable
future. Non-OPEC crude oil sources have proliferated, and OPEC member
countries continue to influence crude oil prices through their production
levels.
On the other hand, U.S. natural gas prices continued to decline, falling an
average of 26 cents per thousand cubic feet to $1.51, as supplies of this
commodity continue to exceed demand, which is heavily dependent on weather
conditions and the price of alternate fuels, such as fuel oil. The company's
international gas realizations also were down an average 11 cents per thousand
cubic feet to $1.73.
Industry refined product sales margins continued to be weak worldwide throughout
the year. U.S. refining margins were especially low in the Gulf Coast region,
and marketing margins were weak on both the Gulf and West Coasts, as ample
supplies and a competitive marketplace prevented product prices from fully
reflecting the higher crude oil costs. These same reasons held down product
prices in the company's international refining and marketing areas in the United
Kingdom, Canada and, through its Caltex affiliate, the Asia-Pacific region.
In addition, Chevron's U.S. refining operations were negatively affected by
significant refinery downtime in 1995 for planned major maintenance and, to a
lesser extent, for unplanned downtime due to refinery problems. The company's
Richmond, California, refinery was down much of the fourth quarter for upgrades
required to produce California-mandated cleaner-burning gasolines.
The chemicals industry continued to strengthen in 1995's first half, as strong
demand translated to higher prices and increased sales volumes for Chevron's
olefins and aromatics products. These favorable conditions peaked midyear and
softened throughout the second half of 1995 and into 1996. Also, the company's
Port Arthur, Texas, ethylene unit was down for unplanned maintenance in early
1996. The company does not expect that 1996 chemicals results will be as strong
as 1995's.
Unusually cold weather in the eastern and central United States in late 1995 and
into 1996 pushed natural gas prices sharply higher due to increased heating
demand and low customer inventory levels. Crude oil prices also rose on
increased heating oil demand. The Henry Hub natural gas spot price, an industry
marker, was $2.91 per thousand cubic feet at year-end 1995 and continued to
increase into 1996, but retreated to $2.72 by late February 1996. Chevron's
posted price for West Texas Intermediate (WTI), a benchmark crude oil, was
$18.50 per barrel at year-end 1995 and $18.00 at February 23, 1996.
Chevron has no major refinery maintenance scheduled for 1996 and is positioned
to refine and market the California cleaner-burning gasolines mandated in the
second quarter. Weak industry sales margins have continued into 1996, and it is
uncertain whether the increased cost of manufacturing these fuels initially will
be recovered in the marketplace. Also, customer acceptance of the new gasolines,
together with the overall industry supply and demand situation, could affect
the company's 1996 results.
The company continues to review its operations to improve its competitiveness
and profitability. In 1995, the decision was made to exit the real estate
development business, a non-core activity located in California, and completion
of the sale of these properties is expected in the first half of 1996.
U.S. gasoline marketing is being reorganized to more efficiently serve the
customer by combining regional offices and consolidating support functions;
the international and U.S. trading and lubricants businesses are being
integrated into global organizations; and the chemicals operations are being
reorganized into geographic areas to facilitate international growth. Two staff
functions - Human Resources and Finance - are each adopting a shared services
approach to provide support to other Chevron organizations, and a new
financial information system is being installed throughout the company. All
these initiatives are intended to help the company accomplish its strategic
intents more effectively and at a lower cost.
In December 1995, Chevron entered into a service agreement with Maraven, a
subsidiary of Venezuela's national oil
FS-1
company, to operate and further develop the Boscan heavy oil field in
Venezuela. The field currently produces about 80,000 barrels per day. As
operator, Chevron will receive a per-barrel fee. Concurrently, agreements were
entered into to supply heavy crude oil to four Chevron U.S. refineries and to
form a joint venture with Maraven to market Chevron-made asphalt in the
western United States. These activities are expected to be in full operation
by mid-1996.
Caltex, Chevron's 50 percent-owned refining and marketing affiliate, is selling
its 50 percent interest in a refining company in Japan to its partner, Nippon
Oil Company, for about $2 billion. The sale, which will result in a significant
gain, is expected to be completed in the first half of 1996. The sales proceeds
are expected to fund dividends to the stockholders and to help fund Caltex
expansion projects in higher-growth areas of the Asia-Pacific region. Caltex's
new grass-roots refinery in Thailand is scheduled for completion in mid-1996.
In January 1996, Chevron announced its intent to merge substantially all of its
U.S. natural gas liquids and natural gas marketing businesses with NGC
Corporation. The company believes the merger will position these activities for
greater growth. If an agreement is reached, the transaction is expected to be
completed by midyear. Chevron will have, through common and preferred stock
holdings, an approximate 28 percent equity interest in the resulting company,
which will be North America's largest natural gas marketer, as well as the
largest processor and marketer of natural gas liquids. In addition, Chevron
expects to negotiate separate agreements for the new company to market Chevron's
North American natural gas production and provide energy and feedstock
requirements to its refineries and chemicals facilities.
INTERNATIONAL EXPLORATION AND PRODUCTION DEVELOPMENTS. Production from
Tengizchevroil (TCO), a 50 percent-owned joint venture with the Republic of
Kazakstan, continues to be constrained by lack of sufficient export
capability. In 1995, liquids production averaged 58,000 barrels per day, up
from 46,000 in 1994. At year end, daily production was at 64,000 barrels.
Crude oil production capacity currently is 95,000 barrels per day, which is
significantly less than the field's potential. Further field development is
dependent upon the availability of additional export capability or the
securing of other marketing alternatives. The partners remain committed to
realizing the full potential of the project and are developing additional
markets as they continue to explore political and commercial solutions to the
export situation. Chevron's cash investment in TCO at year-end 1995 was $717
million.
Chevron has significant oil-producing properties and major development projects
under way in Nigeria and Angola's Cabinda exclave, both of which continue to
experience political uncertainty and civil unrest. Although its operations
generally have been unaffected, the company continues to closely monitor
developments. In 1995, Chevron's net share of production averaged 133,000 and
118,000 barrels per day in Nigeria and Angola, respectively. In prior years,
Chevron's partner in Nigeria, the government-owned Nigerian National Petroleum
Corporation (NNPC), had fallen behind in paying its cash calls to Chevron and to
other oil companies operating in Nigeria. During 1995, NNPC made considerable
progress in bringing its payments to a more-current basis.
The respective participants in the U.K. and Norwegian sectors of the North Sea
Statfjord field have been unable to agree on an equity redetermination in the
field and have submitted the matter for resolution by an independent expert.
Chevron's share of 1995 production from Statfjord was 28,000 oil and equivalent
gas barrels per day in 1995.
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 1995 was
about $1.442 billion for its consolidated companies. Included in these
expenditures were $663 million of environmental capital expenditures and $779
million of costs associated with the control and abatement of hazardous
substances and pollutants from ongoing operations. The total amount also
includes spending charged against reserves established in prior years for
environmental cleanup programs (but not non-cash provisions to increase these
reserves or establish new ones during the year).
In addition to the costs for environmental protection associated with its
ongoing operations and products, the company may incur expenses for corrective
actions at various current and previously owned 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 the company's own policies in this area.
Accidental leaks and spills requiring cleanup may occur in the ordinary course
of business. In addition, an obligation may arise when operations are closed or
sold, or at non-Chevron sites where company products have been handled or
disposed of. Most of the expenditures to fulfill these obligations relate to
facilities and sites where past operations followed practices and procedures
that were considered acceptable under standards existing at the time, but now
require investigatory and/or remedial work to meet current standards.
During 1995, the company recorded $140 million of before-tax provisions ($90
million after tax) for environmental remediation efforts, including Superfund
sites. Also, included in the company's provision for the expected loss from
exiting its real estate development activities was $37 million ($24 million
after tax) for estimated environmental cleanup liabilities retained in
connection with the sale of certain properties. Actual expenditures charged
against these provisions and other previously established reserves amounted to
$162 million in
FS-2
1995. At year-end 1995, the company's environmental remediation reserves were
$1.234 billion, including $60 million related to Superfund sites.
Under provisions of the Superfund law, the Environmental Protection Agency (EPA)
has designated Chevron a Potentially Responsible Party (PRP) or has otherwise
involved it in the remediation of 251 hazardous waste sites. At year-end 1995,
the company's cumulative share of costs and settlements for approximately 174
of these sites, for which payments or provisions have been made in 1995 and
prior years, was about $131 million, including a provision of $17 million made
during 1995. No single site is expected to result in a material liability for
the company at this time. For the remaining sites, investigations are not yet at
a stage where the company is able to quantify a probable liability or determine
a range of reasonably possible exposure. The Superfund law provides for joint
and several liability. Any future actions by the EPA or 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.
It is likely the company will continue to incur additional charges beyond those
reserved for environmental remediation relating to past operations. These future
costs are indeterminable due to such factors as the unknown magnitude of
possible contamination, the unknown timing and extent of the corrective actions
that may be required, the determination of the company's liability in proportion
to other responsible parties and the extent to which such costs are recoverable
from third parties. While the amounts of future costs may be material to the
company's results of operations in the period in which they are recognized, the
company does not expect these costs to have a material effect on its
consolidated financial position or liquidity. Also, the company does not believe
its obligations to make such expenditures have had or will have any significant
impact on the company's competitive position relative to other domestic or
international petroleum or chemicals concerns. 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.
Over the past several years, the petroleum industry has incurred major capital
expenditures to meet clean-air regulations, such as the 1990 amendments to the
Clean Air Act in the United States. For companies operating in California, where
Chevron has a significant presence, the California Air Resources Board has
imposed even stricter requirements. Over the past five years, Chevron spent
approximately $1.8 billion on capital projects to comply with air quality
related measures. The bulk of this required spending has been completed. For
1996, total estimated environmental capital expenditures are estimated at $244
million, compared with $663 million spent in 1995, reflecting the completion of
major air quality projects. These capital costs are in addition to the ongoing
costs of complying with other environmental regulations and the costs to
remediate previously contaminated sites.
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 coal properties at the end of their productive lives.
Most such costs are environmentally related. Provisions are recognized on a
unit-of-production basis as the properties are produced. The amount of these
reserves at year-end 1995 was $1.7 billion and is included in accumulated
depreciation, depletion and amortization in the company's consolidated balance
sheet.
For the company's other ongoing operating assets, such as refineries, no
provisions are made for exit or cleanup costs that may be required when such
assets reach the end of their useful lives unless a decision to sell or
otherwise abandon the facility has been made.
OTHER CONTINGENCIES. At year-end 1995, the company had $250 million of
suspended exploratory wells included in properties, plant and equipment. The
wells are suspended pending a final determination of the commercial potential
of the related oil and gas fields. These well costs will be capitalized or
expensed depending on the results of future drilling activity and development
decisions.
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, although losses
could be material with respect to earnings in any given period.
The company utilizes various derivative instruments to manage its exposure to
price risk stemming from its integrated petroleum activities. Some of the
instruments may be settled by delivery of the underlying commodity, whereas
others can only be settled by cash. All these instruments are commonly used in
the global trade of petroleum products and are relatively straightforward,
involve little complexity and, with the exception of certain long-term natural
gas swaps, are of a short-term duration. Most of the activity in these
instruments is intended to hedge a physical transaction; hence gains and losses
arising from these instruments offset, and are recognized concurrently with,
gains and losses from the underlying commodities. The company believes it has
no material market or credit risks to its operations, financial position or
liquidity as a result of its commodities and other derivatives activities,
including forward exchange contracts and interest rate swaps, and that its
control systems are designed to monitor and manage its financial exposures in
accordance with company policies and procedures.
NEW ACCOUNTING STANDARDS. Effective October 1, 1995, the company adopted a new
accounting standard, Statement of Financial Accounting Standards (SFAS) No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets
to be Disposed Of." The adoption of this standard required non-cash charges
amounting to $659 million after tax, mostly
FS-3
related to impairment write-downs of U.S. oil and gas producing properties.
Impairment of the properties under the new standard is determined on an
individual field basis, whereas previously impairment was evaluated using an
aggregated approach.
SFAS No. 123, "Accounting for Stock-Based Compensation," establishes financial
and reporting standards for stock-based employee compensation plans, which will
be effective for Chevron's 1996 financial statements. The statement encourages,
but does not require, companies to adopt a fair-value-based method of
accounting for such plans, in place of current accounting standards. Companies
electing to continue their existing accounting must make pro forma disclosures
of net income as if the fair-value-based method of accounting had been applied.
The company is evaluating the statement and has made no decision whether to
adopt the new accounting or continue its present accounting.
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. Following is a table that
summarizes the (losses) gains, on an after-tax basis, from special items
included in the company's reported net income.
Millions of dollars 1995 1994 1993
- -----------------------------------------------------------------------------
Asset Write-offs and Revaluations
New Accounting Standard $ (659) $ - $ -
Other (304) - (71)
Environmental Remediation Provisions (90) (304) (90)
Restructurings and Reorganizations (50) (45) (554)
Prior-Year Tax Adjustments (22) 344 (130)
Asset Dispositions 7 48 122
LIFO Inventory Gains (Losses) 2 (10) (46)
Other 84 (11) (114)
- -----------------------------------------------------------------------------
Total Special Items $(1,032) $ 22 $(883)
=============================================================================
ASSET WRITE-OFFS AND REVALUATIONS. In 1995, an estimated loss of $168 million
was recognized in connection with the company's decision to exit its real estate
development business. Included in this charge was $24 million for anticipated
environmental remediation costs. Concurrent with implementing the new accounting
standard for asset impairment in 1995, and in preparation for installation of
the company's new financial information system, a comprehensive review of all
the company's fixed assets was conducted. As a result of this review, asset
write-offs of $94 million were recorded. Also, the write-down of certain assets
made obsolete by the conversion of two West Coast refineries to produce the new
California-mandated reformulated gasolines amounted to $38 million. Other
miscellaneous asset write-offs in 1995 amounted to $4 million. In 1993, asset
write-offs of $71 million comprised certain U.S. refinery assets, U.S. and
Canadian production assets, and miscellaneous corporate assets.
ENVIRONMENTAL REMEDIATION PROVISIONS pertain to estimated future costs for
environmental cleanup programs at certain of the company's U.S. service
stations, marketing terminals, refineries, chemical locations, and oil and gas
properties; divested operations in which Chevron has liability for future
cleanup costs; and sites, commonly referred to as Superfund sites, for which the
company has been designated a PRP by the EPA. Provisions for environmental
remediation amounted to $90 million in 1995, $304 million in 1994 and $90
million in 1993.
RESTRUCTURINGS AND REORGANIZATIONS charges in 1995 were $50 million, including
$12 million related to restructurings at Chevron's Caltex affiliate, and
consisted principally of voluntary and involuntary employee severance provisions
in connection with reorganizations of various business activities. The 1993
charge of $554 million was composed primarily of a write-down of the company's
Philadelphia and Port Arthur, Texas, refinery facilities and related inventories
to their realizable values. In estimating the refineries' realizable values, the
company took into account certain environmental cleanup obligations. The charges
also included provisions for environmental site assessments and employee
severance. In 1994, a $45 million adjustment was made to the 1993 charge as the
result of environmental remediation actions agreed to with regulatory agencies,
and retained by the company, in connection with the terms of the sale of the
Port Arthur refinery, and to recognize the effect of the refinery sale on the
company's chemicals operations. The Philadelphia refinery was sold in August
1994, and the Port Arthur refinery sale was completed in February 1995. At
year-end 1995, the balance remaining in the refineries' reserve was for
estimated environmental clean-up liabilities and was included in the company's
total environmental reserves.
PRIOR-YEAR TAX ADJUSTMENTS are generally the result of the settlement of audit
issues with taxing authorities or the re-evaluation by the company of its tax
liabilities as a result of new developments. Also, adjustments are required for
the effect on deferred income taxes of changes in statutory tax rates. In 1995,
charges for prior-year tax adjustments were $22 million, relating primarily to
a change in the Australian income tax rate. Tax adjustments in 1994 increased
earnings $344 million, including the net reversal of $301 million of tax and
related interest reserves resulting from the company's global settlement with
the Internal Revenue Service (IRS) for issues relating to the years 1979 through
1987. Tax adjustments decreased earnings $130 million in 1993, which included
the effect of a one percent increase in the U.S. corporate income tax rate.
ASSET DISPOSITIONS in 1995 increased earnings a net $7 million and consisted
of sales of a fertilizer plant, natural gas storage facility, and a small oil
and gas property in the United States. The 1994 sale of the company's lead and
zinc prospect in Ireland generated an after-tax profit of $48 million. The
Ortho lawn and garden products business was the major asset sold in 1993,
generating a $130 million gain.
LIFO INVENTORY LIQUIDATION GAINS (LOSSES) result from the reduction of
inventories in certain inventory pools valued under the Last-In, First-Out
(LIFO) accounting method. LIFO effects increased net income in 1995 by $2
million as inventories were liquidated at historical costs that were lower
than the current year costs. LIFO losses decreased net income in 1994
FS-4
and 1993 by $10 million and $46 million, respectively, when inventories were
liquidated at historical costs that were higher than costs incurred in those
years. These amounts include the company's equity share of Caltex LIFO
inventory effects. Chevron's consolidated petroleum inventories were 93
million barrels at year-end 1995 and 99 million barrels at year-end 1994 and
1993.
OTHER SPECIAL ITEMS in 1995 benefited earnings a net $84 million. A gain of $86
million related to a sale of land by a Caltex affiliate in Japan and a refund of
$27 million for federal lease costs were offset partially by litigation and
other costs. Charges in 1994 for litigation and regulatory settlements of $31
million were offset partially by a casualty insurance recovery of $20 million.
In 1993, net additions of $70 million to reserves for various litigation and
regulatory issues and a one-time cash bonus award to employees of $60 million,
were offset partially by a favorable inventory adjustment of $16 million.
RESULTS OF OPERATIONS. Operating results for 1995 were strong in all areas
except for U.S. downstream operations where very poor results severely
affected total earnings. Both chemicals and international upstream businesses
turned in record earnings, and U.S. upstream operations performed well
despite low natural gas prices. International oil and gas production and
reserves increased for the sixth consecutive year. In 1995, international oil
and gas production was up 4 percent, and the company replaced about 178
percent of its international production through proved reserve additions,
resulting in a worldwide replacement rate of about 138 percent.
U.S. downstream results in 1995 were affected by scheduled major maintenance
turnarounds at all the company's core refineries, particularly an extended
turnaround of the Richmond, California, refinery to tie in new units required to
produce the new California-mandated reformulated fuels. This, along with some
unplanned refinery problems and low industry refining margins, resulted in
severely depressed earnings for these operations.
Results for 1994 compared with 1993 were depressed by lower average crude oil
and natural gas prices and lower sales margins on refined products. Crude oil
prices were especially low in the first quarter of 1994, and U.S. refined
products margins were very weak in the second quarter. In addition to these
industry conditions, the company experienced unscheduled refinery downtime and
other refinery operating problems at its U.S. operations that further reduced
earnings, particularly in the first half of 1994. Chemicals operations, however,
were very strong, benefiting from improved industry fundamentals and the
restructuring and cost-reduction programs undertaken in recent years.
SALES AND OTHER OPERATING REVENUES were $36.3 billion, compared with $35.1
billion in 1994 and $36.2 billion in 1993. Revenues improved from 1994 primarily
because of higher prices for crude oil and refined products and higher chemicals
prices and sales volumes, partially offset by lower refined products sales
volumes and lower natural gas prices. The decline in 1994 revenues from 1993 was
due to lower prices for crude oil, natural gas and refined products, together
with lower refined products sales volumes. Higher crude oil and refined products
prices, together with increased volumes of third-party purchased products,
accounted for the increases in PURCHASED CRUDE OIL AND PRODUCTS costs in 1995.
OTHER INCOME in all years included net gains resulting from the disposition of
non-core assets, which caused other income to fluctuate from year to year.
OPERATING, SELLING AND ADMINISTRATIVE EXPENSES, adjusted for special items,
declined $272 million in 1995. Annual operating costs in 1995 were $1.3 billion
less than in 1991, the base measurement year set when the company launched its
cost-reduction program in early 1992. Although a portion of this cost reduction
is a result of operations disposed of over the years, much of the decrease is
due to a significant reduction in the company's ongoing cost structure.
Operating expenses in 1995 were negatively affected by scheduled refinery
shutdowns and maintenance. Unanticipated costs associated with unscheduled
refinery shutdowns and other refinery operating problems also affected operating
costs in both 1995 and 1994.
Reported selling, general and administrative expenses in 1994 were unusually low
due to a reversal of $319 million of accrued interest reserves on federal income
taxes payable resulting from the company's settlement with the IRS of most
issues for nine open tax years.
Millions of dollars 1995 1994 1993
- -----------------------------------------------------------------------------
Operating Expenses $5,974 $6,383 $7,104
Selling, General and
Administrative Expenses 1,384 963 1,530
- -----------------------------------------------------------------------------
Total Operational Costs 7,358 7,346 8,634
Eliminate Special Charges Before Tax (514) (230) (1,368)
- -----------------------------------------------------------------------------
Adjusted Ongoing Operational Costs $6,844 $7,116 $7,266
=============================================================================
DEPRECIATION, DEPLETION AND AMORTIZATION increased in 1995 from 1994 and 1993
because of the impairment of certain fixed assets together with other
adjustments to fixed asset carrying values.
TAXES on income were $859 million in 1995, $1.110 billion in 1994 and $1.161
billion in 1993, equating to effective income tax rates of 48 percent, 39.6
percent and 47.9 percent for each of the three years, respectively. The 1995 tax
rate reflected a shift in taxable earnings from lower tax-rate countries to
higher tax-rate countries. This increase in the tax rate was offset partially by
higher tax credits and an increase in equity earnings recorded on an after-tax
basis. The lower 1994 tax rate is attributable to the effect of favorable prior
year tax adjustments resulting from a global settlement with the IRS of most
issues for the years 1979 through 1987, which included the reversal of excess
interest reserves with little associated tax effect. Taxes in 1993 included
unfavorable prior-year tax adjustments, including a one percent increase in the
statutory U.S. corporate income tax rate.
CURRENCY TRANSACTIONS decreased net income $15 million and $64 million in 1995
and 1994, respectively, compared with an increase of $46 million in 1993. These
amounts include the company's share of affiliates' currency transactions. The
loss on currency transactions in 1995 resulted from fluctu-
FS-5
ations in the value of the Canadian and Nigerian currencies relative to the
U.S. dollar, while in 1994 it was due primarily to fluctuations in the value
of the Australian and Philippine currencies. In 1993, gains resulted from
fluctuations in the currency of Nigeria.
RESULTS BY MAJOR OPERATING AREAS
Millions of dollars 1995 1994 1993
- -----------------------------------------------------------------------------
Exploration and Production
United States $ 72 $ 518 $ 566
International 690 539 580
- -----------------------------------------------------------------------------
Total Exploration and Production 762 1,057 1,146
- -----------------------------------------------------------------------------
Refining, Marketing and Transportation
United States (104) 40 (170)
International 345 239 252
- -----------------------------------------------------------------------------
Total Refining, Marketing
and Transportation 241 279 82
- -----------------------------------------------------------------------------
Total Petroleum 1,003 1,336 1,228
Chemicals 484 206 143
Coal and Other Minerals (18) 111 44
Corporate and Other (539) 40 (150)
- -----------------------------------------------------------------------------
Net Income $ 930 $1,693 $1,265
=============================================================================
SPECIAL ITEMS BY MAJOR OPERATING AREAS
Millions of dollars 1995 1994 1993
- -----------------------------------------------------------------------------
Exploration and Production
United States $ (480) $ (66) $(136)
International (121) 20 (61)
- -----------------------------------------------------------------------------
Total Exploration and Production (601) (46) (197)
- -----------------------------------------------------------------------------
Refining, Marketing and Transportation
United States (179) (285) (725)
International 62 (10) 1
- -----------------------------------------------------------------------------
Total Refining, Marketing
and Transportation (117) (295) (724)
- -----------------------------------------------------------------------------
Total Petroleum (718) (341) (921)
Chemicals (40) (9) 112
Coal and Other Minerals (65) 48 -
Corporate and Other (209) 324 (74)
- -----------------------------------------------------------------------------
Total Special Items Included in Net Income $(1,032) $ 22 $(883)
=============================================================================
U.S. EXPLORATION AND PRODUCTION earnings in 1995, excluding special items, were
down 5 percent from 1994 levels and 21 percent from 1993. Operationally, higher
crude oil prices in 1995 did not fully offset the effects of lower production
volumes and lower natural gas prices. Natural gas accounts for about half the
company's combined U.S. oil and gas production. Lower average crude oil and
natural gas prices and lower crude oil production levels in 1994 contributed to
the earnings decline from 1993.
U.S. EXPLORATION AND PRODUCTION
Millions of dollars 1995 1994 1993
- -----------------------------------------------------------------------------
Earnings, Excluding Special Items $ 552 $584 $ 702
- -----------------------------------------------------------------------------
Asset Write-Offs and Revaluations
New Accounting Standard (490) - -
Other (7) - (13)
Environmental Remediation Provisions (8) (51) (13)
Restructurings and Reorganizations - - (2)
Prior-Year Tax Adjustments - - (40)
Asset Dispositions (2) - (54)
LIFO Inventory (Losses)Gains - (4) 1
Other 27 (11) (15)
- -----------------------------------------------------------------------------
Total Special Items (480) (66) (136)
- -----------------------------------------------------------------------------
Reported Earnings $ 72 $518 $ 566
=============================================================================
Net liquids production for 1995 averaged 350,000 barrels per day, down 5 percent
from 369,000 barrels per day in 1994 and down 11 percent from 394,000 barrels
per day in 1993. Net natural gas production in 1995 averaged about 1.9 billion
cubic feet per day, compared with 2.1 billion cubic feet per day in 1994 and
1993. The production declines resulted from producing property sales and from
normal field declines, partially offset by new production. The company has
several projects under way, including major long-term development projects in
the Gulf of Mexico, which are expected to stabilize its U.S. oil and gas
production volumes.
The company's average crude oil realizations were $15.34 per barrel in 1995, an
increase of $1.48 from $13.86 per barrel in 1994 and a 76 cent increase over the
$14.58 per barrel averaged in 1993. Crude oil prices began falling in the second
half of 1993, reached a low point early in 1994, recovered by year-end 1994 and
remained relatively steady during 1995.
Average natural gas prices were $1.51 per thousand cubic feet in 1995, down 26
cents from the 1994 average of $1.77 per thousand cubic feet. Natural gas prices
also fell throughout 1994, down 22 cents from $1.99 in 1993. Natural gas prices
increased in December 1995 and have remained strong into 1996, reflecting
increased demand caused by abnormally cold weather in the eastern United States.
Ongoing operating expenses and exploration expenses in 1995 both declined from
1994 and 1993 levels. Ongoing depreciation expense declined each year as a
result of lower production volumes.
INTERNATIONAL EXPLORATION AND PRODUCTION earnings in 1995 reflected higher crude
oil sales volumes and prices. Also contributing to the improved results was the
benefit of significantly lower effective tax rates in West Africa, primarily
resulting from credits associated with crude oil reserve additions. In 1994, an
$85 million swing in foreign exchange rates was the principal cause of the
earnings decline from 1993 levels.
FS-6
INTERNATIONAL EXPLORATION AND PRODUCTION
Millions of dollars 1995 1994 1993
- -----------------------------------------------------------------------------
Earnings, Excluding Special Items $ 811 $519 $641
- -----------------------------------------------------------------------------
Asset Write-Offs and Revaluations
New Accounting Standard (81) - (19)
Restructurings and Reorganizations (10) - (2)
Prior-Year Tax Adjustments (22) 20 (63)
Asset Dispositions - - 29
LIFO Inventory Losses (1) - (1)
Other (7) - (5)
- -----------------------------------------------------------------------------
Total Special Items (121) 20 (61)
- -----------------------------------------------------------------------------
Reported Earnings $ 690 $539 $580
=============================================================================
Operationally, the company's average international liquids prices, including
equity affiliates, increased to $16.10 per barrel from $14.86 in 1994 and was
about the same as the 1993 price of $16.09 per barrel. Average natural gas
prices were $1.73 per thousand cubic feet in 1995, compared with $1.84 and $2.08
in 1994 and 1993, respectively.
In 1995, net liquids production, including production from equity affiliates,
increased 4 percent over 1994 to 651,000 barrels per day, and was up 17 percent
from 1993 production levels. New production in West Africa, China and Australia
accounted for most of the increase. Net natural gas production volumes also
increased in 1995, up 3 percent from 1994 to 565 million cubic feet per day and
up 20 percent from 1993 levels. Production of crude oil and natural gas has been
increasing steadily since the late 1980s, reflecting the company's successful
strategy of growing its international operations.
In 1995 and 1994, foreign exchange losses were $16 million and $28 million,
respectively, whereas in 1993 foreign exchange gains amounted to $57 million.
SELECTED OPERATING DATA
1995 1994 1993
- -----------------------------------------------------------------------------
U.S. EXPLORATION AND PRODUCTION
Net Crude Oil and Natural Gas
Liquids Production (MBPD) 350 369 394
Net Natural Gas Production (MMCFPD) 1,868 2,085 2,056
Natural Gas Liquids Sales (MBPD) 213 215 211
Revenues from Net Production
Crude Oil ($/Bbl) $15.34 $13.86 $14.58
Natural Gas ($/MCF) $ 1.51 $ 1.77 $ 1.99
INTERNATIONAL EXPLORATION AND PRODUCTION(1)
Net Crude Oil and Natural Gas
Liquids Production (MBPD) 651 624 556
Net Natural Gas Production (MMCFPD) 565 546 469
Natural Gas Liquids Sales (MBPD) 47 34 37
Revenues from Liftings
Liquids ($/Bbl) $16.10 $14.86 $16.09
Natural Gas ($/MCF) $ 1.73 $ 1.84 $ 2.08
U.S. REFINING AND MARKETING
Gasoline Sales (MBPD) 552 615 652
Other Refined Products Sales (MBPD) 565 699 771
Refinery Input (MBPD) 925 1,213 1,307
Average Refined Products
Sales Price ($/Bbl) $26.19 $24.37 $25.35
INTERNATIONAL REFINING AND MARKETING(1)
Refined Products Sales (MBPD) 969 934 923
Refinery Input (MBPD) 598 623 598
CHEMICALS SALES AND OTHER OPERATING REVENUES(2)
United States $3,332 $2,801 $2,459
International 621 561 518
--------------------------
Worldwide $3,953 $3,362 $2,977
============================================================================
MBPD = THOUSAND BARRELS PER DAY; MMCFPD = MILLION CUBIC FEET PER DAY;
BBL = BARREL; MCF = THOUSAND CUBIC FEET.
(1) INCLUDES EQUITY IN AFFILIATES.
(2) MILLIONS OF DOLLARS. INCLUDES SALES TO OTHER CHEVRON COMPANIES. 1994 AND
1993 AMOUNTS RESTATED TO CONFORM WITH 1995 PRESENTATION.
U.S. REFINING AND MARKETING earnings, excluding special items, declined 77
percent from 1994 levels and were down 86 percent from the strong results of
1993. Extensive scheduled and unscheduled refinery maintenance, coupled with
weak industry refining margins, resulted in significantly reduced operating
earnings for 1995. In addition, the Richmond, California, refinery was down for
an extended period in the 1995 fourth quarter for upgrades required to produce
cleaner-burning California-mandated gasolines.
Average refined products prices were higher in 1995 compared with 1994 and 1993,
partially reflecting the increase in crude oil feedstock costs, but industry
refining margins were weak as refined products availability remained ample.
Margins were further weakened by high maintenance expenses in 1995
FS-7
caused by the extensive refinery downtime, which also required more expensive
third-party product purchases to supply the company's marketing system.
Results in 1994 were lower than in 1993; industry sales margins were lower and
unscheduled refinery downtime in early 1994 negatively affected both operating
expenses and purchased products costs.
U.S. REFINING AND MARKETING
Millions of dollars 1995 1994 1993
- -----------------------------------------------------------------------------
Earnings, Excluding Special Items $ 75 $ 325 $ 555
- -----------------------------------------------------------------------------
Asset Write-Offs and Revaluations
New Accounting Standard - - -
Other (112) - (25)
Environmental Remediation Provisions (62) (249) (77)
Restructurings and Reorganizations (7) (39) (543)
Prior-Year Tax Adjustments - - (38)
Asset Dispositions - - (1)
LIFO Inventory Gains (Losses) 2 3 (44)
Other - - 3
- -----------------------------------------------------------------------------
Total Special Items (179) (285) (725)
- -----------------------------------------------------------------------------
Reported (Loss) Earnings $(104) $ 40 $(170)
=============================================================================
Refined products sales volumes in 1995 declined about 15 percent and 22 percent
from 1994 and 1993 levels, largely due to the sales of the company's
Philadelphia refinery in August 1994 and its Port Arthur, Texas, refinery in
February 1995, in connection with a major restructuring of U.S. refining and
marketing operations. The volume declines year to year occurred primarily in
unbranded bulk sales; volumes sold through the company's marketing system were
about flat in the three years.
INTERNATIONAL REFINING AND MARKETING earnings include international marine
operations and equity earnings of the company's Caltex Petroleum Corporation
affiliate. Excluding special items, 1995 earnings increased 14 percent from 1994
levels and 13 percent from 1993.
INTERNATIONAL REFINING AND MARKETING
Millions of dollars 1995 1994 1993
- ----------------------------------------------------------------------------
Earnings, Excluding Special Items $283 $249 $251
- ----------------------------------------------------------------------------
Asset Write-Offs and Revaluations
New Accounting Standard - - -
Other (1) - (1)
Restructurings and Reorganizations (17) - (1)
Prior-Year Tax Adjustments - - (4)
Asset Dispositions - - 13
LIFO Inventory Losses - (10) (3)
Other 80 - (3)
- ----------------------------------------------------------------------------
Total Special Items 62 (10) 1
- ----------------------------------------------------------------------------
Reported Earnings $345 $239 $252
============================================================================
Improved results for 1995 primarily reflect improved shipping operations,
partially offset by lower results in the United Kingdom refining and marketing
operations, where low industry sales margins and an extensive planned refinery
turnaround in the second quarter negatively affected earnings. Shipping results
improved on higher ocean freight rates and lower operating expenses. There was
also a modest improvement in earnings reported by the company's Caltex affiliate
despite poor refining margins throughout its major operating areas in the Asia
Pacific region and South Africa. Compared with 1993, earnings in 1994 also
reflected lower results from the company's United Kingdom operations which
experienced an explosion and fire at the cracking facility that manufactures its
gasoline. All three years reflected weak industry conditions that held down
product prices, resulting in shrinking sales margins in the company's major
areas of operations.
International sales volumes for 1995 increased 4 percent over 1994 levels, due
to higher Caltex sales volumes and increased sales in Chevron's international
trading operations. Sales in 1994 and 1993 were about flat as a 5 percent
increase in marketing sales in 1994 was offset mostly by a decline in the
company's trading sales volumes. Caltex volumes, excluding transactions with
Chevron, increased 6 percent from 1994 and 4 percent from 1993 to 1994,
continuing its growth over the past several years.
Equity earnings of Caltex were $294 million, $210 million and $227 million for
1995, 1994 and 1993, respectively. In 1995, Chevron's share of Caltex earnings
included an $86 million benefit from a gain related to a land sale by a Caltex
affiliate in Japan. This gain was offset partially by other special items
netting to $18 million related to Caltex restructurings and asset write-offs. In
1995 and 1994, Chevron's share of Caltex earnings benefited $13 million and $15
million, respectively, from upward adjustments to the carrying value of its
petroleum inventories to reflect market values after a 1993 write-down of $52
million. Also, 1995 results included $13 million of favorable foreign tax
benefits. Caltex foreign currency transactions resulted in gains of $26 million
in 1995, losses of $27 million in 1994 and gains of $16 million in 1993.
Total international refining and marketing foreign currency transactions
amounted to gains of $19 million in 1995, losses of $19 million in 1994 and
gains of $2 million in 1993.
CHEMICALS reported record earnings, excluding special items, that were up
dramatically from 1994 and 1993 levels, reflecting higher sales volumes and
product prices. However, during the second half of 1995, industry conditions
began to soften, and falling prices for the company's major products, coupled
with increased feedstock costs, caused earnings to decline from the first half
of the year. Nevertheless, operating results were strong in all the company's
divisions - additives, aromatics and olefins. Foreign currency transaction
losses were $3 million in 1995 and $10 million in both 1994 and 1993.
FS-8
CHEMICALS
Millions of dollars 1995 1994 1993
- -----------------------------------------------------------------------------
Earnings, Excluding Special Items $524 $215 $ 31
- -----------------------------------------------------------------------------
Asset Write-Offs and Revaluations
New Accounting Standard (13) - -
Other (14) - -
Environmental Remediation Provisions (20) (4) -
Restructurings and Reorganizations (3) (6) (5)
Prior-Year Tax Adjustments - - (5)
Asset Dispositions 9 - 130
LIFO Inventory Gains 1 1 1
Other - - (9)
- -----------------------------------------------------------------------------
Total Special Items (40) (9) 112
- -----------------------------------------------------------------------------
Reported Earnings $484 $206 $143
=============================================================================
COAL AND OTHER MINERALS earnings, excluding special items, were down 25 percent
from 1994 levels, but up 7 percent from 1993 results. Mild weather in the first
half of 1995, coupled with customers electing to purchase cheaper alternate
fuels, reduced demand resulting in lower sales volumes and lower prices.
Operating results improved late in the year as industry conditions improved.
Sales, at about 17 million tons, were down 15 percent from the 20 million tons
produced in each of the prior two years. Earnings in 1994 were higher than in
1993 as coal sales margins were slightly higher, and earnings benefited from the
absence of 1993 losses from non-coal minerals activities.
COAL AND OTHER MINERALS
Millions of dollars 1995 1994 1993
- -----------------------------------------------------------------------------
Earnings, Excluding Special Items $ 47 $ 63 $44
- -----------------------------------------------------------------------------
Asset Write-Offs and Revaluations
New Accounting Standard (63) - -
Restructurings and Reorganizations (2) - -
Prior-Year Tax Adjustments - - (2)
Asset Dispositions - 48 5
Other - - (3)
- -----------------------------------------------------------------------------
Total Special Items (65) 48 -
- -----------------------------------------------------------------------------
Reported (Loss) Earnings $(18) $111 $44
=============================================================================
CORPORATE AND OTHER activities include interest expense, interest income on cash
and marketable securities, real estate and insurance operations, and corporate
center costs.
CORPORATE AND OTHER
Millions of dollars 1995 1994 1993
- -----------------------------------------------------------------------------
Earnings, Excluding Special Items $(330) $(284) $ (76)
- -----------------------------------------------------------------------------
Asset Write-Offs and Revaluations
New Accounting Standard (12) - -
Other (170) - (13)
Restructurings and Reorganizations (11) - (1)
Prior-Year Tax Adjustments - 324 22
Other (16) - (82)
- -----------------------------------------------------------------------------
Total Special Items (209) 324 (74)
- -----------------------------------------------------------------------------
Reported (Loss) Earnings $(539) $ 40 $(150)
=============================================================================
Corporate and other net operating charges, excluding special items, increased in
1995 as higher interest rates and lower earnings from real estate operations
more than offset lower corporate overhead expenses. Interest expense in 1994 was
higher than 1993 due to the combined effect of higher debt levels and higher
interest rates.
Corporate charges in 1995 and 1994 were higher than in 1993 because the company
changed its method of distributing certain corporate expenses to its business
segments in 1994. As a result, corporate and other charges for 1995 and 1994
included $226 million and $190 million, respectively, that under the previous
method, would have been allocated to the business segments. This change had no
net income effect.
LIQUIDITY AND CAPITAL RESOURCES. Cash, cash equivalents and marketable
securities increased $88 million to $1.4 billion at year-end 1995. Cash
provided by operating activities in 1995 was $4.1 billion, compared with $2.9
billion in 1994 and $4.2 billion in 1993. The 1995 increase reflects higher
operational earnings, adjusted for non-cash charges, and lower working capital
requirements, including the absence of the 1994 payment of $675 million to the
Internal Revenue Service for the settlement of several years of open tax
issues. Cash from operations, proceeds from asset sales and an increase in
overall debt levels were used to fund the company's capital expenditures and
dividend payments to stockholders.
At year-end 1995, the company classified $1.8 billion of short-term obligations
as long-term debt. Settlement of these obligations, consisting of commercial
paper, is not expected to require the use of working capital in 1996 because the
company has the intent and the ability, as evidenced by committed credit
arrangements, to refinance them on a long-term basis. The company's practice has
been to continually refinance its commercial paper, maintaining levels it
believes to be appropriate.
On December 31, 1995, Chevron had $4.4 billion in committed credit facilities
with various major banks. These facilities support commercial paper borrowing
and can also be used for general credit requirements. No borrowings were
outstanding under these facilities during the year or at year-end 1995. In
addition, Chevron and one of its subsidiaries each have existing "shelf"
registrations on file with the Securities and Exchange Commission that together
would permit registered offerings of up to $1.3 billion of debt securities.
The company's debt and capital lease obligations totaled $8.327 billion at
December 31, 1995, up $185 million from $8.142 billion at year-end 1994. The
increase is primarily the issuance of $282 million in capital lease obligations
associated with the sale and leaseback of four vessels, $160 million of 7.61
percent notes due in 2003, and $51 million of 6.92 percent notes due in 2005.
These increases were offset partially by $227 million in repayments of net
short-term borrowings, largely commercial paper, and miscellaneous other debt
repayments of $98 million. The company also retired $50 million of debt related
to the Employee Stock Ownership Plan in January 1995.
The company's future debt level is dependent primarily on its capital spending
program and its business outlook. While the company does not currently expect
its debt level to increase significantly during 1996, it believes it has
substantial borrowing capacity to meet unanticipated cash requirements.
FS-9
FINANCIAL RATIOS
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 1995 were lower than
current costs by $917 million. Also, the company's practice of continually
refinancing its commercial paper, $3.0 billion classified as short-term at year
end 1995, results in a large portion of its short-term debt being outstanding
indefinitely. The INTEREST COVERAGE RATIO is defined as income before income tax
expense, plus interest and debt expense and amortization of capitalized
interest, divided by before-tax interest costs. Chevron's interest coverage
ratio decreased in 1995 due to lower before-tax income and higher interest
expense. The company's DEBT RATIO (total debt to total debt plus equity)
increased slightly in 1995, as total debt increased and stockholders' equity
decreased year to year, due to the charge against earnings from the adoption of
the new accounting standard.
FINANCIAL RATIOS
1995 1994 1993
- -----------------------------------------------------------------------------
Current Ratio 0.8 0.8 0.8
Interest Coverage Ratio 4.1 7.6 7.4
Total Debt/Total Debt Plus Equity 36.7% 35.8% 35.0%
=============================================================================
The company's senior debt is rated AA by Standard & Poor's Corporation and Aa2
by Moody's Investors Service. Chevron's U.S. commercial paper is rated A-1+ by
Standard & Poor's and Prime-1 by Moody's, and Chevron's Canadian commercial
paper is rated R-1 (middle) by Dominion Bond Rating Service. Moody's
counterparty rating for Chevron is also Aa2. All these ratings denote high
quality, investment-grade securities.
CAPITAL AND EXPLORATORY EXPENDITURES
WORLDWIDE CAPITAL AND EXPLORATORY EXPENDITURES FOR 1995 TOTALED $4.8 BILLION,
including the company's equity share of affiliates' expenditures. Expenditures
for exploration and production accounted for 57 percent of total outlays in 1995
and 1994, compared with 53 percent in 1993. International exploration and
production spending was 68 percent of worldwide exploration and production
expenditures in 1995, down slightly from 71 percent in 1994 and about the same
percentage as in 1993, reflecting the company's continued focus on international
exploration and production activities.
THE COMPANY PROJECTS 1996 CAPITAL AND EXPLORATORY EXPENDITURES AT APPROXIMATELY
$5.3 BILLION, including Chevron's share of spending by affiliates; this is up
about 10 percent from 1995 levels. The 1996 program provides $3.0 billion in
exploration and production investments, of which about 65 percent is for
international projects. Several long-term development projects in the Gulf of
Mexico designed to stabilize U.S. oil and gas production account for a projected
19 percent increase in U.S. exploration and production expenditures.
The company is participating in several significant oil and gas development
projects. These projects include the continuing development of the Hibernia oil
field off the coast of Newfoundland; steam- and water-flood projects in
Indonesia; expansion of the North West Shelf liquefied natural gas project in
Australia; development of the Britannia gas field and the expansion of the Alba
oil field in the North Sea; development of the N'Kossa and Kitina projects and
delineation work at the Moho discovery in Congo; continued development of the
Escravos Gas Project in Nigeria; development of Areas "B" and "C" in Angola;
continuing enhanced oil recovery projects in California; and continued
development in the Norphlet Trend natural gas and Green Canyon deep-water oil
projects in the Gulf of Mexico. The TCO joint venture plans to fund an increase
in production capacity from 95,000 to 130,000 barrels per day if an expected
increase in crude oil sales occurs.
Refining, marketing and transportation expenditures are estimated at about $1.5
billion, with $890 million of that planned for international projects.
Completion in 1995 of the company's U.S. refinery upgrade projects to produce
California-mandated fuels will result in lower total spending in the U.S.
downstream areas by 36 percent to $570 million in 1996, but spending will
increase 40 percent to $282 million for domestic marketing projects. Most of the
international capital program 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 as well as a
major project to upgrade its retail marketing system. Chemicals spending also
will increase substantially, with expansion projects at the ethylene facilities
in Port Arthur, Texas, the paraxylene plant in Pascagoula, Mississippi, the
polystyrene plant in Marietta, Ohio, and the construction of a fuel and lube oil
additives plant in Singapore, and through a joint venture, a benzene and
cyclohexane complex in Saudi Arabia.
CAPITAL AND EXPLORATORY EXPENDITURES
1995 1994 1993
------------------------ ------------------------ ------------------------
INTER- Inter- Inter-
Millions of dollars U.S. NATIONAL TOTAL U.S. national Total U.S. national Total
- ----------------------------------------------------------------------------------------------------------------
Exploration and Production $ 879 $1,835 $2,714 $ 807 $1,931 $2,738 $ 763 $1,599 $2,362
Refining, Marketing
& Transportation 892 839 1,731 885 890 1,775 949 748 1,697
Chemicals 172 32 204 109 29 138 199 34 233
Coal and Other Minerals 40 1 41 39 15 54 47 10 57
All Other 110 - 110 114 - 114 91 - 91
- ----------------------------------------------------------------------------------------------------------------
Total $2,093 $2,707 $4,800 $1,954 $2,865 $4,819 $2,049 $2,391 $4,440
- ----------------------------------------------------------------------------------------------------------------
Total, Excluding
Equity in Affiliates $2,080 $1,808 $3,888 $1,927 $2,046 $3,973 $2,029 $1,710 $3,739
================================================================================================================
FS-10
QUARTERLY RESULTS AND STOCK MARKET DATA
Unaudited
1995 1994
--------------------------------- ---------------------------------
Millions of dollars, except per-share amounts 4TH Q 3RD Q 2ND Q 1ST Q 4TH Q 3RD Q 2ND Q 1ST Q
- ----------------------------------------------------------------------------------------------------------------------
REVENUES
Sales and other operating revenues $8,922 $9,171 $9,397 $8,820 $8,927 $9,396 $8,702 $8,105
Equity in net income of affiliated
companies and other income 235 143 170 224 330 113 122 159
- ----------------------------------------------------------------------------------------------------------------------
TOTAL REVENUES 9,157 9,314 9,567 9,044 9,257 9,509 8,824 8,264
- ----------------------------------------------------------------------------------------------------------------------
COSTS AND OTHER DEDUCTIONS
Purchased crude oil and products,
operating and other expenses 6,606 6,527 6,375 6,255 6,225 6,695 6,201 5,594
Depreciation, depletion and amortization(1) 1,679 560 566 576 598 626 615 592
Taxes other than on income 1,483 1,475 1,417 1,373 1,406 1,405 1,403 1,345
Interest and debt expense 94 93 104 110 97 93 83 73
- ----------------------------------------------------------------------------------------------------------------------
TOTAL COSTS AND OTHER DEDUCTIONS 9,862 8,655 8,462 8,314 8,326 8,819 8,302 7,604
- ----------------------------------------------------------------------------------------------------------------------
(LOSS) INCOME BEFORE INCOME TAX EXPENSE (705) 659 1,105 730 931 690 522 660
INCOME TAX EXPENSE (287) 377 498 271 308 265 265 272
- ----------------------------------------------------------------------------------------------------------------------
NET (LOSS) INCOME(2) $ (418) $ 282 $ 607 $ 459 $ 623 $ 425 $ 257 $ 388
======================================================================================================================
NET (LOSS) INCOME PER SHARE $(0.64) $ 0.44 $ 0.93 $ 0.70 $ 0.96 $ 0.65 $ 0.39 $ 0.60
======================================================================================================================
DIVIDENDS PAID PER SHARE $ 0.50 $ 0.50 $ 0.4625 $ 0.4625 $ 0.4625 $ 0.4625 $ 0.4625 $ 0.4625
======================================================================================================================
COMMON STOCK PRICE RANGE - HIGH $53 5/8 $50 3/8 $49 3/4 $48 1/2 $46 1/2 $45 3/8 $49 3/16 $47 5/16
- LOW $46 1/8 $46 5/8 $44 1/4 $43 3/8 $41 $39 7/8 $41 1/4 $41 3/16
======================================================================================================================
(1)FOURTH QUARTER 1995 INCLUDES $985 FROM
THE ADOPTION OF SFAS 121.
(2)SPECIAL (CHARGES) CREDITS INCLUDED IN NET
INCOME, INCLUDING A $659 CHARGE FOR THE
ADOPTION OF A NEW ACCOUNTING STANDARD,
SFAS 121, IN THE FOURTH QUARTER OF 1995. $ (869) $ (222) $ (4) $ 63 $ 45 $ 18 $ (5) $ (36)
- ----------------------------------------------------------------------------------------------------------------------
THE COMPANY'S COMMON STOCK IS LISTED ON THE NEW YORK STOCK EXCHANGE (TRADING SYMBOL: CHV), AS WELL AS THE CHICAGO;
PACIFIC; 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 23,1996, STOCKHOLDERS OF RECORD NUMBERED APPROXIMATELY 135,500.
THERE ARE NO RESTRICTIONS ON THE COMPANY'S ABILITY TO PAY DIVIDENDS. CHEVRON HAS MADE DIVIDEND PAYMENTS TO STOCKHOLDERS
FOR 84 CONSECUTIVE YEARS.
REPORT OF MANAGEMENT
TO THE STOCKHOLDERS OF CHEVRON CORPORATION
Management of Chevron is responsible for preparing the accompanying financial
statements and for assuring their integrity and objectivity. The statements
were prepared in accordance with generally accepted accounting principles and
fairly represent the transactions and financial position of the company. The
financial statements include amounts that are based on management's best
estimates and judgments.
The company's statements have been audited by Price Waterhouse LLP, independent
accountants, selected by the Audit Committee and approved by the stockholders.
Management has made available to Price Waterhouse LLP all the company's
financial records and related data, as well as the minutes of stockholders' and
directors' meetings.
Management of the company has established and maintains a system of internal
accounting controls that is designed to provide reasonable assurance that assets
are safeguarded, transactions are properly recorded and executed in accordance
with management's authorization, and the books and records accurately reflect
the disposition of assets. The system of internal controls includes appropriate
division of responsibility. The company maintains an internal audit department
that conducts an extensive program of internal audits and independently assesses
the effectiveness of the internal controls.
The Audit Committee is composed of directors who are not officers or employees
of the company. It meets regularly with members of management, the internal
auditors and the independent accountants to discuss the adequacy of the
company's internal controls, financial statements and the nature, extent and
results of the audit effort. Both the internal auditors and the independent
accountants have free and direct access to the Audit Committee without the
presence of management.
/s/ K. T. Derr /s/ M. R. Klitten /s/ D. G. Henderson
Kenneth T. Derr Martin R. Klitten Donald G. Henderson
Chairman of the Board Vice President Vice President
and Chief Executive Officer and Chief Financial Officer and Comptroller
February 23, 1996
FS-11
CONSOLIDATED STATEMENT OF INCOME
Year ended December 31
-----------------------------------
Millions of dollars,
except per-share amounts 1995 1994 1993
- ------------------------------------------------------------------------------
REVENUES
Sales and other operating revenues* $36,310 $35,130 $36,191
Equity in net income of affiliated
companies 553 440 440
Other income 219 284 451
- ------------------------------------------------------------------------------
TOTAL REVENUES 37,082 35,854 37,082
- ------------------------------------------------------------------------------
COSTS AND OTHER DEDUCTIONS
Purchased crude oil and products 18,033 16,990 18,007
Operating expenses 5,974 6,383 7,104
Exploration expenses 372 379 360
Selling, general and administrative expenses 1,384 963 1,530
Depreciation, depletion and amortization 3,381 2,431 2,452
Taxes other than on income* 5,748 5,559 4,886
Interest and debt expense 401 346 317
- ------------------------------------------------------------------------------
TOTAL COSTS AND OTHER DEDUCTIONS 35,293 33,051 34,656
- ------------------------------------------------------------------------------
INCOME BEFORE INCOME TAX EXPENSE 1,789 2,803 2,426
INCOME TAX EXPENSE 859 1,110 1,161
- ------------------------------------------------------------------------------
NET INCOME $ 930 $ 1,693 $ 1,265
==============================================================================
NET INCOME PER SHARE OF COMMON STOCK $1.43 $2.60 $1.94
WEIGHTED AVERAGE NUMBER OF SHARES
OUTSTANDING 652,083,804 651,672,238 650,957,752
==============================================================================
*INCLUDES CONSUMER EXCISE TAXES. $4,988 $4,790 $4,068
See accompanying notes to consolidated financial statements.
REPORT OF INDEPENDENT ACCOUNTANTS
TO THE STOCKHOLDERS
AND THE BOARD OF DIRECTORS OF CHEVRON CORPORATION
In our opinion, the accompanying consolidated balance 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, 1995 and 1994, and the
results of their operations and their cash flows for each of the three years
in the period ended December 31, 1995, 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 3 to the consolidated financial statements, effective
October 1, 1995, the company changed its method of accounting for the impairment
of long-lived assets to comply with the provisions of Statement of Financial
Accounting Standard No. 121.
/s/ Price Waterhouse LLP
San Francisco, California
February 23, 1996
FS-12
CONSOLIDATED BALANCE SHEET
At December 31
------------------
Millions of dollars 1995 1994
- -----------------------------------------------------------------------------
ASSETS
Cash and cash equivalents $ 621 $ 413
Marketable securities 773 893
Accounts and notes receivable
(less allowance: 1995 - $69; 1994 - $62) 4,014 3,923
Inventories:
Crude oil and petroleum products 822 1,036
Chemicals 487 391
Materials, supplies and other 289 283
------------------
1,598 1,710
Prepaid expenses and other current assets 861 652
- -----------------------------------------------------------------------------
TOTAL CURRENT ASSETS 7,867 7,591
Long-term receivables 149 138
Investments and advances 4,087 3,991
Properties, plant and equipment, at cost 48,031 46,810
Less: accumulated depreciation, depletion and amortization 26,335 24,637
------------------
21,696 22,173
Deferred charges and other assets 531 514
- -----------------------------------------------------------------------------
TOTAL ASSETS $34,330 $34,407
=============================================================================
LIABILITIES AND STOCKHOLDERS' EQUITY
Short-term debt $ 3,806 $ 4,014
Accounts payable 3,294 2,990
Accrued liabilities 1,257 1,274
Federal and other taxes on income 558 624
Other taxes payable 530 490
- -----------------------------------------------------------------------------
TOTAL CURRENT LIABILITIES 9,445 9,392
Long-term debt 4,133 3,955
Capital lease obligations 388 173
Deferred credits and other non-current obligations 1,992 2,043
Non-current deferred income taxes 2,433 2,674
Reserves for employee benefit plans 1,584 1,574
- -----------------------------------------------------------------------------
TOTAL LIABILITIES 19,975 19,811
- -----------------------------------------------------------------------------
Preferred stock (authorized 100,000,000 shares,
$1.00 par value, none issued) - -
Common stock (authorized 1,000,000,000 shares,
$1.50 par value, 712,487,068 shares issued) 1,069 1,069
Capital in excess of par value 1,863 1,858
Deferred compensation - Employee Stock
Ownership Plan (ESOP) (850) (900)
Currency translation adjustment and other 174 175
Retained earnings 14,146 14,457
Treasury stock, at cost (1995 - 60,160,057 shares;
1994 - 60,736,435 shares) (2,047) (2,063)
- -----------------------------------------------------------------------------
TOTAL STOCKHOLDERS' EQUITY 14,355 14,596
- -----------------------------------------------------------------------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $34,330 $34,407
=============================================================================
See accompanying notes to consolidated financial statements.
FS-13
CONSOLIDATED STATEMENT OF CASH FLOWS
Year ended December 31
-----------------------------
Millions of dollars 1995 1994 1993
- -----------------------------------------------------------------------------
OPERATING ACTIVITIES
Net income $ 930 $ 1,693 $ 1,265
Adjustments
Depreciation, depletion and amortization 3,381 2,431 2,452
Dry hole expense related to prior
years' expenditures 19 53 29
Distributions less than equity in
affiliates' income (132) (55) (173)
Net before-tax losses (gains) on
asset retirements and sales 164 (83) 373
Net foreign exchange losses (gains) 47 40 (27)
Deferred income tax provision (258) 110 (160)
Net decrease (increase) in operating
working capital(1) 40 (1,773) 463
Other (116) 480 (1)
- -----------------------------------------------------------------------------
NET CASH PROVIDED BY OPERATING ACTIVITIES(2) 4,075 2,896 4,221
- -----------------------------------------------------------------------------
INVESTING ACTIVITIES
Capital expenditures (3,529) (3,405) (3,323)
Proceeds from asset sales 581 731 908
Net sales (purchases) of marketable
securities(3) 144 (545) 30
- -----------------------------------------------------------------------------
NET CASH USED FOR INVESTING ACTIVITIES (2,804) (3,219) (2,385)
- -----------------------------------------------------------------------------
FINANCING ACTIVITIES
Net (repayments) borrowings of
short-term obligations (227) 466 293
Proceeds from issuance of long-term debt 536 436 199
Repayments of long-term debt and other
financing obligations (103) (588) (854)
Cash dividends paid (1,255) (1,206) (1,139)
Purchases of treasury shares (4) (5) (4)
- -----------------------------------------------------------------------------
NET CASH USED FOR FINANCING ACTIVITIES (1,053) (897) (1,505)
- -----------------------------------------------------------------------------
EFFECT OF EXCHANGE RATE CHANGES ON CASH AND
CASH EQUIVALENTS (10) (11) 21
- -----------------------------------------------------------------------------
NET CHANGE IN CASH AND CASH EQUIVALENTS 208 (1,231) 352
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 413 1,644 1,292
- -----------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT YEAR-END $ 621 $ 413 $ 1,644
=============================================================================
(1)THE "NET DECREASE (INCREASE) IN OPERATING
WORKING CAPITAL" IS COMPOSED OF THE FOLLOWING:
(INCREASE) DECREASE IN ACCOUNTS AND
NOTES RECEIVABLE $ (62) $ (44) $ 187
(INCREASE) DECREASE IN INVENTORIES (162) (57) 288
(INCREASE) DECREASE IN PREPAID EXPENSES
AND OTHER CURRENT ASSETS (148) 4 (52)
INCREASE (DECREASE) IN ACCOUNTS PAYABLE
AND ACCRUED LIABILITIES 428 (1,510) 214
DECREASE IN INCOME AND OTHER TAXES PAYABLE (16) (166) (174)
- -----------------------------------------------------------------------------
NET DECREASE (INCREASE) IN OPERATING
WORKING CAPITAL $ 40 $(1,773) $ 463
=============================================================================
(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) $ 318 $ 310 $ 309
INCOME TAXES PAID $ 1,176 $ 1,147 $ 1,505
=============================================================================
(3)"NET SALES (PURCHASES) OF MARKETABLE
SECURITIES" CONSISTS OF THE FOLLOWING
GROSS AMOUNTS:
MARKETABLE SECURITIES PURCHASED $(2,759) $(1,943) $(1,855)
MARKETABLE SECURITIES SOLD 2,903 1,398 1,885
- -----------------------------------------------------------------------------
NET SALES (PURCHASES) OF
MARKETABLE SECURITIES $ 144 $ (545) $ 30
=============================================================================
See accompanying notes to consolidated financial statements.
FS-14
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
NUMBER OF SHARES MILLIONS OF DOLLARS
------------------------ --------------------------------------------------------------------------
CURRENCY
COMMON COMMON CAPITAL IN DEFERRED TRANSLATION
STOCK STOCK IN COMMON EXCESS OF COMPENSA- ADJUSTMENT RETAINED TREASURY
ISSUED TREASURY STOCK PAR VALUE TION-ESOP AND OTHER EARNINGS STOCK
------------------------ -------------------------------------------------------------------------
BALANCE AT
JANUARY 1, 1993 712,487,068 (62,139,490) $1,069 $1,840 $(954) $ 56 $13,814 $(2,097)
Net income - - - - - - 1,265 -
Cash dividends -
$1.75 per share - - - - - - (1,139) -
Tax benefit from
dividends 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 - (92,506) - - - - - (4)
Reissuance of treasury shares - 1,223,138 - 15 - - - 31
- ------------------------------------------------------- -------------------------------------------------------------------------
BALANCE AT
DECEMBER 31, 1993 712,487,068 (61,008,858) $1,069 $1,855 $(920) $108 $13,955 $(2,070)
Net income - - - - - - 1,693 -
Cash dividends -
$1.85 per share - - - - - - (1,206) -
Tax benefit from
dividends paid on
unallocated ESOP shares - - - - - - 15 -
Market value adjustments
on investments - - - - - 11 - -
Foreign currency
translation adjustment - - - - - 72 - -
Pension plan
minimum liability - - - - - (16) - -
ESOP expense
accrual adjustment - - - - (20) - - -
Reduction of ESOP debt - - - - 40 - - -
Purchase of treasury shares - (108,964) - - - - - (5)
Reissuance of treasury shares - 381,387 - 3 - - - 12
- ------------------------------------------------------- -------------------------------------------------------------------------
BALANCE AT
DECEMBER 31, 1994 712,487,068 (60,736,435) $1,069 $1,858 $(900) $175 $14,457 $(2,063)
Net income - - - - - - 930 -
Cash dividends -
$1.925 per share - - - - - - (1,255) -
Tax benefit from
dividends paid on
unallocated ESOP shares - - - - - - 14 -
Market value adjustments
on investments - - - - - 23 - -
Foreign currency
translation adjustment - - - - - (28) - -
Pension Plan
minimum liability - - - - - 4 - -
Reduction of ESOP debt - - - - 50 - - -
Purchase of treasury shares - (83,028) - - - - - (4)
Reissuance of treasury shares - 659,406 - 5 - - - 20
- ------------------------------------------------------- -------------------------------------------------------------------------
BALANCE AT
DECEMBER 31, 1995 712,487,068 (60,160,057) $1,069 $1,863 $(850) $174 $14,146 $(2,047)
======================================================= =========================================================================
See accompanying notes to consolidated financial statements.
FS-15
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Millions of dollars
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Chevron Corporation is an
international company that, through its subsidiaries and affiliates, engages in
fully integrated petroleum operations, chemical operations and coal mining
in the United States and approximately 95 other countries. Petroleum operations
consist of exploring for, developing and producing crude oil and natural gas;
transporting crude oil, natural gas and products by pipelines, marine vessels
and motor equipment; refining crude oil into finished petroleum products; and
marketing crude oil, natural gas and refined petroleum products. Chemicals
operations include the manufacture and marketing of a wide range of chemicals
for industrial uses.
In preparing its consolidated financial statements, the company follows
accounting policies that are in accordance with generally accepted accounting
principles in the United States. This requires the use of estimates and
assumptions that affect the assets and liabilities and the revenues and expenses
reported in the financial statements, as well as amounts included in the notes
thereto, including discussion and disclosure of contingent liabilities. While
the company uses its best estimates and judgments, actual results could differ
from these estimates as future confirming events occur. The company believes
that the effect of any such changes in the near term would not have a material
effect on the financial statements.
The nature of the company's operations and the many countries in which it
operates subject it to changing economic, regulatory and political conditions.
Also, the company imports crude oil for its U.S. refining operations. The
company does not believe it is vulnerable to the risk of a near-term severe
impact as a result of any concentration of its activities.
SUBSIDIARY AND AFFILIATED COMPANIES The consolidated financial statements
include the accounts of subsidiary companies more than 50 percent owned.
Investments in and advances to affiliates in which the company has a
substantial ownership interest of approximately 20 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.
DERIVATIVES Gains and losses on hedges of existing assets or liabilities are
included in the carrying amounts of those assets or liabilities and are
ultimately recognized in income as part of those carrying amounts. Gains and
losses related to qualifying hedges of firm commitments or anticipated
transactions also are deferred and are recognized in income or as adjustments
of carrying amounts when the underlying hedged transaction occurs. If,
subsequent to being hedged, underlying transactions are no longer likely to
occur, the related derivatives gains and losses are recognized currently in
income. Gains and losses on derivatives contracts that do not qualify as
hedges are recognized currently in "Other income."
SHORT-TERM INVESTMENTS All short-term investments are classified as available
for sale and are in highly liquid debt securities. Those investments that are
part of the company's cash management portfolio with original maturities of
three months or less are reported as cash equivalents. The balance of the
short-term investments is reported as marketable securities.
INVENTORIES Crude oil, petroleum products and chemicals are stated at cost,
using a Last-In, First-Out (LIFO) method. In the aggregate, these costs are
below market. Materials, supplies and other inventories generally are stated
at average cost.
PROPERTIES, PLANT AND EQUIPMENT All costs for development wells, related
plant and equipment (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.
Beginning in 1995, long-lived assets, including proved oil and gas properties,
are assessed for possible impairment in accordance with the provisions of SFAS
121. Under this standard, the occurrence of certain events may trigger a review
of affected assets for possible impairment. For proved oil and gas properties,
the company would typically perform the review on an individual field basis. An
impairment is deemed to exist if the sum of undiscounted before-tax expected
future cash flows for the asset are less than the asset's carrying value. If an
impairment is indicated, the amount of the impairment is measured as the
difference between the asset's fair market value and its net book value. Where a
market value is not available, it is approximated by the company's best estimate
of the sum of discounted future before-tax cash flows. Impairment amounts are
recorded as incremental depreciation expense in the period in which the specific
event occurred.
Prior to the adoption of SFAS 121, proved oil and gas properties were 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 existed if the aggregate net
book carrying value of these properties, net of applicable deferred income
taxes, exceeded 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 were 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 were 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
FS-16
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES - Continued
method by individual fields as the proved developed reserves are produced.
Depletion expenses for capitalized costs of proved mineral interests are
recognized using the unit-of-production method by individual fields as the
related proved reserves are produced. Periodic valuation provisions for
impairment of capitalized costs of unproved mineral interests are expensed.
Depreciation and depletion expenses for coal are determined using the unit-of-
production method as the proved reserves are produced. The capitalized costs of
all other plant and equipment are depreciated or amortized over estimated useful
lives. In general, the declining-balance method is used to depreciate plant and
equipment in the United States; the straight-line method generally is used to
depreciate international plant and equipment and to amortize all capitalized
leased assets.
Gains or losses are not recognized for normal retirements of properties, plant
and equipment subject to composite group amortization or depreciation. Gains or
losses from abnormal retirements or sales are included in income.
Expenditures for maintenance, repairs and minor renewals to maintain facilities
in operating condition are expensed. Major replacements and renewals are
capitalized.
ENVIRONMENTAL EXPENDITURES Environmental expenditures that relate to current
ongoing operations or to conditions caused by past operations are expensed.
Expenditures that create future benefits or contribute to future revenue
generation are capitalized.
Liabilities related to future remediation costs are recorded when environmental
assessments and/or cleanups are probable, and the costs can be reasonably
estimated. Other than for assessments, the timing and magnitude of these
accruals are generally based on the company's commitment to a formal plan of
action, such as an approved remediation plan or the sale or disposal of an
asset. For the company's domestic marketing facilities, the accrual is based on
the probability that a future remediation commitment will be required. For oil
and gas and coal producing properties, a provision is made through depreciation
expense for anticipated abandonment and restoration costs at the end of the
property's useful life.
For Superfund sites, the company records a liability for its share of costs when
it has been named as a Potentially Responsible Party (PRP) and when an
assessment or cleanup plan has been developed. This liability includes the
company's own portion of the costs and also the company's portion of amounts for
other PRPs when it is probable that they will not be able to pay their share of
the cleanup obligation.
The company records the gross amount of its liability based on its best estimate
of future costs 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.
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 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.
NOTE 2. 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 (decrease) increase
to net income, after related tax effects:
Year ended December 31
-----------------------------
1995 1994 1993
- -----------------------------------------------------------------------------
Asset write-offs and revaluations
New accounting standard $ (659) $ - $ -
Real estate development assets (168) - -
Adjustment of fixed assets records (94) - -
Refining and marketing assets (38) - (24)
Oil and gas properties - - (31)
Other (4) - (16)
-----------------------------
(963) - (71)
- -----------------------------------------------------------------------------
Environmental remediation provisions (90) (304) (90)
- -----------------------------------------------------------------------------
Restructurings and reorganizations
Workforce reductions (38) - (11)
Caltex (12) - -
U.S. refining and marketing - (39) (543)
Chemicals - (6) -
-----------------------------
(50) (45) (554)
- -----------------------------------------------------------------------------
Prior-year tax adjustments (22) 344 (130)
- -----------------------------------------------------------------------------
Asset dispositions, net
Oil and gas properties 6 - (25)
Lead and zinc property in Ireland - 48 -
Ortho lawn and garden products - - 130
Other 1 - 17
-----------------------------
7 48 122
- -----------------------------------------------------------------------------
LIFO inventory gains (losses) 2 (10) (46)
- -----------------------------------------------------------------------------
Other, net
Caltex gain related to land sale 86 - -
Federal lease cost refund 27 - -
Litigation and regulatory issues (23) (31) (70)
One-time employee bonus - - (60)
Miscellaneous, net (6) 20 16
-----------------------------
84 (11) (114)
- -----------------------------------------------------------------------------
Total special items, after tax $(1,032) $ 22 $(883)
=============================================================================
FS-17
NOTE 2. SPECIAL ITEMS AND OTHER FINANCIAL
INFORMATION - Continued
During 1995, the company and its Caltex affiliate committed to restructurings
and reorganizations of several of their businesses and activities. After-tax
provisions totaling $50 were recorded, substantially all of which related to
employee severance programs for which the number of employees had been
identified and terms and benefits had been communicated. It is expected the
programs will be completed during 1996.
During 1993 and 1994, after-tax provisions totaling $588 were recorded for the
financial effects of the company's decision to sell two refineries. One of the
refineries was sold in 1994, and the sale of the other was completed in early
1995. After completion of the sales, the remaining reserve balance of $224 was
for estimated environmental cleanup obligations retained by the company, in
excess of previously established reserves for these refineries, and was
classified with the company's other environmental reserves.
Other financial information is as follows:
Year ended December 31
-----------------------------
1995 1994 1993
- -----------------------------------------------------------------------------
Total financing interest and debt costs $543 $419 $371
Less: capitalized interest 142 73 54
- -----------------------------------------------------------------------------
Interest and debt expense 401 346 317
Research and development expenses 185 179 206
Currency transaction (losses) gains* $(15) $(64) $ 46
=============================================================================
*INCLUDES $25, $(24) AND $18 IN 1995, 1994 AND 1993, RESPECTIVELY, FOR THE
COMPANY'S SHARE OF AFFILIATES' CURRENCY TRANSACTION EFFECTS.
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
$917, $684 and $671 at December 31, 1995, 1994 and 1993, respectively.
NOTE 3. ADOPTION OF STATEMENT OF FINANCIAL ACCOUNTING STANDARD (SFAS) NO.
121, "ACCOUNTING FOR THE IMPAIRMENT OF LONG-LIVED ASSETS AND FOR LONG-LIVED
ASSETS TO BE DISPOSED OF" Effective October 1, 1995, the company and its
affiliates adopted SFAS 121 issued by the Financial Accounting Standards
Board. The adoption of this standard required non-cash charges to 1995 net
income amounting to $659, or $1.01 per share, after related income tax
benefits of $358, and was mostly related to impairment writedowns of U.S. oil
and gas producing properties.
NOTE 4. INFORMATION RELATING TO THE CONSOLIDATED STATEMENT OF CASH FLOWS The
Consolidated Statement of Cash Flows excludes the following non-cash
transactions:
Capital lease arrangements of $282 and $65 in 1995 and 1994, respectively, were
recorded as additions to "Properties, plant and equipment," "Deferred charges
and other assets," and "Capital lease obligations.
The company's Employee Stock Ownership Plan (ESOP) repaid $50 and $40 of matured
debt guaranteed by Chevron Corporation in 1995 and 1994, respectively. The
company reflected this payment as reductions in "Short-term debt" and in
"Deferred compensation - ESOP."
In 1993, the company acquired a 50 percent interest in the Tengizchevroil joint
venture (TCO) in the Republic of Kazakstan 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 $461 and $466 at year-end 1995 and 1994,
respectively, and is recorded in "Accrued liabilities" and "Deferred credits and
other non-current obligations" in the Consolidated Balance Sheet. 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 refinanced an aggregate amount of $334 in tax-exempt long-term debt
and capital lease obligations in 1993. These refinancings are not reflected in
the Consolidated Statement of Cash Flows.
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 assets, liabilities and stockholders'
equity resulting from the accounting for the company's ESOP, minimum pension
liability, and market value adjustments on investments. 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
-----------------------------
1995 1994 1993
- -----------------------------------------------------------------------------
Additions to properties plant and equipment* $3,611 $3,112 $3,214
Additions to investments 44 284 179
Payments for other (liabilities) and assets, net (126) 9 (70)
- -----------------------------------------------------------------------------
Capital expenditures 3,529 3,405 3,323
Expensed exploration expenditures 354 326 330
Payments of long-term debt
and other financing obligations 5 242 86
- -----------------------------------------------------------------------------
Capital and exploratory expenditures,
excluding equity companies $3,888 $3,973 $3,739
=============================================================================
*EXCLUDES NON-CASH CAPITAL LEASE ADDITIONS OF $282 AND $65 IN 1995 AND 1994,
RESPECTIVELY.
NOTE 5. STOCKHOLDERS' EQUITY Retained earnings at December 31, 1995 and 1994,
include $2,363 and $2,265, respectively, 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
FS-18
NOTE 5. STOCKHOLDERS' EQUITY - Continued
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
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. Twenty 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 1995 made the Rights exercisable.
NOTE 6. FINANCIAL AND DERIVATIVE INSTRUMENTS
OFF-BALANCE-SHEET RISK The company utilizes a variety of derivative instruments,
both financial and commodity based, as hedges to manage a small portion of its
exposure to price volatility stemming from its integrated petroleum activities.
Relatively straightforward and involving little complexity, these instruments
consist mainly of crude oil and natural gas futures contracts traded on the New
York Mercantile Exchange and the International Petroleum Exchange, and natural
gas swap contracts, entered into principally with major financial institutions.
The futures contracts hedge anticipated crude oil and natural gas purchases and
sales, generally forecasted to occur within a 60-day period. Natural gas swaps
are primarily used to hedge firmly committed sales, and the terms of the swap
contracts held have an average maturity of 20 months. Gains and losses on these
derivative instruments offset and are recognized concurrently with gains and
losses from the underlying commodities. In addition, the company in 1995 entered
into a managed program utilizing natural gas contracts to take advantage of
perceived opportunities for favorable price movements in this commodity. The
results of this program are reflected currently in income and were not material
in 1995.
The company enters into forward exchange contracts, generally with terms of 90
days or less, as a hedge against some of its foreign currency exposures,
primarily anticipated purchase transactions forecasted to occur within 90 days.
The company enters into interest rate swaps as part of its overall strategy to
manage the interest rate risk on its debt. Under the terms of the swaps, net
cash settlements, based on the difference between fixed-rate and floating-rate
interest amounts calculated by reference to agreed notional principal amounts,
are made either semiannually or annually, and are recorded monthly as "Interest
and debt expense." At December 31, 1995, the seven contracts have remaining
terms of between one and ten years.
CONCENTRATIONS OF CREDIT RISK The company's financial instruments that are
exposed to concentrations of credit risk consist primarily of its cash
equivalents, marketable securities, derivative financial instruments and
trade receivables.
The company's short-term investments are placed with various foreign governments
and a wide array of financial institutions with high credit ratings. This
diversified investment policy limits the company's exposure both to credit risk
and to concentration of credit risk. Similar standards of diversity and
creditworthiness are applied to the company's counterparties in derivative
instruments.
The trade receivable balances, reflecting the company's diversified sources of
revenue, are dispersed among the company's broad customer base worldwide. As a
consequence, concentrations of credit risk are limited. The company routinely
assesses the financial strength of its customers. Letters of credit are the
principal security obtained to support lines of credit or negotiated contracts
when the financial strength of a customer is not considered sufficient.
FAIR VALUE Fair values are derived either from quoted market prices where
available or, in their absence, the present value of the expected cash flows.
The fair values reflect the cash that would have been received or paid if the
instruments were settled at year-end. At December 31, 1995 and 1994, the fair
values of the financial and derivative instruments were as follows:
Long-term debt of $2,333 and $2,155 had estimated fair values of $2,492 and
$2,127.
The notional principal amounts of the interest rate swaps totaled $1,223 and
$850, with approximate fair values totaling $(26) and $33. The notional amounts
of these and other derivative instruments do not represent assets or liabilities
of the company but, rather, are the basis for the settlements under the contract
terms.
The company holds cash equivalents and U.S. dollar marketable securities in
domestic and offshore portfolios. Eurodollar bonds and floating-rate notes are
the primary instruments held. Cash equivalents and marketable securities had
fair values of $1,219 and $1,178. Of these balances, $446 and $285 classified as
cash equivalents had average maturities under 90 days, while the remainder,
classified as marketable securities, had average maturities of one year and four
years.
For other derivatives the contract or notional values for 1995 and 1994 were as
follows: Crude oil and natural gas futures had contract values of $57 and $68.
Forward exchange contracts had contract values of $102 and $60. The fair values
for these derivative instruments approximated their contract values. Gas swap
contracts, based on notional gas volumes of approximately 180 and 149 billion
cubic feet, had negative fair values totaling $(33) and $(38). Deferred gains
and losses that have been accrued on the Consolidated Balance Sheet are not
material.
NOTE 7. SUMMARIZED FINANCIAL DATA - CHEVRON U.S.A. INC. At December 31, 1995,
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
FS-19
NOTE 7. SUMMARIZED FINANCIAL DATA - CHEVRON U.S.A.
INC. - Continued
operations are conducted by three divisions: Chevron U.S.A. Production Company,
Chevron Products Company (formerly 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
-----------------------------
1995* 1994 1993
- -----------------------------------------------------------------------------
Sales and other operating revenues $24,392 $25,833 $28,092
Total costs and other deductions 25,177 25,367 27,588
Net (loss) income (384) 501 325
=============================================================================
*1995 NET INCOME INCLUDES $(490) FOR THE COMPANY'S ADOPTION OF SFAS 121.
At December 31
------------------
1995 1994
- -----------------------------------------------------------------------------
Current assets $ 3,426 $ 3,341
Other assets 13,666 14,136
Current liabilities 5,800 6,347
Other liabilities 5,357 5,599
Net equity 5,935 5,531
=============================================================================
The company announced in January 1996 that it had entered into exclusive
negotiations with NGC Corporation to merge certain gas gathering, processing and
marketing operations of Chevron U.S.A. Production Company's Natural Gas Business
Unit and Warren Petroleum Company with those of NGC Corporation. The merger is
expected to be completed in the second quarter of 1996, following which the
company will have an approximate 28 percent ownership interest in the resulting
company.
NOTE 8. LITIGATION The company is a defendant in numerous lawsuits, including
an action brought against the company by OXY U.S.A. in an Oklahoma state court.
Plaintiffs may seek to recover large and sometimes unspecified amounts, and
some matters may remain unresolved for several years. It is not practical to
estimate a range of possible loss for the company's litigation matters, and
losses could be material with respect to earnings in any given period. However,
management is of the opinion that resolution of the lawsuits will not result in
any significant liability to the company in relation to its consolidated
financial position or liquidity.
OXY U.S.A. has brought a lawsuit in its capacity as successor in interest to
Cities Services Company, which involves claims for damages resulting from the
allegedly improper termination of a tender offer to purchase Cities' stock in
1982 made by Gulf Oil Corporation, acquired by Chevron in 1984. A trial with
respect to the claims is expected to begin in 1996.
NOTE 9. SUMMARIZED FINANCIAL DATA - CHEVRON TRANSPORT CORPORATION Chevron
Transport Corporation (CTC), a Liberian corporation, is an indirect, wholly
owned subsidiary of Chevron Corporation. CTC is the principal operator of
Chevron's international tanker fleet and is engaged in the marine
transportation of oil and refined petroleum products. Most of CTC's shipping
revenue is derived by providing transportation services to other Chevron
companies. Chevron Corporation has guaranteed this subsidiary's obligations
in connection with certain debt securities where CTC is deemed to be an
issuer. In accordance with the Securities and Exchange Commission's
disclosure requirements, summarized financial information for CTC and its
consolidated subsidiaries is presented below. This information was derived
from the financial statements prepared on a stand-alone basis in conformity
with generally accepted accounting principles.
Separate financial statements and other disclosures with respect to CTC are
omitted as such separate financial statements and other disclosures are not
material to investors in the debt securities deemed issued by CTC. There were no
restrictions on CTC's ability to pay dividends or make loans or advances at
December 31, 1995.
Year ended December 31
-----------------------------
1995 1994 1993*
- -----------------------------------------------------------------------------
Sales and other operating revenues $462 $440 $543
Total costs and other deductions 477 504 553
Loss before cumulative effect
of changes in accounting principles (23) (58) (3)
Cumulative effect
of changes in accounting principles - - (15)
Net loss (23) (58) (18)
=============================================================================
*1993 INCLUDES THE CUMULATIVE EFFECT OF CTC'S ADOPTION OF STATEMENT OF
FINANCIAL ACCOUNTING STANDARDS NO. 109, "ACCOUNTING FOR INCOME TAXES," WHICH
FOR PURPOSES OF THE CHEVRON CORPORATION CONSOLIDATED FINANCIAL STATEMENTS WAS
ADOPTED IN 1992.
At December 31
-------------------
1995 1994
- -----------------------------------------------------------------------------
Current assets $ 37 $ 75
Other assets 1,561 851
Current liabilities 459 404
Other liabilities 431 208
Net equity 708 314
=============================================================================
NOTE 10. 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:
At December 31
-----------------------------
1995 1994 1993
- -----------------------------------------------------------------------------
IDENTIFIABLE ASSETS
United States
Petroleum $14,521 $15,540 $16,443
Chemicals 2,115 1,992 2,045
Coal and Other Minerals 503 592 744
-----------------------------
Total United States 17,139 18,124 19,232
-----------------------------
International
Petroleum 13,392 12,493 12,202
Chemicals 409 411 412
Coal and Other Minerals 28 45 13
-----------------------------
Total International 13,829 12,949 12,627
- -----------------------------------------------------------------------------
TOTAL IDENTIFIABLE ASSETS 30,968 31,073 31,859
Corporate and Other 3,362 3,334 2,877
- -----------------------------------------------------------------------------
TOTAL ASSETS $34,330 $34,407 $34,736
=============================================================================
FS-20
NOTE 10. GEOGRAPHIC AND SEGMENT DATA - Continued
Year ended December 31
-----------------------------
1995 1994 1993
- -----------------------------------------------------------------------------
OPERATING INCOME
United States
Petroleum $ (64) $ 831 $ 692
Chemicals 689 241 162
Coal and Other Minerals (42) 60 59
-----------------------------
Total United States 583 1,132 913
-----------------------------
International
Petroleum 2,074 1,672 1,772
Chemicals 96 81 63
Coal and Other Minerals 3 79 (3)
-----------------------------
Total International 2,173 1,832 1,832
- -----------------------------------------------------------------------------
TOTAL OPERATING INCOME 2,756 2,964 2,745
Corporate and Other (967) (161) (319)
Income Tax Expense (859) (1,110) (1,161)
- -----------------------------------------------------------------------------
NET INCOME $ 930 $ 1,693 $ 1,265
=============================================================================
Operating income in 1995 included asset impairment writedowns of $1,017 in
connection with the adoption of SFAS 121, as follows: U.S. Petroleum - $754;
U.S. Chemicals - $20; U.S. Coal and Other Minerals - $97; International
Petroleum - $127; and Corporate and Other - $19.
Beginning January 1, 1994, the company no longer distributes certain corporate
expenses to its business segments. Prior to 1994, these expenses were allocated
on the basis of each segment's identifiable assets (including an allocation to
"Corporate and Other"). Starting in 1994, segments are billed for direct
corporate services; unbilled corporate expenses are included in "Corporate and
Other." The company believes this better reflects the current organizational and
management structure of its business units and corporate departments.
As a result of the change, "Corporate and Other" in 1995 and 1994 included $277
and $232, respectively, of before-tax expenses that, under the previous method,
would have reduced segment operating income. There was no change in the net
income of the company. Also in connection with the change, the company no longer
allocates certain corporate identifiable assets to the business segments. At
December 31, 1995 and 1994, "Corporate and Other" included $1,349 and $1,259 of
identifiable assets that in previous years would have been included in the
identifiable assets of the business segments.
These changes resulted in an increase to 1995 and 1994 U.S. Petroleum operating
income of $121 and $101, and for international petroleum $132 and $111,
respectively. Identifiable assets at December 31, 1995 and 1994, for U.S.
Petroleum were reduced $632 and $630, and for International Petroleum, $583 and
$506, respectively. The effect of these changes on 1995 and 1994 operating
income and year-end 1995 and 1994 identifiable assets of the company's other
segments and geographic areas was not material.
Identifiable assets for the business segments include all assets associated with
operations in the indicated geographic areas, including investments in
affiliates.
Year ended December 31
-----------------------------
1995 1994 1993
- -----------------------------------------------------------------------------
SALES AND OTHER OPERATING REVENUES
United States
Petroleum-Refined products $10,677 $11,690 $13,169
-Crude oil 3,850 3,466 4,086
-Natural gas 1,604 1,755 1,776
-Natural gas liquids 1,130 1,072 1,098
-Other petroleum revenues 717 637 682
-Excise taxes 2,999 2,977 2,554
-Intersegment 676 977 924
-----------------------------
Total Petroleum 21,653 22,574 24,289
-----------------------------
Chemicals-Products 3,157 2,528 2,211
-Intersegment 175 273 248
-----------------------------
Total Chemicals 3,332 2,801 2,459
-----------------------------
Coal and Other Minerals 350 415 447
-----------------------------
Total United States 25,335 25,790 27,195
- -----------------------------------------------------------------------------
International
Petroleum-Refined products 2,794 2,638 2,920
-Crude oil 5,526 4,783 4,415
-Natural gas 415 383 380
-Natural gas liquids 155 108 137
-Other petroleum revenues 429 307 285
-Excise taxes 1,977 1,797 1,499
-Intersegment - (2) 1
-----------------------------
Total Petroleum 11,296 10,014 9,637
-----------------------------
Chemicals-Products 600 537 497
-Excise taxes 12 16 15
-Intersegment 9 8 6
-----------------------------
Total Chemicals 621 561 518
-----------------------------
Coal and Other Minerals 7 1 -
-----------------------------
Total International 11,924 10,576 10,155
- -----------------------------------------------------------------------------
Intersegment sales elimination (860) (1,256) (1,179)
- -----------------------------------------------------------------------------
Corporate and Other (89) 20 20
- -----------------------------------------------------------------------------
TOTAL SALES AND OTHER OPERATING REVENUES $36,310 $35,130 $36,191
=============================================================================
Memo: Intergeographic Sales
United States $ 565 $ 512 $ 266
International 1,077 1,803 4,418
=============================================================================
Sales and other operating revenues for the petroleum segments are derived from
the production and sale of crude oil, 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. During 1994, the company essentially completed its
withdrawal from non-coal minerals activities. The company's real estate and
insurance operations and worldwide cash management and financing activities are
in "Corporate and Other."
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.
FS-21
NOTE 10. GEOGRAPHIC AND SEGMENT DATA - Continued
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 the Caltex and Tengizchevroil
affiliates is presented in Note 12. Other affiliates are either not material or
not vertically integrated with a segment's operations.
NOTE 11. 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
------------------
1995 1994
- -----------------------------------------------------------------------------
Petroleum
Exploration and Production $ 46 $ 45
Refining, Marketing and Transportation 833 618
- -----------------------------------------------------------------------------
879 663
Less: accumulated amortization 403 398
- -----------------------------------------------------------------------------
Net capitalized leased assets $476 $265
=============================================================================
At December 31, 1995, the future minimum lease payments under operating and
capital leases are as follows:
At December 31
----------------------
Operating Capital
Year Leases Leases
- -----------------------------------------------------------------------------
1996 $142 $ 90
1997 130 86
1998 106 84
1999 96 75
2000 93 65
Thereafter 131 885
- -----------------------------------------------------------------------------
Total $698 1,285
- -----------------------------------------------------------------
Less: amounts representing interest and executory costs (582)
- -----------------------------------------------------------------------------
Net present values 703
Less: capital lease obligations included in short-term debt (315)
- -----------------------------------------------------------------------------
Long-term capital lease obligations $388
=============================================================================
Future sublease rental income $ 37 $ -
=============================================================================
Rental expenses incurred for operating leases during 1995, 1994 and 1993 were as
follows:
Year ended December 31
-----------------------------
1995 1994 1993
- -----------------------------------------------------------------------------
Minimum rentals $403 $410 $452
Contingent rentals 9 7 9
- -----------------------------------------------------------------------------
Total 412 417 461
Less: sublease rental income 14 14 15
- -----------------------------------------------------------------------------
Net rental expense $398 $403 $446
=============================================================================
Contingent rentals are based on factors other than the passage of time,
principally sales volumes at leased service stations. Certain leases include
escalation clauses for adjusting rentals to reflect changes in price indices,
renewal options ranging from one to 25 years and/or options to purchase the
leased property during or at the end of the initial lease period for the fair
market value at that time.
NOTE 12. INVESTMENTS AND ADVANCES 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
------------------
1995 1994
- -----------------------------------------------------------------------------
Equity method affiliates
Caltex Group
Exploration and Production $ 446 $ 496
Refining, Marketing and Transportation 2,032 1,866
- -----------------------------------------------------------------------------
Total Caltex Group 2,478 2,362
Tengizchevroil 1,153 1,153
Other affiliates 293 346
- -----------------------------------------------------------------------------
3,924 3,861
Other, at or below cost 163 130
- -----------------------------------------------------------------------------
Total investments and advances $4,087 $3,991
=============================================================================
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 subsidiary, 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.
Tengizchevroil (TCO) is a 50-percent owned joint venture formed in 1993 with the
Republic of Kazakstan to develop the Tengiz and Korolev oil fields over a 40
year period. The investment in TCO at December 31, 1995 and 1994, included a
deferred payment portion of $461 and $466, respectively, $420 of which is
payable to the Republic of Kazakstan upon the attainment of a dedicated export
system with the capability of the greater of 260,000 barrels of oil per day or
TCO's production capacity. This portion of the investment was recorded upon
formation of the venture as the company believed at the time, and continues to
believe, that its payment is beyond a reasonable doubt given the original intent
and continuing commitment of both parties to realizing the full potential of the
venture over its 40-year life.
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 1995, 1994 and 1993 are as follows:
Year ended December 31
-------------------------------------------------
Equity in Earnings Dividends
---------------------- ----------------------
1995 1994 1993 1995 1994 1993
- -------------------------------------------------------------------------------
Caltex Group
Exploration and Production $156 $140 $134
Refining, Marketing
and Transportation 294 210 227
- ----------------------------------------------------
Total Caltex Group 450 350 361 $305 $239 $172
Tengizchevroil 1 (10) (1) - - -
Other affiliates 102 100 80 116 146 95
- -------------------------------------------------------------------------------
Total $553 $440 $440 $421 $385 $267
===============================================================================
FS-22
NOTE 12. 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
-----------------------------
1995 1994 1993
- -----------------------------------------------------------------------------
Sales to Caltex Group $1,330 $1,166 $1,739
Sales to other affiliates 10 7 5
- -----------------------------------------------------------------------------
Total sales to affiliates $1,340 $1,173 $1,744
=============================================================================
Purchases from Caltex Group $ 934 $ 800 $ 842
Purchases from other affiliates 40 52 101
- -----------------------------------------------------------------------------
Total purchases from affiliates $ 974 $ 852 $ 943
=============================================================================
Accounts and notes receivable in the consolidated balance sheet include $144 and
$135 at December 31, 1995 and 1994, respectively, of amounts due from affiliated
companies. Accounts payable include $37 and $46 at December 31, 1995 and 1994,
respectively, of amounts due to affiliated companies.
The following tables summarize the combined financial information for the Caltex
Group and all of the other equity method companies together with Chevron's
share. Amounts shown for the affiliates are 100 percent.
Caltex Group Other Affiliates Chevron's Share
---------------------------- ---------------------------- ----------------------------
Year ended December 31 1995 1994 1993 1995 1994 1993 1995 1994 1993
- ---------------------------------------------------------------------------------------------------------------------------------
Sales and other operating revenues $15,067 $14,751 $15,409 $2,594 $2,237 $1,972 $8,549 $8,176 $8,229
Total costs and other deductions 14,130 13,860 14,392 2,194 1,815 1,542 7,741 7,500 7,633
Net income 899 689 720 315 357 374 553 440 440
=================================================================================================================================
Caltex Group Other Affiliates Chevron's Share
---------------------------- ---------------------------- ----------------------------
At December 31 1995 1994 1993 1995 1994 1993 1995 1994 1993
- ---------------------------------------------------------------------------------------------------------------------------------
Current assets $ 2,323 $ 2,421 $ 2,123 $ 877 $ 913 $ 766 $1,527 $1,446 $1,256
Other assets 7,794 7,389 6,266 3,888 4,216 3,871 5,414 5,396 4,731
Current liabilities 3,223 3,072 2,411 413 543 471 1,863 1,617 1,332
Other liabilities 1,935 2,005 1,683 3,341 3,225 2,620 1,154 1,364 1,155
Net equity 4,959 4,733 4,295 1,011 1,361 1,546 3,924 3,861 3,500
=================================================================================================================================
NOTE 13. PROPERTIES, PLANT AND EQUIPMENT
At December 31 Year ended December 31
----------------------------------------------------- -----------------------------------------------------
Gross Investment at Cost Net Investment Additions at Cost(1) Depreciation Expense
------------------------- -------------------------- ------------------------- --------------------------
1995 1994 1993 1995 1994 1993 1995 1994 1993 1995 1994 1993
- -----------------------------------------------------------------------------------------------------------------------------------
UNITED STATES
Petroleum
Exploration and
Production $18,209 $17,980 $17,608 $ 5,010 $ 5,900 $ 6,189 $ 776 $ 675 $ 663 $1,577 $ 983 $1,064
Refining and
Marketing 11,136 11,442 10,693 6,520 6,524 6,187 887 899 960 564 460 460
Chemicals 2,075 1,915 1,899 1,233 1,150 1,225 168 89 174 162 131 124
Coal and Other
Minerals 857 869 848 359 461 488 33 30 32 135 54 54
- -----------------------------------------------------------------------------------------------------------------------------------
Total United States 32,277 32,206 31,048 13,122 14,035 14,089 1,864 1,693 1,829 2,438 1,628 1,702
- -----------------------------------------------------------------------------------------------------------------------------------
INTERNATIONAL
Petroleum
Exploration and
Production 10,951 9,661 8,729 5,463 4,800 4,353 1,421 1,051 1,014 712 578 519
Refining and
Marketing 2,459 2,482 2,385 1,674 1,743 1,686 335 218 219 116 114 106
Chemicals 354 330 313 146 143 148 26 25 24 24 27 25
Coal and Other
Minerals 22 21 12 19 19 10 - 12 3 1 - -
- -----------------------------------------------------------------------------------------------------------------------------------
Total International 13,786 12,494 11,439 7,302 6,705 6,197 1,782 1,306 1,260 853 719 650
- -----------------------------------------------------------------------------------------------------------------------------------
Corporate and Other(2) 1,968 2,110 2,320 1,272 1,433 1,579 203 125 96 90 84 100
- -----------------------------------------------------------------------------------------------------------------------------------
TOTAL $48,031 $46,810 $44,807 $21,696 $22,173 $21,865 $3,849 $3,124 $3,185 $3,381 $2,431 $2,452
===================================================================================================================================
(1)NET OF DRY HOLE EXPENSE RELATED TO PRIOR YEARS' EXPENDITURES OF $19, $53 AND $29 IN 1995, 1994 AND 1993, RESPECTIVELY.
(2)INCLUDES PRIMARILY REAL ESTATE AND MANAGEMENT INFORMATION SYSTEMS.
Expenses for maintenance and repairs were $833, $928 and $875 in 1995, 1994 and
1993, respectively.
FS-23
NOTE 14. TAXES
Year ended December 31
-----------------------------
1995 1994 1993
- -----------------------------------------------------------------------------
Taxes other than on income
United States
Excise taxes on products and merchandise $2,999 $2,978 $2,554
Property and other miscellaneous taxes 341 395 401
Payroll taxes 127 112 122
Taxes on production 105 102 135
- -----------------------------------------------------------------------------
Total United States 3,572 3,587 3,212
- -----------------------------------------------------------------------------
International
Excise taxes on products and merchandise 1,989 1,812 1,514
Property and other miscellaneous taxes 146 127 134
Payroll taxes 30 19 19
Taxes on production 11 14 7
- -----------------------------------------------------------------------------
Total International 2,176 1,972 1,674
- -----------------------------------------------------------------------------
Total taxes other than on income $5,748 $5,559 $4,886
=============================================================================
Year ended December 31
-----------------------------
1995 1994 1993
- -----------------------------------------------------------------------------
Taxes on income
U.S. federal
Current $ 152 $ 175 $ 394
Deferred (289) 43 (241)
Deferred - Adjustment for enacted
changes in tax laws/rates - - 54
State and local 29 10 63
- -----------------------------------------------------------------------------
Total United States (108) 228 270
- -----------------------------------------------------------------------------
International
Current 937 815 864
Deferred 14 67 48
Deferred - Adjustment for enacted
changes in tax laws/rates 16 - (21)
- -----------------------------------------------------------------------------
Total International 967 882 891
- -----------------------------------------------------------------------------
Total taxes on income $ 859 $1,110 $1,161
=============================================================================
U.S. federal income tax expense was reduced by $68, $60 and $57 in 1995, 1994
and 1993, respectively, for low-income housing and other business tax credits.
In 1995, before-tax (loss) income for U.S. operations was $(331) compared with
$1,194 in 1994 and $687 in 1993. Before-tax income for international operations
was $2,120, $1,609 and $1,739 in 1995, 1994 and 1993, respectively.
The deferred income tax provisions included benefits (costs) of $75, $(475) and
$98 related to properties, plant and equipment in 1995, 1994 and 1993,
respectively. Benefits were recorded in 1995 of $358 related to the impairment
of long-lived assets and $91 related to the provision for the expected loss from
exiting the real estate development business. U.S. benefits were recorded in
1993 related to the U.S. refining and marketing restructuring provision.
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
-----------------------------
1995 1994 1993
- -----------------------------------------------------------------------------
Statutory U.S. federal income tax rate 35.0% 35.0% 35.0%
Effects of income taxes on international
operations in excess of taxes at the
U.S. statutory rate 26.2 18.5 15.6
Effects of asset dispositions (0.1) - (0.6)
State and local taxes on income,
net of U.S. federal income tax benefit 0.9 0.2 2.2
Prior-year tax adjustments 0.3 (4.4) 3.0
Effects of enacted changes in tax
laws/rates on deferred tax liabilities 0.9 - 1.3
Tax credits (3.8) (2.1) (2.4)
All others (2.6) (3.2) (0.9)
- -----------------------------------------------------------------------------
Consolidated companies 56.8 44.0 53.2
Effect of recording equity in income
of certain affiliated companies
on an after-tax basis (8.8) (4.4) (5.3)
- -----------------------------------------------------------------------------
Effective tax rate 48.0% 39.6% 47.9%
=============================================================================
The company records its deferred taxes on a tax jurisdiction basis and
classifies those net amounts as current or non-current based on the balance
sheet classification of the related assets or liabilities.
At December 31, 1995 and 1994, deferred taxes were classified in the
Consolidated Balance Sheet, as follows:
At December 31
------------------
1995 1994
- -----------------------------------------------------------------------------
Prepaid expenses and other current assets $ (139) $ (112)
Deferred charges and other assets (138) (148)
Federal and other taxes on income 11 18
Non-current deferred income taxes 2,433 2,674
- -----------------------------------------------------------------------------
Total deferred income taxes, net $2,167 $2,432
=============================================================================
The reported deferred tax balances are composed of the following deferred tax
liabilities (assets):
At December 31
------------------
1995 1994
- -----------------------------------------------------------------------------
Properties, plant and equipment $ 4,442 $ 4,451
Inventory 182 240
Miscellaneous 277 254
- -----------------------------------------------------------------------------
Deferred tax liabilities 4,901 4,945
- -----------------------------------------------------------------------------
Abandonment/environmental reserves (1,169) (1,066)
Employee benefits (567) (564)
AMT/other tax credits (816) (711)
Other accrued liabilities (240) (299)
Miscellaneous (649) (523)
- -----------------------------------------------------------------------------
Deferred tax assets (3,441) (3,163)
- -----------------------------------------------------------------------------
Deferred tax assets valuation allowance 707 650
- -----------------------------------------------------------------------------
Total deferred taxes, net $ 2,167 $ 2,432
=============================================================================
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
FS-24
NOTE 14. TAXES - Continued
approximately $3,712 at December 31, 1995. 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 $207 would be payable upon remittance of
these earnings.
NOTE 15. SHORT-TERM DEBT
At December 31
------------------
1995 1994
- -----------------------------------------------------------------------------
Commercial paper(1) $4,808 $5,036
Current maturities of long-term debt 143 134
Current maturities of long-term capital leases 42 33
Redeemable long-term obligations
Long-term debt 315 315
Capital leases 273 273
Notes payable 25 23
- -----------------------------------------------------------------------------
Subtotal(2) 5,606 5,814
Reclassified to long-term debt (1,800) (1,800)
- -----------------------------------------------------------------------------
Total short-term debt $3,806 $4,014
=============================================================================
(1)WEIGHTED AVERAGE INTEREST RATES AT DECEMBER 31, 1995 AND 1994, WERE 6.0%
AND 6.0%, RESPECTIVELY, INCLUDING THE EFFECT OF INTEREST RATE SWAPS.
(2)WEIGHTED AVERAGE INTEREST RATES AT DECEMBER 31, 1995 AND 1994, WERE 5.9%
AND 5.9%, RESPECTIVELY, INCLUDING THE EFFECT OF INTEREST RATE SWAPS.
Redeemable long-term obligations consist primarily of tax-exempt variable-rate
put bonds that are included as current liabilities because they become
redeemable at the option of the bondholders during the year following the
balance sheet date.
The company has entered into interest rate swaps on a portion of its short-term
debt. At December 31, 1995 and 1994, the company agreed to swap notional amounts
of $1,050 and $700, respectively, of floating rate debt for fixed rates. The
effect of these swaps on the company's interest expense was not material.
NOTE 16. LONG-TERM DEBT Chevron and one of its wholly owned subsidiaries each
have "shelf" registrations on file with the Securities and Exchange
Commission (SEC) that together would permit the issuance of $1,300 of debt
securities pursuant to Rule 415 of the Securities Act of 1933.
At year-end 1995, the company had $4,425 of committed credit facilities with
banks worldwide, $1,800 of which had termination dates beyond one year. The
facilities support the company's commercial paper borrowings. Interest on any
borrowings under the agreements is based on either the London Interbank Offered
Rate or the Reserve Adjusted Domestic Certificate of Deposit Rate. No amounts
were outstanding under these credit agreements during the year nor at year-end.
At both December 31, 1995 and 1994, the company classified $1,800 of short-term
debt as long-term. Settlement of these obligations is not expected to require
the use of working capital in 1996, as the company has both the intent and
ability to refinance this debt on a long-term basis.
At December 31
------------------
1995 1994
- -----------------------------------------------------------------------------
8.11% amortizing notes due 2004(1) $ 750 $ 750
7.45% notes due 2004 348 348
9.375% sinking-fund debentures due 2016 278 278
5.6% notes due 1998 190 190
9.75% sinking-fund debentures due 2017 180 180
4.625% 200 million Swiss franc issue due 1997(2) 173 152
7.61% notes due 2003 160 -
7.10% serial notes due 1996-1997(1,3) 100 150
6.92% notes due 2005 51 -
Other long-term obligations (7.11%)(3)
(less than $50 individually) 166 183
Other foreign currency obligations (4.6%)(3) 80 58
- -----------------------------------------------------------------------------
Total including debt due within one year 2,476 2,289
Debt due within one year (143) (134)
Reclassified from short-term debt (6.0%)(3) 1,800 1,800
- -----------------------------------------------------------------------------
Total long-term debt $4,133 $3,955
=============================================================================
(1)GUARANTEE OF ESOP DEBT.
(2)AN INTEREST RATE SWAP EFFECTIVELY CHANGED THE FIXED INTEREST RATE TO A
FLOATING RATE, WHICH WAS 2.24% AND 4.25% AT YEAR-END 1995 AND 1994.
(3)WEIGHTED AVERAGE INTEREST RATES AT DECEMBER 31, 1995.
Consolidated long-term debt maturing in each of the five years after December
31, 1995, is as follows: 1996-$143, 1997-$291, 1998-$301, 1999-$124 and 2000-
$121.
NOTE 17. 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.
The net pension (credit) expense for all of the company's pension plans for the
years 1995, 1994 and 1993 consisted of:
1995 1994 1993
- -----------------------------------------------------------------------------
Cost of benefits earned during the year $ 99 $ 97 $ 103
Interest cost on projected benefit obligations 273 263 276
Actual return on plan assets (728) (62) (472)
Net amortization and deferral 342 (294) 101
- -----------------------------------------------------------------------------
Net pension (credit) expense $ (14) $ 4 $ 8
=============================================================================
Settlement gains in 1995 and 1994, related to lump-sum payments, totaled $7 and
$17, respectively. 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.
At December 31, 1995 and 1994, 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:
1995 1994
- -----------------------------------------------------------------------------
Assumed discount rates 7.4% 8.8%
Assumed rates for compensation increases 5.1% 5.1%
Expected return on plan assets 9.1% 10.1%
=============================================================================
FS-25
NOTE. 17. EMPLOYEE BENEFIT PLANS - Continued
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, 1995 and 1994, was as follows:
Plans with
Plans with Assets Accumulated
in Excess of Benefits
Accumulated in Excess of
Benefits Plan Assets
----------------- -----------------
At December 31 1995 1994 1995 1994
- -----------------------------------------------------------------------------
Actuarial present value of:
Vested benefit obligations $(2,961) $(2,596) $(218) $(186)
- -----------------------------------------------------------------------------
Accumulated benefit obligations $(3,085) $(2,680) $(230) $(194)
=============================================================================
Projected benefit obligations $(3,557) $(3,053) $(259) $(222)
Plan assets at fair values 4,020 3,626 13 -
- -----------------------------------------------------------------------------
Plan assets greater (less) than
projected benefit obligations 463 573 (246) (222)
Unrecognized net transition
(assets) liabilities (240) (294) 15 18
Unrecognized net (gains) losses (29) (178) 65 54
Unrecognized prior-service costs 94 113 9 6
Minimum liability adjustment - - (75) (80)
- -----------------------------------------------------------------------------
Net pension cost prepaid (accrued) $ 288 $ 214 $(232) $(224)
=============================================================================
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 $99, $75 and $95 in 1995, 1994 and 1993,
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 28.2 million previously unissued shares of the
company's common stock. The ESOP provides a partial pre-funding of the
company's future commitments to the profit sharing part of the plan, which will
result in annual income tax savings for the company. The ESOP is expected to
satisfy most of the company's obligations to the profit sharing part of the
plan during the next nine years.
As allowed by AICPA Statement of Position (SOP) 93-6, the company has elected to
continue its practices, which are based on SOP 76-3 and subsequent consensuses
of the Emerging Issues Task Force of the Financial Accounting Standards Board.
Accordingly, the debt of the ESOP is recorded as debt, and shares pledged as
collateral are reported as deferred compensation in the Consolidated Balance
Sheet and Statement of Stockholders' Equity. The company reports compensation
expense equal to the ESOP debt principal repayments less dividends received by
the ESOP. Interest incurred on the ESOP debt is recorded as interest expense.
Dividends paid on ESOP shares are reflected as a reduction of retained
earnings. All ESOP shares are considered outstanding for earnings-per-share
computations.
The company recorded expense for the ESOP of $67, $42 and $60 in 1995, 1994 and
1993, respectively, including $68, $71 and $74 of interest expense related to
the ESOP debt. All dividends paid on the shares held by the ESOP are used to
service the ESOP debt. The dividends used were $50, $50 and $47 in 1995, 1994
and 1993, respectively.
The company made contributions to the ESOP of $69, $63 and $57 in 1995, 1994 and
1993, respectively, to satisfy ESOP debt service in excess of dividends received
by the ESOP. The ESOP shares were pledged as collateral for its debt. Shares are
released from a suspense account and allocated to profit sharing accounts of
plan participants, based on the debt service deemed to be paid in the year in
proportion to the total of current year and remaining debt service. Compensation
expense was $(1), $(10) and $(17) in 1995, 1994 and 1993, respectively. The ESOP
shares as of December 31 were as follows:
Thousands 1995 1994
- -----------------------------------------------------------------------------
Allocated shares 7,223 5,969
Unallocated shares 19,490 21,208
- -----------------------------------------------------------------------------
Total ESOP shares 26,713 27,177
=============================================================================
BROAD-BASED EMPLOYEE STOCK OPTIONS In 1996, the company granted to all
eligible employees 150 stock options or equivalents that become exercisable
if, within three years, the price of Chevron stock reaches $75 or the company
has the highest annual total stockholder return of its competitor group for
the years 1994-1998.
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, or beginning with awards deferred in 1996, stock
units or other investment fund alternatives. 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. In addition, in 1996
a portion of the LTIP options granted had terms similar to the broad-based
employee stock options discussed above.
The maximum number of shares of common stock that may be granted each year is
one percent of the total outstanding shares of common stock as of January 1 of
such year. As of December 31, 1995, 7,074,852 shares were under option at
exercise prices ranging from $31.9375 to $48.375 per share. Stock option
transactions for 1995 and 1994 were as follows:
FS-26
NOTE 17. EMPLOYEE BENEFIT PLANS - Continued
At December 31
------------------
Thousands of shares 1995 1994
- -----------------------------------------------------------------------------
Outstanding at January 1 5,845 4,303
Granted 1,806 1,770
Exercised (498) (140)
Forfeited (78) (88)
- -----------------------------------------------------------------------------
Outstanding December 31 7,075 5,845
=============================================================================
Exercisable December 31 5,339 4,152
=============================================================================
Charges to expense for the combined management incentive plans were $45, $31
and $36 in 1995, 1994 and 1993, 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.
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, 1995 At December 31, 1994
--------------------------- ---------------------------
Health Life Total Health Life Total
- -------------------------------------------------------------------------------
Accumulated
postretirement
benefit
obligation
(APBO)
Retirees $ (467) $(328) $ (795) $(480) $(262) $ (742)
Fully eligible
active
participants (144) (81) (225) (120) (57) (177)
Other active
participants (211) (51) (262) (190) (37) (227)
- -------------------------------------------------------------------------------
Total APBO (822) (460) (1,282) (790) (356) (1,146)
Fair value
of plan assets - - - - - -
- -------------------------------------------------------------------------------
APBO (greater)
than plan assets (822) (460) (1,282) (790) (356) (1,146)
Unrecognized
net (gain) loss (179) 25 (154) (195) (66) (261)
- -------------------------------------------------------------------------------
Accrued
postretirement
benefit costs $(1,001) $(435) $(1,436) $(985) $(422) $(1,407)
===============================================================================
The company's net postretirement benefits expense was as follows:
1995 1994 1993
--------------------- --------------------- ---------------------
Health Life Total Health Life Total Health Life Total
- -------------------------------------------------------------------------------
Cost of benefits
earned during
the year $15 $ 3 $ 18 $23 $ 4 $ 27 $23 $ 3 $ 26
Interest cost
on benefit
obligation 67 30 97 71 31 102 76 30 106
Net amortization
of (gain) loss (9) (2) (11) - - - - - -
- -------------------------------------------------------------------------------
Net post-
retirement
benefits
expense $73 $31 $104 $94 $35 $129 $99 $33 $132
===============================================================================
For measurement purposes, separate health care cost-trend rates were utilized
for pre-age 65 and post-age 65 retirees. The 1996 annual rates of change were
assumed to be (3.7) percent and 1.8 percent, respectively, increasing to 8.3
percent and 7.5 percent in 1997 and gradually decreasing thereafter to the
average ultimate rates of 5.6 percent in 2005 for pre-age 65 and 4.5 percent in
2005 for post-age 65. An increase in the assumed health care cost-trend rates of
one percent in each year would increase the aggregate of service and interest
costs for the year 1995 by $13 and would increase the December 31, 1995
accumulated postretirement benefit obligation (APBO) by $113.
At December 31, 1995, 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.
NOTE 18. 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. For federal income tax purposes, all
issues other than the allocation of state income taxes and the creditability
of taxes paid to the government of Indonesia have been resolved through 1987.
A Tax Court decision in 1995 confirmed the validity of tax regulations for
allocating state income taxes. The company currently is working with the
Internal Revenue Service to agree on a methodology that could apply to all
years. The Indonesia issue applies only to years after 1982. While the amounts
under dispute with the IRS are significant, settlement of open tax matters is
not expected to have a material effect on the consolidated net assets or
liquidity 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.
At December 31, 1995, the company and its subsidiaries, as direct or indirect
guarantors, had contingent liabilities of $100 for notes of affiliated companies
and $77 for notes of others.
The company and its subsidiaries have certain contingent liabilities with
respect to long-term unconditional purchase obligations and commitments,
throughput agreements and
FS-27
NOTE 18. OTHER CONTINGENT LIABILITIES AND COMMITMENTS - Continued
take-or-pay agreements, some of which relate to suppliers' financing
arrangements. The aggregate amount of required payments under these various
commitments are: 1996-$177; 1997-$156; 1998-$140; 1999-$118; 2000-$90; 2001 and
after-$509. Total payments under the agreements were $173 in 1995, $154 in 1994
and $142 in 1993.
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 claimed the company overrecouped under the
regulations by $125 during the period in question but is currently requesting
that the DOE's Office of Hearings and Appeals (OHA) amend the amount to $167. If
the amendment is granted, the total claim, including interest through December
1995, amounts to $442. The company asserts that in fact it incurred a loss
through participation in the DOE program. Evidentiary hearings on the no-benefit
argument began in mid-December 1994 and were concluded in March 1995. Oral
arguments were held in August 1995 and the company is awaiting a decision by the
OHA.
The company is subject to loss contingencies pursuant to environmental laws and
regulations that in the future may require the company to take action to correct
or ameliorate the effects on the environment of prior disposal or release of
chemical or petroleum substances by the company or other parties. Such
contingencies may exist for various sites including, but not limited to:
Superfund sites and refineries, oil fields, service stations, terminals and land
development areas, whether operating, closed or sold. The amount of such future
cost is indeterminable due to such factors as the unknown magnitude of possible
contamination, the unknown timing and extent of the corrective actions that may
be required, the determination of the company's liability in proportion to other
responsible parties and the extent to which such costs are recoverable from
third parties. While the company has provided for known environmental
obligations that are probable and reasonably estimable, the amount of future
costs may be material to results of operations in the period in which they are
recognized. The company does not expect these costs to have a material effect on
its consolidated financial position or liquidity. Also, the company does not
believe its obligations to make such expenditures has had or will have any
significant impact on the company's competitive position relative to other
domestic or international petroleum or chemical concerns.
The company'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,
Canada, Australia, United Kingdom, Congo, Angola, Nigeria, Papua New Guinea,
Indonesia, China and Zaire. The company's Caltex affiliates have significant
operations in Indonesia, Japan, Korea, Australia, the Philippines, Singapore,
Thailand and South Africa. The company's Tengizchevroil affiliate operates in
Kazakstan.
FS-28
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 Africa geographic area includes activities
principally in Nigeria, Angola, Zaire and Congo. The "Other" geographic category
includes activities in Australia, the United Kingdom North Sea, Canada, Papua
New Guinea, China 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 Kazakstan, which began operations in April 1993.
TABLE I - COSTS INCURRED IN EXPLORATION, PROPERTY ACQUISITIONS AND
DEVELOPMENT (1)
Consolidated Companies Affiliated Companies
------------------------------------------------- --------------------
Millions of dollars U.S. Africa Other Total CPI TCO Worldwide
- ---------------------------------------------------------------------------------------------------------------------------------
YEAR ENDED DECEMBER 1995
Exploration
Wells $256 $ 63 $141 $ 460 $ 1 $ - $ 461
Geological and geophysical 9 29 37 75 9 - 84
Rentals and other 47 11 64 122 - - 122
- ---------------------------------------------------------------------------------------------------------------------------------
Total exploration 312 103 242 657 10 - 667
- ---------------------------------------------------------------------------------------------------------------------------------
Property acquisitions(2)
Proved(3) 21 56 - 77 - - 77
Unproved 31 8 12 51 - - 51
- ---------------------------------------------------------------------------------------------------------------------------------
Total property acquisitions 52 64 12 128 - - 128
- ---------------------------------------------------------------------------------------------------------------------------------
Development 453 640 568 1,661 97 7 1,765
- ---------------------------------------------------------------------------------------------------------------------------------
TOTAL COSTS INCURRED $817 $807 $822 $2,446 $107 $ 7 $2,560
=================================================================================================================================
YEAR ENDED DECEMBER 1994
Exploration
Wells $163 $ 48 $118 $ 329 $ - $ - $ 329
Geological and geophysical 5 29 38 72 9 - 81
Rentals and other 41 4 71 116 - - 116
- ---------------------------------------------------------------------------------------------------------------------------------
Total exploration 209 81 227 517 9 - 526
- ---------------------------------------------------------------------------------------------------------------------------------
Property acquisitions(2)
Proved(3) 95 145 4 244 - - 244
Unproved 28 19 21 68 - - 68
- ---------------------------------------------------------------------------------------------------------------------------------
Total property acquisitions 123 164 25 312 - - 312
- ---------------------------------------------------------------------------------------------------------------------------------
Development 416 276 503 1,195 140 173 1,508
- ---------------------------------------------------------------------------------------------------------------------------------
TOTAL COSTS INCURRED $748 $521 $755 $2,024 $149 $173 $2,346
=================================================================================================================================
YEAR ENDED DECEMBER 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 1,280 136 35 1,451
- ---------------------------------------------------------------------------------------------------------------------------------
TOTAL COSTS INCURRED $681 $352 $826 $1,859 $146 $731 $2,736
=================================================================================================================================
(1)INCLUDES COSTS INCURRED WHETHER CAPITALIZED OR CHARGED TO EARNINGS. EXCLUDES SUPPORT EQUIPMENT EXPENDITURES.
(2)PROVED AMOUNTS INCLUDE WELLS, EQUIPMENT AND FACILITIES ASSOCIATED WITH PROVED RESERVES. UNPROVED REPRESENTS AMOUNTS FOR
EQUIPMENT AND FACILITIES NOT ASSOCIATED WITH THE PRODUCTION OF PROVED RESERVES.
(3)DOES NOT INCLUDE PROPERTIES ACQUIRED THROUGH PROPERTY EXCHANGES.
FS-29
TABLE II - CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES
Consolidated Companies Affiliated Companies
------------------------------------------------- --------------------
Millions of dollars U.S. Africa Other Total CPI TCO Worldwide
- ---------------------------------------------------------------------------------------------------------------------------------
AT DECEMBER 31, 1995
Unproved properties $ 329 $ 57 $ 190 $ 576 $ - $ 420 $ 996
Proved properties and related
producing assets 16,261 1,959 5,334 23,554 900 408 24,862
Support equipment 686 138 295 1,119 494 207 1,820
Deferred exploratory wells 148 40 62 250 - - 250
Other uncompleted projects 368 1,010 1,176 2,554 320 112 2,986
- ---------------------------------------------------------------------------------------------------------------------------------
Gross capitalized costs 17,792 3,204 7,057 28,053 1,714 1,147 30,914
- ---------------------------------------------------------------------------------------------------------------------------------
Unproved properties valuation 213 30 95 338 - - 338
Proved producing properties -
Depreciation and depletion 11,282 1,071 3,119 15,472 492 18 15,982
Future abandonment and restoration 1,062 247 291 1,600 24 2 1,626
Support equipment depreciation 384 64 179 627 277 30 934
- ---------------------------------------------------------------------------------------------------------------------------------
Accumulated provisions 12,941 1,412 3,684 18,037 793 50 18,880
- ---------------------------------------------------------------------------------------------------------------------------------
NET CAPITALIZED COSTS $ 4,851 $1,792 $3,373 $10,016 $ 921 $1,097 $12,034
=================================================================================================================================
AT DECEMBER 31, 1994
Unproved properties $ 354 $ 50 $ 213 $ 617 $ - $ 420 $ 1,037
Proved properties and related
producing assets 15,996 1,822 4,946 22,764 804 330 23,898
Support equipment 755 133 302 1,190 456 180 1,826
Deferred exploratory wells 145 44 68 257 - - 257
Other uncompleted projects 308 403 1,000 1,711 353 210 2,274
- ---------------------------------------------------------------------------------------------------------------------------------
Gross capitalized costs 17,558 2,452 6,529 26,539 1,613 1,140 29,292
- ---------------------------------------------------------------------------------------------------------------------------------
Unproved properties valuation 230 23 109 362 - - 362
Proved producing properties -
Depreciation and depletion 10,296 924 2,713 13,933 435 8 14,376
Future abandonment and restoration 1,005 221 294 1,520 14 1 1,535
Support equipment depreciation 359 60 157 576 250 16 842
- ---------------------------------------------------------------------------------------------------------------------------------
Accumulated provisions 11,890 1,228 3,273 16,391 699 25 17,115
- ---------------------------------------------------------------------------------------------------------------------------------
NET CAPITALIZED COSTS $ 5,668 $1,224 $3,256 $10,148 $ 914 $1,115 $12,177
=================================================================================================================================
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 21,829 694 311 22,834
Support equipment 750 105 303 1,158 397 149 1,704
Deferred exploratory wells 139 23 60 222 - - 222
Other uncompleted projects 269 296 879 1,444 398 68 1,910
- ---------------------------------------------------------------------------------------------------------------------------------
Gross capitalized costs 17,217 1,983 6,094 25,294 1,489 948 27,731
- ---------------------------------------------------------------------------------------------------------------------------------
Unproved properties valuation 280 20 103 403 - - 403
Proved producing properties -
Depreciation and depletion 9,645 799 2,467 12,911 384 2 13,297
Future abandonment and restoration 1,002 195 276 1,473 12 1 1,486
Support equipment depreciation 338 52 149 539 233 5 777
- ---------------------------------------------------------------------------------------------------------------------------------
Accumulated provisions 11,265 1,066 2,995 15,326 629 8 15,963
- ---------------------------------------------------------------------------------------------------------------------------------
NET CAPITALIZED COSTS $ 5,952 $ 917 $3,099 $ 9,968 $ 860 $ 940 $11,768
=================================================================================================================================
FS-30
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 1995, 1994 and 1993 are shown below.
Net income from exploration and production activities as reported on page FS-6
reflects income taxes computed on an effective rate basis. In accordance with
SFAS 69, income taxes below are based on statutory tax rates, reflecting
allowable deductions and tax credits. Results reported below exclude any
allocation of corporate overhead; net income for 1993 reported on page FS-6
includes allocated corporate overhead, but 1995 and 1994 do not. Interest
expense is excluded from the results reported below and from the net income
amounts on page FS-6.
Consolidated Companies Affiliated Companies
------------------------------------------------- --------------------
Millions of dollars U.S. Africa Other Total CPI TCO Worldwide
- ---------------------------------------------------------------------------------------------------------------------------------
YEAR ENDED DECEMBER 31, 1995
Revenues from net production
Sales $ 1,189 $ 748 $ 783 $ 2,720 $ 35 $125 $ 2,880
Transfers 1,689 824 662 3,175 583 - 3,758
- ---------------------------------------------------------------------------------------------------------------------------------
Total 2,878 1,572 1,445 5,895 618 125 6,638
Production expenses (1,196) (190) (400) (1,786) (195) (94) (2,075)
Proved producing properties depreciation,
depletion and abandonment provision (752) (174) (316) (1,242) (69) (26) (1,337)
Exploration expenses (102) (57) (213) (372) (9) - (381)
Unproved properties valuation (18) (7) (11) (36) - - (36)
New accounting standard for impaired assets (753) - (128) (881) - - (881)
Other income (expense)(2) 130 (52) 37 115 (13) - 102
- ---------------------------------------------------------------------------------------------------------------------------------
Results before income taxes 187 1,092 414 1,693 332 5 2,030
Income tax expense (61) (660) (246) (967) (176) (4) (1,147)
- ---------------------------------------------------------------------------------------------------------------------------------
RESULTS OF PRODUCING OPERATIONS $ 126 $ 432 $ 168 $ 726 $ 156 $ 1 $ 883
=================================================================================================================================
YEAR ENDED DECEMBER 31, 1994
Revenues from net production
Sales $ 1,484 $ 353 $ 736 $ 2,573 $ 24 $ 86 $ 2,683
Transfers 1,598 960 642 3,200 531 - 3,731
- ---------------------------------------------------------------------------------------------------------------------------------
Total 3,082 1,313 1,378 5,773 555 86 6,414
Production expenses (1,219) (222) (399) (1,840) (184) (65) (2,089)
Proved producing properties depreciation,
depletion and abandonment provision (885) (153) (326) (1,364) (53) (17) (1,434)
Exploration expenses (132) (52) (192) (376) (9) - (385)
Unproved properties valuation (21) (3) (15) (39) - - (39)
Other income (expense)(2) 22 (50) (21) (49) (26) (8) (83)
- ---------------------------------------------------------------------------------------------------------------------------------
Results before income taxes 847 833 425 2,105 283 (4) 2,384
Income tax expense (314) (569) (252) (1,135) (143) (6) (1,284)
- ---------------------------------------------------------------------------------------------------------------------------------
Results of Producing Operations $ 533 $ 264 $ 173 $ 970 $ 140 $(10) $ 1,100
=================================================================================================================================
YEAR ENDED DECEMBER 31, 1993
Revenues from net production
Sales $ 1,539 $ 247 $ 779 $ 2,565 $ 22 $ 41 $ 2,628
Transfers 1,912 1,040 661 3,613 487 - 4,100
- ---------------------------------------------------------------------------------------------------------------------------------
Total 3,451 1,287 1,440 6,178 509 41 6,728
Production expenses (1,274) (208) (402) (1,884) (161) (43) (2,088)
Proved producing properties depreciation,
depletion and abandonment provision (958) (126) (311) (1,395) (50) (8) (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 (3) 9 34
- ---------------------------------------------------------------------------------------------------------------------------------
Results before income taxes 1,109 870 549 2,528 286 (1) 2,813
Income tax expense (422) (625) (243) (1,290) (152) - (1,442)
- ---------------------------------------------------------------------------------------------------------------------------------
Results of Producing Operations $ 687 $ 245 $ 306 $ 1,238 $ 134 $ (1) $ 1,371
=================================================================================================================================
FS-31
TABLE III - RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES (1) -
Continued
Consolidated Companies Affiliated Companies
------------------------------------------------- --------------------
PER-UNIT AVERAGE SALES PRICE
AND PRODUCTION COST (1)(3) U.S. Africa Other Total CPI TCO Worldwide
- ---------------------------------------------------------------------------------------------------------------------------------
YEAR ENDED DECEMBER 31, 1995
Average sales prices
Liquids, per barrel $14.98 $16.49 $15.32 $15.55 $14.35 $11.51 $15.29
Natural gas, per thousand cubic feet 1.52 - 1.72 1.56 - .71 1.55
Average production costs, per barrel 5.11 2.00 3.83 4.12 4.52 7.73 4.24
=================================================================================================================================
YEAR ENDED DECEMBER 31, 1994
Average sales prices
Liquids, per barrel $13.65 $15.16 $14.16 $14.18 $12.65 $10.54 $13.90
Natural gas, per thousand cubic feet 1.76 - 1.83 1.78 - .56 1.76
Average production costs, per barrel 4.81 2.57 3.79 4.13 4.19 7.13 4.19
=================================================================================================================================
YEAR ENDED DECEMBER 31, 1993
Average sales prices
Liquids, per barrel $14.48 $16.21 $16.06 $15.33 $13.29 $10.74 $15.05
Natural gas, per thousand cubic feet 1.98 - 2.08 2.00 - .13 1.99
Average production costs, per barrel 4.91 2.62 4.22 4.34 4.19 9.82 4.38
=================================================================================================================================
Average sales price for liquids ($/Bbl)
DECEMBER 1995 $15.47 $17.45 $16.03 $16.25 $15.39 $11.37 $16.01
December 1994 13.80 15.20 14.35 14.36 13.10 10.54 14.12
December 1993 10.73 12.94 13.63 12.05 10.72 8.58 11.82
=================================================================================================================================
Average sales price for natural gas ($/MCF)
DECEMBER 1995 $ 2.04 $ - $ 1.99 $ 2.03 $ - $ .77 $ 2.02
December 1994 1.62 - 1.73 1.64 - .57 1.63
December 1993 2.19 - 2.34 2.21 - .26 2.20
=================================================================================================================================
(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 1995, BEFORE-TAX NET ASSET WRITE-OFFS, ASSET DISPOSITIONS, ENVIRONMENTAL PROVISIONS AND
REGULATORY ISSUES INCREASED INCOME $15 IN THE UNITED STATES. HOWEVER, IN THE INTERNATIONAL OTHER SEGMENT, NET SPECIAL
CHARGES FOR LITIGATION AND EMPLOYEE SEVERANCE REDUCED EARNINGS $29. IN 1994, THE UNITED STATES INCLUDED BEFORE-TAX NET CHARGES
OF $97 RELATING TO ENVIRONMENTAL CLEANUP PROVISIONS, LITIGATION AND REGULATORY SETTLEMENTS AND AN INSURANCE RECOVERY. IN 1993,
THE UNITED STATES INCLUDES BEFORE-TAX LOSSES ON PROPERTY DISPOSITIONS AND OTHER SPECIAL CHARGES TOTALING $150.
(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 1995, 1994 and 1993 are shown in the following table.
Proved reserves are estimated by the company's asset teams composed of earth
scientists and reservoir engineers. These proved reserve estimates are reviewed
annually by the corporation's reserves advisory committee to ensure that
rigorous professional standards and the reserves definitions prescribed by the
Securities and Exchange Commission are consistently applied throughout the
company.
Proved reserves are the estimated quantities that geologic and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. Due to the
inherent uncertainties and the limited nature of reservoir data, estimates of
underground reserves are subject to change over time as additional information
becomes available.
Proved reserves do not include additional quantities recoverable beyond the term
of the lease or contract unless renewal is reasonably certain, or that may
result from extensions of currently proved areas, or from application of
secondary or tertiary recovery processes not yet tested and determined to be
economic.
Proved developed reserves are the quantities expected to be recovered through
existing wells with existing equipment and operating methods.
"Net" reserves exclude royalties and interests owned by others and reflect
contractual arrangements and royalty obligations in effect at the time of the
estimate.
Proved reserves for Tengizchevroil (TCO), the company's 50 percent owned
affiliate in Kazakstan, do not include reserves that will be produced when a
dedicated export system is in place.
FS-32
TABLE IV - RESERVE QUANTITIES INFORMATION - Continued
NET PROVED RESERVES OF CRUDE OIL, CONDENSATE NET PROVED RESERVES OF NATURAL GAS
AND NATURAL GAS LIQUIDS MILLIONS OF BARRELS BILLIONS OF CUBIC FEET
--------------------------------------------------- ----------------------------------------------------
CONSOLIDATED COMPANIES AFFILIATES CONSOLIDATED COMPANIES AFFILIATES
---------------------------- ------------ WORLD- ----------------------------- ------------- WORLD-
U.S. AFRICA OTHER TOTAL CPI TCO WIDE U.S. AFRICA OTHER TOTAL CPI TCO WIDE
- --------------------------------------------------------------------------- ----------------------------------------------------
RESERVES AT
JANUARY 1, 1993 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 (4) 1 238
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) (48) (4) (347) (751) - (151) (902) (14) (6) (922)
- --------------------------------------------------------------------------- ----------------------------------------------------
RESERVES AT
DECEMBER 31, 1993 1,279 682 453 2,414 669 1,102 4,185 5,484 - 2,257 7,741 142 1,528 9,411
Changes attributable to:
Revisions 1 30 10 41 (19) 1 23 283 - (11) 272 (6) 2 268
Improved recovery 22 18 36 76 9 - 85 5 - 7 12 - - 12
Extensions
and discoveries 35 85 46 166 - - 166 533 - 675 1,208 26 - 1,234
Purchases(1) 1 76 - 77 - - 77 55 - 1 56 - - 56
Sales(2) (4) - (3) (7) - - (7) (23) - (31) (54) - - (54)
Production (134) (87) (77) (298) (56) (8) (362) (761) - (176) (937) (11) (12) (960)
- --------------------------------------------------------------------------- ----------------------------------------------------
RESERVES AT
DECEMBER 31, 1994 1,200 804 465 2,469 603 1,095 4,167 5,576 - 2,722 8,298 151 1,518 9,967
Changes attributable to:
Revisions 25 62 74 161 (28) 2 135 3 62 71 136 13 2 151
Improved recovery 7 36 66 109 42 - 151 7 - 23 30 - - 30
Extensions
and discoveries 87 137 14 238 - - 238 609 22 175 806 6 - 812
Purchases(1) 3 25 - 28 - - 28 48 - 2 50 - - 50
Sales(2) (6) - (5) (11) - - (11) (29) - (23) (52) - - (52)
Production (129) (95) (76) (300) (55) (10) (365) (682) - (176) (858) (15) (15) (888)
- --------------------------------------------------------------------------- ----------------------------------------------------
RESERVES AT
DECEMBER 31, 1995 1,187 969 538 2,694 562 1,087 4,343 5,532 84 2,794 8,410 155 1,505 10,070
=========================================================================== ====================================================
Developed reserves
- --------------------------------------------------------------------------- ----------------------------------------------------
At January 1, 1993 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 1,964 511 421 2,896 4,863 - 1,647 6,510 130 584 7,224
At December 31, 1994 1,097 546 293 1,936 499 414 2,849 4,919 - 1,508 6,427 135 574 7,136
AT DECEMBER 31, 1995 1,061 596 371 2,028 457 406 2,891 4,929 84 1,726 6,739 140 562 7,441
=========================================================================== ====================================================
(1)INCLUDES RESERVES ACQUIRED THROUGH PROPERTY EXCHANGES.
(2)INCLUDES RESERVES DISPOSED OF THROUGH PROPERTY EXCHANGES.
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 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-33
TABLE V -STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO
PROVED OIL AND GAS RESERVES - Continued
Consolidated Companies Affiliated Companies
------------------------------------------------- --------------------
Millions of dollars U.S. Africa Other Total CPI TCO Worldwide
- ---------------------------------------------------------------------------------------------------------------------------------
AT DECEMBER 31, 1995
Future cash inflows from production $ 30,200 $17,570 $15,340 $ 63,110 $ 9,530 $15,630 $ 88,270
Future production and development costs (14,140) (4,350) (4,600) (23,090) (5,700) (7,140) (35,930)
Future income taxes (5,390) (7,910) (3,660) (16,960) (1,950) (3,350) (22,260)
- ---------------------------------------------------------------------------------------------------------------------------------
Undiscounted future net cash flows 10,670 5,310 7,080 23,060 1,880 5,140 30,080
10 percent midyear annual discount for
timing of estimated cash flows (4,260) (1,830) (3,140) (9,230) (800) (3,700) (13,730)
- ---------------------------------------------------------------------------------------------------------------------------------
STANDARDIZED MEASURE OF DISCOUNTED
FUTURE NET CASH FLOWS $ 6,410 $ 3,480 $ 3,940 $ 13,830 $ 1,080 $ 1,440 $ 16,350
=================================================================================================================================
AT DECEMBER 31, 1994
Future cash inflows from production $ 26,030 $12,230 $12,450 $ 50,710 $ 9,160 $14,080 $ 73,950
Future production and development costs (13,540) (4,060) (5,450) (23,050) (6,050) (8,020) (37,120)
Future income taxes (3,950) (5,000) (2,410) (11,360) (1,570) (2,090) (15,020)
- ---------------------------------------------------------------------------------------------------------------------------------
Undiscounted future net cash flows 8,540 3,170 4,590 16,300 1,540 3,970 21,810
10 percent midyear annual discount for
timing of estimated cash flows (3,490) (1,220) (1,870) (6,580) (660) (2,950) (10,190)
- ---------------------------------------------------------------------------------------------------------------------------------
Standardized Measure of Discounted
Future Net Cash Flows $ 5,050 $ 1,950 $ 2,720 $ 9,720 $ 880 $ 1,020 $ 11,620
=================================================================================================================================
AT DECEMBER 31, 1993
Future cash inflows from production $ 24,990 $ 8,680 $10,590 $ 44,260 $ 8,490 $11,170 $ 63,920
Future production and development costs (13,510) (3,640) (4,740) (21,890) (5,660) (8,240) (35,790)
Future income taxes (3,490) (3,020) (1,660) (8,170) (1,380) (900) (10,450)
- ---------------------------------------------------------------------------------------------------------------------------------
Undiscounted future net cash flows 7,990 2,020 4,190 14,200 1,450 2,030 17,680
10 percent midyear annual discount for
timing of estimated cash flows (3,400) (700) (1,500) (5,600) (650) (1,690) (7,940)
- ---------------------------------------------------------------------------------------------------------------------------------
Standardized Measure of Discounted
Future Net Cash Flows $ 4,590 $ 1,320 $ 2,690 $ 8,600 $ 800 $ 340 $ 9,740
=================================================================================================================================
TABLE VI - CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS FROM PROVED RESERVES
CONSOLIDATED COMPANIES AFFILIATED COMPANIES WORLDWIDE
---------------------------- ---------------------------- ----------------------------
MILLIONS OF DOLLARS 1995 1994 1993 1995 1994 1993 1995 1994 1993
- ---------------------------------------------------------------------------------------------------------------------------------
PRESENT VALUE AT JANUARY 1 $ 9,720 $ 8,600 $12,740 $1,900 $1,140 $ 1,010 $11,620 $ 9,740 $13,750
- ---------------------------------------------------------------------------------------------------------------------------------
Sales and transfers of oil and gas
produced, net of production costs (4,109) (3,933) (4,294) (454) (392) (346) (4,563) (4,325) (4,640)
Development costs incurred 1,661 1,195 1,280 104 313 171 1,765 1,508 1,451
Purchases of reserves 230 305 30 - - 436 230 305 466
Sales of reserves (116) (54) (72) - - - (116) (54) (72)
Extensions, discoveries and improved
recovery, less related costs 2,927 1,775 922 165 (3) 5 3,092 1,772 927
Revisions of previous quantity estimates 1,979 1,064 1,210 (723) (377) 560 1,256 687 1,770
Net changes in prices, development
and production costs 3,602 1,317 (6,602) 1,756 1,384 (1,123) 5,358 2,701 (7,725)
Accretion of discount 1,513 1,233 1,775 310 206 205 1,823 1,439 1,980
Net change in income tax (3,577) (1,782) 1,611 (538) (371) 222 (4,115) (2,153) 1,833
- ---------------------------------------------------------------------------------------------------------------------------------
Net change for the year 4,110 1,120 (4,140) 620 760 130 4,730 1,880 (4,010)
- ---------------------------------------------------------------------------------------------------------------------------------
PRESENT VALUE AT DECEMBER 31 $13,830 $ 9,720 $ 8,600 $2,520 $1,900 $ 1,140 $16,350 $11,620 $ 9,740
=================================================================================================================================
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
1995 changes reflected higher year-end crude oil and natural gas prices and
quantity increases in crude oil and natural gas reserves.
FS-34
FIVE-YEAR FINANCIAL SUMMARY (1)
MILLIONS OF DOLLARS, EXCEPT PER-SHARE AMOUNTS 1995 1994 1993 1992 1991
- ------------------------------------------------------------------------------------------------------------------------
CONSOLIDATED STATEMENT OF INCOME DATA
REVENUES
Sales and other operating revenues
Refined products $13,471 $14,328 $16,089 $16,821 $16,794
Crude oil 9,376 8,249 8,501 10,031 10,276
Natural gas 2,019 2,138 2,156 1,995 1,869
Natural gas liquids 1,285 1,180 1,235 1,190 1,165
Other petroleum 1,144 944 967 927 812
Chemicals 3,758 3,065 2,708 2,872 3,098
Coal and other minerals 358 416 447 397 427
Excise taxes 4,988 4,790 4,068 3,964 3,659
Corporate and other (89) 20 20 15 18
- ------------------------------------------------------------------------------------------------------------------------
Total sales and other operating revenues 36,310 35,130 36,191 38,212 38,118
Equity in net income of affiliated companies 553 440 440 406 491
Other income 219 284 451 1,059 334
- ------------------------------------------------------------------------------------------------------------------------
TOTAL REVENUES 37,082 35,854 37,082 39,677 38,943
COSTS, OTHER DEDUCTIONS AND INCOME TAXES 36,152 34,161 35,817 37,467 37,650
- ------------------------------------------------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGES
IN ACCOUNTING PRINCIPLES $ 930 $ 1,693 $ 1,265 $ 2,210 $ 1,293
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES - - - (641) -
- ------------------------------------------------------------------------------------------------------------------------
NET INCOME $ 930 $ 1,693 $ 1,265 $ 1,569 $ 1,293
========================================================================================================================
PER SHARE OF COMMON STOCK:
INCOME BEFORE CUMULATIVE EFFECT OF CHANGES
IN ACCOUNTING PRINCIPLES $1.43 $2.60 $1.94 $3.26 $1.85
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES - - - (0.95) -
- ------------------------------------------------------------------------------------------------------------------------
NET INCOME PER SHARE OF COMMON STOCK $1.43 $2.60 $1.94 $2.31 $1.85
========================================================================================================================
CASH DIVIDENDS PER SHARE $1.925 $1.85 $1.75 $1.65 $1.625
========================================================================================================================
CONSOLIDATED BALANCE SHEET DATA (YEAR-END)
Current assets $ 7,867 $ 7,591 $ 8,682 $ 8,722 $ 9,031
Properties, plant and equipment (net) 21,696 22,173 21,865 22,188 22,850
Total assets 34,330 34,407 34,736 33,970 34,636
Short-term debt 3,806 4,014 3,456 2,888 1,706
Other current liabilities 5,639 5,378 7,150 6,947 7,774
Long-term debt and capital lease obligations 4,521 4,128 4,082 4,953 5,991
Stockholders' equity 14,355 14,596 13,997 13,728 14,739
Per share $ 22.01 $ 22.40 $ 21.49 $ 21.11 $ 21.25
========================================================================================================================
SELECTED DATA
Return on average stockholders' equity 6.4% 11.8% 9.1% 11.0% 8.7%
Return on average capital employed 5.3% 8.7% 6.8% 8.5% 7.5%
Total debt/total debt plus equity 36.7% 35.8% 35.0% 36.4% 34.3%
Capital and exploratory expenditures(2) $ 4,800 $ 4,819 $ 4,440 $ 4,423 $ 4,787
Common stock price - High $53 5/8 $49 3/16 $49 3/8 $37 11/16 $40 1/16
- Low $43 3/8 $39 7/8 $33 11/16 $30 1/16 $31 3/4
- Year-end $52 3/8 $44 5/8 $43 9/16 $34 3/4 $34 1/2
Common shares outstanding at year-end (in thousands) 652,327 651,751 651,478 650,348 693,444
Weighted average shares outstanding for
the year (in thousands) 652,084 651,672 650,958 677,955 700,348
Number of employees at year-end 43,019 45,758 47,576 49,245 55,123
========================================================================================================================
(1)COMPARABILITY BETWEEN YEARS IS AFFECTED BY CHANGES IN ACCOUNTING METHODS: 1995 REFLECTS ADOPTION OF STATEMENT OF
FINANCIAL ACCOUNTING STANDARD (SFAS) 121, "ACCOUNTING FOR THE IMPAIRMENT OF LONG-LIVED ASSETS AND FOR LONG-LIVED
ASSETS TO BE DISPOSED OF"; 1992 AND SUBSEQUENT YEARS REFLECT ADOPTION OF SFAS 106, "EMPLOYERS' ACCOUNTING FOR
POST-RETIREMENT BENEFITS OTHER THAN PENSIONS" AND SFAS 109, "ACCOUNTING FOR INCOME TAXES"; 1991 REFLECTS THE
ADOPTION OF SFAS 96, "ACCOUNTING FOR INCOME TAXES." SHARE AND PER-SHARE AMOUNTS FOR ALL YEARS REFLECT THE
TWO-FOR-ONE STOCK SPLIT IN MAY 1994.
(2)INCLUDES EQUITY IN AFFILIATES' EXPENDITURES. $912 $846 $701 $621 $498
FS-35
CALTEX GROUP OF COMPANIES
COMBINED FINANCIAL STATEMENTS
December 31, 1995
C-1
CALTEX GROUP OF COMPANIES
COMBINED FINANCIAL STATEMENTS
DECEMBER 31, 1995
INDEX
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-20
Note: Financial statement schedules are omitted as permitted by Rule 4.03 and
Rule 5.04 of Regulation S-X.
C-2
CALTEX GROUP OF COMPANIES
GENERAL INFORMATION
The Caltex Group of Companies (Group) is jointly owned 50% each by Chevron
Corporation and Texaco Inc. The private joint venture was created in
Bahrain in 1936 by its two owners to produce, transport, refine and market
crude oil and refined products. 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,
marketing and transporting 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 subsidiary, provides services for and manages
certain exploration and production operations in Indonesia in which
Chevron and Texaco have interests, but not necessarily jointly or 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 approximately 60
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 15 refineries in 11 countries.
Caltex' share of refinery inputs approximated 903,000 barrels per day in 1995.
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 1995, Caltex had over 7,000
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 17.9% with refined product sales of approximately 1.3
million barrels per day in 1995. Caltex built 97 new branded retail outlets
during 1995 and refurbished 85 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. The company has an
interest in a fleet of vessels and owns or has equity interests in numerous
pipelines, terminals and depots. Caltex is also 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 through
an area comprising 2.446 million acres with production established in the
giant Minas and Duri fields, along with 72 smaller fields. Gross production
from fields operated by CPI for 1995 was over 753,000 barrels per day. CPI
entitlements are sold to its shareholders, who use it in their systems or sell
it to third parties. At year end 1995, CPI had about 6,300 employees, all
located in Indonesia.
C-3
CALTEX GROUP OF COMPANIES
GENERAL INFORMATION
American Overseas Petroleum Limited (AOPL)
- ------------------------------------------
In addition to providing services to CPI, AOPL, through its subsidiary
Amoseas Indonesia Inc., manages selective contract areas for Texaco's and
Chevron's undivided interests in Indonesia, excluding Sumatra. One of the
contract areas is dedicated to geothermal reserves. Geothermal proved
reserves in Darajat, West Java, are able to supply a 100 megawatt power
generating plant for over 30 years. Production of steam generation during
1995 was 368,219,927 KWH, with 55 megawatts being sold under a 30 year energy
contract and 70 megawatts of electrical power generation being developed for
sale. A joint operating agreement is being developed with a new Indonesian
partner to carry out geothermal business interests. At year end, AOPL had
about 275 employees, of which about 6% 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, 1995, the Group had accrued $21 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, 1995,
the Group, including its equity share of nonsubsidiary companies, incurred
capital costs of $206 million and nonremediation related operating expenses of
$139 million. The major component of the Group's expenditures is for the
prevention of air pollution. In addition, as of December 31, 1995, reserves
relative to the future cost of restoring and abandoning existing oil and gas
properties were $48 million. 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, 1995 and 1994, 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, 1995. These combined financial
statements are the responsibility of the Group's management. Our
responsibility is to express an opinion on these combined financial statements
based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the combined financial statements referred to above present
fairly, in all material respects, the financial position of the Caltex Group
of Companies as of December 31, 1995 and 1994 and the results of its
operations and its cash flows for each of the years in the three-year period
ended December 31, 1995, in conformity with generally accepted accounting
principles.
As discussed in Note 2 to the combined financial statements, effective
January 1, 1994, the Group adopted the provisions of the Financial Accounting
Standards Board's Statement of Financial Accounting Standards No. 115,
"Accounting for Certain Investments in Debt and Equity Securities."
/s/ KPMG Peat Marwick LLP
Dallas, Texas
February 12, 1996
C-5
CALTEX GROUP OF COMPANIES
COMBINED BALANCE SHEET - DECEMBER 31, 1995 AND 1994
(MILLIONS OF DOLLARS)
ASSETS
1995 1994
-------- --------
CURRENT ASSETS:
Cash and cash equivalents (including time
deposits of $60 in 1995 and $136 in 1994) $ 166 $ 251
Notes and accounts receivable, less allowance for
doubtful accounts of $11 in 1995 and $14 in 1994:
Trade 1,002 1,107
Other 238 187
Nonsubsidiary companies 210 88
-------- --------
1,450 1,382
Inventories:
Crude oil 130 132
Refined products 516 573
Materials and supplies 61 73
-------- --------
707 778
Other - 10
-------- --------
Total current assets 2,323 2,421
INVESTMENTS AND ADVANCES:
Nonsubsidiary companies at equity 3,163 2,370
Miscellaneous investments and long-term
receivables, less allowance of $8 in 1995
and 1994 207 198
-------- --------
3,370 2,568
PROPERTY, PLANT AND EQUIPMENT, AT COST:
Producing 3,485 3,284
Refining 1,468 1,787
Marketing 2,160 2,552
Other 9 154
-------- --------
7,122 7,777
Less: Accumulated depreciation, depletion
and amortization 2,868 3,165
-------- --------
4,254 4,612
PREPAID AND DEFERRED CHARGES 170 209
-------- --------
Total assets $10,117 $9,810
======== ========
See accompanying Notes to Combined Financial Statements.
C-6
CALTEX GROUP OF COMPANIES
COMBINED BALANCE SHEET - DECEMBER 31, 1995 AND 1994
(MILLIONS OF DOLLARS)
LIABILITIES AND STOCKHOLDERS' EQUITY
1995 1994
-------- --------
CURRENT LIABILITIES:
Notes payable to banks and other
financial institutions $ 1,576 $1,229
Long-term debt due within one year 89 157
Accounts payable:
Trade and other 1,195 1,240
Stockholder companies 90 77
Nonsubsidiary companies 74 123
-------- --------
1,359 1,440
Accrued liabilities 97 113
Estimated income taxes 102 133
-------- --------
Total current liabilities 3,223 3,072
LONG-TERM DEBT 628 715
ACCRUED LIABILITY FOR EMPLOYEE BENEFITS 98 113
DEFERRED CREDITS AND OTHER NON-CURRENT LIABILITIES 864 789
DEFERRED INCOME TAXES 209 236
MINORITY INTEREST IN SUBSIDIARY COMPANIES 136 152
STOCKHOLDERS' EQUITY:
Common stock 355 355
Additional paid-in capital 2 2
Retained earnings 4,187 3,898
Currency translation adjustment 350 399
Unrealized holding gain on investments 65 79
-------- --------
Total stockholders' equity 4,959 4,733
COMMITMENTS AND CONTINGENT LIABILITIES
-------- --------
Total liabilities and stockholders' equity $10,117 $9,810
======== ========
See accompanying Notes to Combined Financial Statements.
C-7
CALTEX GROUP OF COMPANIES
COMBINED STATEMENT OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
(MILLIONS OF DOLLARS)
1995 1994 1993
-------- -------- --------
SALES AND OTHER OPERATING REVENUES(1) $15,067 $14,751 $15,409
OPERATING CHARGES:
Cost of sales and operating expenses(2) 13,045 12,801 13,431
Selling, general and administrative expenses 620 568 496
Depreciation, depletion and amortization 361 331 295
Maintenance and repairs 104 160 170
-------- -------- --------
14,130 13,860 14,392
-------- -------- --------
Operating income 937 891 1,017
OTHER INCOME (DEDUCTIONS):
Equity in net income
of nonsubsidiary companies 425 263 140
Dividends, interest and other income 130 134 99
Foreign exchange, net 37 (73) 23
Interest expense (159) (101) (93)
Minority interest in subsidiary companies (4) (3) (8)
-------- -------- --------
429 220 161
-------- -------- --------
Income before provision for income taxes 1,366 1,111 1,178
-------- -------- --------
PROVISION FOR INCOME TAXES:
Current 449 467 433
Deferred 18 (45) 25
-------- -------- --------
Total provision for income taxes 467 422 458
-------- -------- --------
Net income $ 899 $ 689 $ 720
======== ======== ========
(1) Includes sales to:
Stockholder companies $ 1,376 $ 1,250 $ 943
Nonsubsidiary companies $ 1,524 $ 1,044 $ 944
(2) Includes purchases from:
Stockholder companies $ 1,834 $ 1,662 $ 2,410
Nonsubsidiary companies $ 1,638 $ 1,587 $ 1,356
See accompanying Notes to Combined Financial Statements.
C-8
CALTEX GROUP OF COMPANIES
COMBINED STATEMENT OF RETAINED EARNINGS
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
(MILLIONS OF DOLLARS)
1995 1994 1993
-------- -------- --------
Balance at beginning of year $3,898 $3,688 $3,310
Net income 899 689 720
Cash dividends (610) (479) (342)
-------- -------- --------
Balance at end of year $4,187 $3,898 $3,688
======== ======== ========
COMBINED STATEMENT OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
(MILLIONS OF DOLLARS)
1995 1994 1993
-------- -------- --------
OPERATING ACTIVITIES:
Net income $ 899 $ 689 $ 720
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation, depletion and amortization 361 331 295
Dividends from nonsubsidiary companies,
less than equity in net income (349) (220) (103)
Net gains/losses on asset sales 11 (17) (4)
Deferred income taxes 18 (45) 25
Prepaid charges and deferred credits 69 115 (41)
Changes in operating working capital (27) 58 31
Other 66 77 10
-------- -------- --------
Net cash provided by operating activities 1,048 988 933
-------- -------- --------
INVESTING ACTIVITIES:
Capital expenditures (663) (837) (763)
Investments in and advances to
nonsubsidiary companies (150) (131) (149)
Net purchases/sales of investment instruments (7) 14 (21)
Proceeds from asset sales 46 37 73
-------- -------- --------
Net cash used in investing activities (774) (917) (860)
-------- -------- --------
FINANCING ACTIVITIES:
Proceeds from borrowings having original terms
in excess of three months 1,063 1,257 745
Repayments of borrowings having original terms
in excess of three months (1,093) (880) (704)
Net increase in other borrowings 275 135 140
Dividends paid, including minority interest (617) (482) (342)
-------- -------- --------
Net cash provided by (used in) financing activities (372) 30 (161)
-------- -------- --------
Effect of exchange rate changes on cash
and cash equivalents 13 (16) 15
NET CHANGE IN CASH AND CASH EQUIVALENTS (85) 85 (73)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 251 166 239
-------- -------- --------
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 166 $ 251 $ 166
======== ======== ========
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 subsidiary and P.T. Caltex Pacific
Indonesia after the elimination of intercompany balances and transactions.
Subsidiaries include companies owned directly or indirectly more than 50
percent except cases in which control does not rest with the Group.
A subsidiary of Chevron Corporation and two subsidiaries of Texaco Inc.
(stockholders) each own 50% of the outstanding common shares of the Group
companies. 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.
ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates. The
Group believes that the effects of any such changes in the near term would
not have a material impact on the financial statements.
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.
C-10
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - CONTINUED
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.
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.
DERIVATIVE FINANCIAL INSTRUMENTS
Gains and losses on hedges of existing assets or liabilities are included
in the carrying amounts of those assets and liabilities and are ultimately
recognized in income as part of those carrying amounts. Gains and losses
related to qualifying hedges of firm commitments or anticipated transactions
also are deferred and are recognized in income or as adjustments of carrying
amounts when the underlying hedged transaction occurs. If, subsequent to
being hedged, underlying transactions are no longer likely to occur, the
related derivatives' gains and losses are recognized currently in income.
ENVIRONMENTAL MATTERS
Compliance with environmental regulations is determined in consideration of
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
realizable.
RECLASSIFICATIONS
Certain amounts have been reclassified for preceding periods to conform with
the current year's presentation.
(2) CHANGES IN ACCOUNTING PRINCIPLES
The Group adopted Statement of Financial Accounting Standards (SFAS) No. 115,
"Accounting for Certain Investments in Debt and Equity Securities" effective
January 1, 1994. SFAS No. 115 requires that investments in equity securities
that have readily determinable fair values and all investments in debt
securities be classified into three categories based on management's intent.
Such investments are to be reported at fair value except for debt securities
intended to be held to maturity which are to be reported at amortized cost.
Previously, all such investments were accounted for at amortized cost. The
cumulative effect of this change at January 1, 1994 was an increase in
stockholders' equity of $70 million, after related taxes, representing
unrealized net gains applicable to securities categorized as available-for-
sale under the new standard. Such securities are primarily held by
nonsubsidiary companies accounted for by the equity method.
Effective October 1, 1995, the Group adopted SFAS No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of."
SFAS No. 121 establishes guidelines for recognizing and measuring impairment
of long-lived assets. Adoption of this standard did not impact the combined
financial statements of the Group.
C-11
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(3) INVENTORIES
The excess of current cost over the stated value of inventory maintained on
the LIFO basis was approximately $52 million and $56 million at December 31,
1995 and 1994, respectively.
During 1995, 1994 and 1993, inventory quantities maintained on the LIFO basis
were reduced at certain locations. The inventory reductions, net of market
valuation adjustments, resulted in a decrease in the earnings of consolidated
subsidiaries and nonsubsidiary companies at equity of approximately $1 million
and $8 million in 1995 and 1994, respectively, and an increase of $1 million
in 1993.
Charges of $104 million reduced income in 1993 to reflect a market value of
certain inventories lower than their LIFO carrying value. Earnings of $25
million and $30 million, net of inventory reduction effects, were recorded in
1995 and 1994, respectively, to reflect a partial recovery of prior year
charges.
(4) NONSUBSIDIARY COMPANIES AT EQUITY
Investments in and advances to nonsubsidiary companies at equity at
December 31 include the following (in millions):
Equity Share 1995 1994
------------ ------ ------
Nippon Petroleum Refining Company, Limited 50% $1,132 $ 997
Koa Oil Company, Limited 50% 427 448
Honam Oil Refinery Company, Limited 50% 762 557
Australian Petroleum Pty. Limited 50% 412 -
Star Petroleum Refining Company, Ltd. 64% 327 266
All other Various 103 102
------ ------
$3,163 $2,370
====== ======
Effective May 1995, Caltex Australia Limited (CAL), a subsidiary of the Group,
combined its petroleum refining and marketing operations with those of Ampol
Limited, a competitor, to form Australian Petroleum Pty. Limited (APPL) which
owns and manages the combined refining and marketing operations. CAL
contributed net assets with a carrying value of $419 million for its 50%
equity interest in APPL. CAL's petroleum refining and marketing net assets
were contributed at their historical basis, and no gain or loss was recognized
on the transaction. The carrying value of CAL's investment in APPL exceeds
its proportionate share of APPL's net equity. The excess will be amortized
over a period of 20 years.
The remaining interest in Star Petroleum Refining Company, Ltd. (SPRC) is
owned by a Thailand governmental entity. Due to provisions in the SPRC
shareholder agreement, control over SPRC does not rest with the Group. In
addition, the Group's degree of ownership is temporary. The SPRC construction
and operation agreement between the government's Ministry of Industry and the
Group stipulates that the Group must reduce its interest in SPRC to a minority
share by the year 2000.
C-12
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(4) NONSUBSIDIARY COMPANIES AT EQUITY - CONTINUED
Shown below is summarized combined financial information for these
nonsubsidiary companies (in millions):
100% Equity Share
--------------- -----------------
1995 1994 1995 1994
------ ------ ------ ------
Current assets $7,125 $5,352 $3,556 $2,651
Other assets 10,415 7,821 5,368 3,858
Current liabilities 5,608 4,940 2,804 2,363
Other liabilities 5,865 3,504 3,039 1,776
Net worth 6,067 4,729 3,081 2,370
100% Equity Share
--------------------------- ---------------------------
1995 1994 1993 1995 1994 1993
------- ------- ------- ------- ------- -------
Operating revenues $15,396 $10,886 $10,679 $7,674 $5,418 $5,304
Operating income 955 770 494 472 381 242
Net income 859 526 281 425 263 140
During 1995, a nonsubsidiary company of the Group sold certain property
required by a local government. The nonsubsidiary was compensated for the
value of the property transferred and the cost of replacing operating assets
affected by the transfer. While the compensation is to be fully utilized in
the reconstruction program over a five year period, the excess of the
compensation over the net book value of the property and the dismantled
operating assets was recognized in 1995 earnings by the nonsubsidiary. The
Group's after-tax equity share of the gain was $171.5 million.
Retained earnings at December 31, 1995 and 1994, includes $1.7 billion and
$1.4 billion, respectively, representing the Group's share of undistributed
earnings of nonsubsidiary companies at equity.
Cash dividends received from these nonsubsidiary companies were $76 million,
$43 million, and $37 million in 1995, 1994, and 1993, respectively.
Sales to the other 50 percent owner of Nippon Petroleum Refining Company,
Limited of products refined by Nippon Petroleum Refining Company, Limited and
Koa Oil Company, Limited were approximately $2.1 billion, $2 billion, and $1.9
billion in 1995, 1994, and 1993, respectively.
On December 6, 1995, the Group signed a memorandum of understanding with
Nippon Oil Company, Limited (NOC) to sell the Group's interest in Nippon
Petroleum Refining Company, Limited. Subsequently, on January 30, 1996, the
Group signed binding agreements for the sale and scheduled the closing for
April 1, 1996. The agreed proceeds are 200 billion Yen (approximately $2
billion) and the impact on the Group's earnings in 1996 is currently estimated
to be a net after-tax gain of approximately $650 million, inclusive of the
impact of a forward exchange contract hedge.
C-13
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(5) NOTES PAYABLE
Short-term financing consists primarily of demand loans, promissory notes,
acceptance credits and overdrafts. The weighted average interest rates on
short-term financing at December 31, 1995, and 1994 were 7.0% and 6.8%,
respectively.
Unutilized lines of credit available for short-term financing totaled $844
million at December 31, 1995.
(6) LONG-TERM DEBT
Long-term debt, with related interest rates at December 31, 1995, consist of
the following (in millions):
1995 1994
-------- --------
U.S. dollars:
Variable interest rate term loans $243 $233
Fixed interest rate term loans
with 6.7% average rate 58 206
Australian dollars:
Variable interest rate term loan 50 -
Promissory notes payable with
7.6% average rate 19 81
Fixed interest rate loans with
11.2% rate due 2001-2002 230 132
Other - 38
New Zealand dollars:
Variable interest rate term loans 13 16
Other 15 9
-------- --------
$628 $715
======== ========
At December 31, 1995 and 1994, $19 million and $124 million, respectively,
of short-term borrowings were classified as long-term debt. Settlement of
these obligations is not expected to require the use of working capital in
1996, as the Group has both the intent and ability to refinance this debt on a
long-term basis. At December 31, 1995 and 1994, $19 million and $170 million,
respectively, of long-term committed credit facilities were available with
major banks to support notes payable classified as long-term debt.
Aggregate maturities of long-term debt for the next five years are as follows
(in millions): 1996 - $89 (included on the combined balance sheet as a current
liability and excluding short-term borrowings classified as long-term debt);
1997 - $56; 1998 - $70; 1999 - $95; 2000 - $97; 2001 and thereafter - $310.
C-14
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(7) 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
-------------- --------------- ---------------
1995 1994 1995 1994
------ ------ ------ ------
Actuarial present value of:
Vested benefit obligation $186 $224 $215 $194
Accumulated benefit obligation 208 248 251 229
Projected benefit obligation 362 408 308 308
Amount of assets available for benefits:
Funded assets at fair value $341 $385 $123 $109
Net pension (asset) liability recorded (23) (22) 146 149
------ ------ ------ ------
Total assets $318 $363 $269 $258
====== ====== ====== ======
Assets less than projected
benefit obligation $(44) $(45) $(39) $(50)
Consisting of:
Unrecognized transition net assets
(liabilities) 13 21 (5) (7)
Unrecognized net losses (38) (39) (30) (40)
Unrecognized prior service costs (19) (27) (4) (3)
Weighted average rate assumptions:
Discount rate 10.5% 10.5% 5.1% 6.3%
Rate of increase in compensation 8.2% 7.9% 3.1% 4.4%
Expected return on plan assets 10.1% 10.8% 4.5% 5.5%
Components of Pension Expense 1995 1994 1993
----------------------------- ------ ------ ------
Cost of benefits earned during the year $32 $27 $27
Interest cost on projected benefit obligation 55 55 58
Actual return on plan assets (47) (23) (59)
Net amortization and deferral 12 (16) 16
------ ------ ------
Total $52 $43 $42
====== ====== ======
C-15
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(8) OPERATING LEASES
The Group has various operating leases involving service stations, equipment
and other facilities for which net rental expense was $91 million, $121
million, and $110 million in 1995, 1994, and 1993, respectively.
Future net minimum rental commitments under operating leases having non-
cancelable terms in excess of one year are as follows (in millions): 1996 -
$35; 1997 - $37; 1998 - $38; 1999 - $40; 2000 - $41; 2001 and thereafter -
$73.
(9) COMMITMENTS AND CONTINGENCIES
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 in 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. Consequently, no
reasonable estimate of damages involved or being sought can be made. These
issues were resolved in the Group's favor by the Federal District Court in
March 1992, through a forum non conveniens dismissal. Subsequent to that
dismissal, but consistent with its terms, cases were filed against the Group
entities in the Philippine courts (over and above those previously filed there
subsequent to the collision, all of which are in various stages of litigation
and are being vigorously resisted). However, and notwithstanding the Houston
Federal District Court dismissal, the plaintiffs filed another lawsuit,
alleging the same causes of action as in the Texas litigation, in Louisiana
State Court in New Orleans. The Group removed that case to Federal District
Court in New Orleans from which it was remanded back to Louisiana State Court.
The Group then sought injunctive and other relief from the Federal District
Court in Houston in order to ensure that Court's previous dismissal would be
given proper effect. On having its request for relief denied, the Group then
filed an expedited appeal to the U.S. Fifth Circuit Court of Appeals. That
court, in January of 1996, affirmed the Federal District Court's refusal to
enjoin the plaintiffs' proceeding with their Louisiana lawsuit. The Group has
filed requests for rehearing with the Fifth Circuit three judge panel which
heard the case and, additionally, for en banc consideration of the case by the
entire Fifth Circuit. Management is contesting this case vigorously.
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.
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.
C-16
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(9) COMMITMENTS AND CONTINGENCIES - CONTINUED
While it is impossible to ascertain the ultimate legal and financial liability
with respect to the above mentioned and other contingent liabilities, the
aggregate amount that may arise from such liabilities is not anticipated to be
material in relation to the Group's combined financial position, results of
operations, or liquidity.
Unconditional purchase obligations in 1993 were not considered material.
However, in April 1994, a Group subsidiary entered into a contractual
commitment, effective October 1996, for a period of eleven years, to purchase
refined products in conjunction with the financing of a refinery that is
presently under construction by a nonsubsidiary company. Total future
estimated commitments (in billions) for the Group under this and other similar
contracts, based on current pricing and projected growth rates, are: 1996 -
$1.1, 1997 - $1.1, 1998 - $1.2, 1999 - $1.3, 2000 - $1.3, and 2001 to
expiration of contracts - $6.1. Purchases (in billions) under similar
contracts were $.5, $.5, and $.6 in 1995, 1994, and 1993, respectively.
(10) 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):
1995 1994
-------- --------
Interest rate swaps - Pay Fixed, Receive Floating $ 485 $ 363
Interest rate swaps - Pay Floating, Receive Fixed $ 230 $ 182
Commitments to purchase foreign currencies $ 439 $ 252
Commitments to sell foreign currencies $2,001 $ 274
The Group enters into interest rate swaps in managing its interest rate risk,
and their effects are recognized in the statement of income at the same time
as the interest expense on the debt to which they relate. The swap contracts
have remaining maturities up to ten years. Unrealized gains and losses on
contracts outstanding at year-end 1995 and 1994 were not material.
The Group enters into forward exchange contracts to hedge against some of its
foreign currency exposure stemming from existing liabilities and firm
commitments. Forward exchange contracts hedging existing liabilities have
maturities of up to seven years, and those contracts hedging firm commitments
have maturities of under a year. Contracts at December 31, 1995 primarily
reflect a hedge of the agreed proceeds of 200 billion Yen (approximately $2
billion) from the April 1, 1996 sale of the Group's interest in Nippon
Petroleum Refining Company, Limited, a nonsubsidiary. As of December 31,
1995, the estimated unrealized exchange gain on this hedge is $42 million.
Unrealized gains and losses applicable to the remaining forward exchange
contracts at December 31, 1995 and to the contracts at December 31, 1994 were
immaterial since the forward rates approximated year-end spot rates.
The Group's activity in commodity-based derivative contracts, that must be
settled in cash, is not material. Unrealized gains and losses on commodity-
based derivative contracts outstanding at year-end 1995 and 1994 were not
material.
C-17
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(10) FINANCIAL INSTRUMENTS - CONTINUED
The Group's long-term debt of $628 million and $715 million at December 31,
1995 and 1994, respectively, had fair values of $639 million and $707 million
at December 31, 1995 and 1994, 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.
The Group had investments in debt securities available-for-sale at amortized
costs of $65 million and $63 million at December 31, 1995 and 1994,
respectively, and investments in debt securities held to maturity at amortized
costs of $14 million and $77 million at December 31, 1995 and 1994,
respectively. The fair value of these securities at December 31, 1995 and
1994 approximates amortized costs. At December 31, 1995 and 1994, investments
in debt securities available-for-sale had maturities less than ten years and
investments in debt securities held to maturity had maturities less than one
year. At December 31, 1995 and 1994, the Group's carrying amount for
investments in nonsubsidiary companies accounted for at equity included $65
million and $83 million, respectively, for net-of-tax unrealized net gains on
investments held by these nonsubsidiaries.
The Group had commitments of $12 million and $99 million at December 31,
1995 and 1994, 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. In addition, the
Group is contingently liable at December 31, 1995, for a maximum of $192
million, for precompletion sponsor support of project finance obligations of a
nonsubsidiary. Considering the status of the construction at December 31,
1995, the need for precompletion sponsor support is unlikely. The Group will
become contingently liable for post-completion support of these project
finance obligations when the nonsubsidiary has met certain plant physical
completion requirements.
The Group is exposed to credit risks in the event of non-performance by
counterparties to financial instruments. For financial instruments with
institutions, the Group does not expect any counterparty to fail to meet their
obligations given their high credit ratings. Other financial instruments
exposed to credit risk consist primarily of trade receivables. These
receivables are dispersed among the countries in which the Group operates,
thus limiting 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.
(11) TAXES
Taxes charged to income consist of the following (in millions):
1995 1994 1993
------ ------ ------
Taxes other than income taxes:
Duties, import and excise taxes $1,660 $2,384 $1,978
Other 29 32 29
------ ------ ------
Total taxes other than income taxes 1,689 2,416 2,007
Provision for income taxes 467 422 458
------ ------ ------
$2,156 $2,838 $2,465
====== ====== ======
C-18
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(11) TAXES - CONTINUED
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:
1995 1994 1993
------ ------ ------
Computed "expected" tax expense 35.0% 35.0% 35.0%
Effect of recording equity in net income of
nonsubsidiary companies on an after tax basis (10.9) (8.3) (4.2)
Effect of dividends received from subsidiary
and nonsubsidiary companies 2.9 4.4 4.2
Foreign income subject to foreign taxes
in excess of U.S. statutory tax rate 8.3 6.9 7.4
Increase/(Decrease) in deferred tax asset
valuation allowance .6 .3 (3.1)
Other (1.7) (.3) (.4)
------ ------ ------
34.2% 38.0% 38.9%
====== ====== ======
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, 1995 and 1994 are as follows (in
millions):
Deferred Deferred
Tax Assets Tax Liabilities
--------------- ---------------
1995 1994 1995 1994
------ ------ ------ ------
Inventory $ 4 $ 17 $ 9 $ 12
Depreciation - - 306 310
Retirement plans 29 34 3 2
Tax loss carryforwards 24 27 - -
Investment allowances 62 40 - -
Other 43 30 44 41
------ ------ ------ ------
162 148 362 365
Valuation allowance (17) (9) - -
------ ------ ------ ------
Total deferred taxes $145 $139 $362 $365
====== ====== ====== ======
The Group classifies deferred taxes as net current or net non-current based
on the balance sheet classification of the related assets or liabilities.
Deferred taxes were classified on the combined balance sheet as current
liabilities, included in estimated income taxes, $8 million and non-current
liabilities $209 million at December 31, 1995 and as other current assets $10
million and non-current liabilities $236 million at December 31, 1994.
C-19
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(11) TAXES - CONTINUED
The valuation allowance has been established to record deferred tax assets
at amounts where recoverability is more likely than not. Net income was
decreased in 1995 and 1994 by $8 million and $3 million, respectively, and
increased by $36 million in 1993 for changes in the deferred tax asset
valuation allowance.
Undistributed earnings for which no deferred income tax provision has been
made approximated $4.1 billion at December 31, 1995 and $3.8 billion at
December 31, 1994. 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. Upon
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):
1995 1994 1993
------ ------ ------
Notes and accounts receivable $ 42 $(97) $ 82
Inventories (89) (37) 66
Accounts payable 15 152 (147)
Accrued liabilities 31 16 16
Estimated income taxes (26) 24 14
------ ------ ------
Total $(27) $ 58 $ 31
====== ====== ======
"Net Cash Provided by Operating Activities" includes the following cash
payments for interest and income taxes (in millions):
1995 1994 1993
------ ------ ------
Interest paid (net of capitalized interest) $144 $ 94 $ 92
Income taxes paid $466 $444 $391
During 1995, Caltex Australia Limited exchanged, in a non-cash investing
transaction, its petroleum refining and marketing net assets of $419 million
for an investment in Australian Petroleum Pty. Limited, a nonsubsidiary of the
Group. No significant non-cash investing or financing transactions occurred
in 1994 or 1993.
(13) 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-20